10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)

[ X ]	ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 2016
or
[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to

Commission File Number	Registrant, Address and Telephone Number	State of Incorporation	I.R.S. Employer Identification Number
1-16681	Spire Inc. 700 Market Street St. Louis, MO 63101 Telephone Number 314-342-0500	Missouri	74-2976504
1-1822	Laclede Gas Company 700 Market Street St. Louis, MO 63101 Telephone Number 314-342-0500	Missouri	43-0368139
2-38960	Alabama Gas Corporation 2101 6th Avenue North Birmingham, Alabama 35203 Telephone Number 205-326-8100	Alabama	63-0022000

Securities registered pursuant to Section 12(b) of the Act:

	Title of each class	Name of each exchange on which registered
Spire Inc.	Common Stock $1.00 par value	New York Stock Exchange
Laclede Gas Company	None	Not applicable
Alabama Gas Corporation	None	Not Applicable

Securities registered pursuant to Section 12(g) of the Act:

Spire Inc.            Yes [ ]No [ X ]

Laclede Gas CompanyYes [ ]No [ X ]

Alabama Gas CorporationYes [ ]No [ X ]

Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Spire Inc.Yes [ X ]No [ ]

Laclede Gas CompanyYes [ ]No [ X ]

Alabama Gas CorporationYes [ ]No [ X ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the act.

Spire Inc.Yes [ ]No [ X ]

Laclede Gas CompanyYes [ ]No [ X ]

Alabama Gas Corporation    Yes [ ]No [ X ]

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such report), and (2) has been subject to such filing requirements for the past 90 days.

Spire Inc.Yes [ X ]    No [ ]

Laclede Gas CompanyYes [ X ]        No [ ]

Alabama Gas Corporation    Yes [ X ]No [ ]

Indicate by check mark whether each registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Spire Inc.            Yes [ X ]        No [ ]    

Laclede Gas CompanyYes [ X ]    No [ ]

Alabama Gas Corporation        Yes [ X ]        No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Spire Inc.            [ X ]

Laclede Gas Company[ X ]

Alabama Gas Corporation[ X ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

	Large accelerated filer	Accelerated filer	Non- accelerated filer	Smaller reporting company
Spire Inc.	X
Laclede Gas Company			X
Alabama Gas Corporation			X

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Spire Inc.Yes [ ]No [ X ]

Laclede Gas CompanyYes [ ]No [ X ]

Alabama Gas CorporationYes [ ]No [ X ]

The aggregate market value of the voting stock held by non-affiliates of Spire Inc. amounted to $2,843,343,450 as of March 31, 2016. All of Laclede Gas Company’s and Alabama Gas Corporation’s equity securities are owned by Spire Inc., their parent company and a 1934 Act Reporting Company. Laclede Gas Company and Alabama Gas Corporation meet the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instructions I(2) to Form 10-K.

The number of shares outstanding of each registrant’s common stock as of November 11, 2016 was as follows:

Spire Inc.	Common Stock, par value $1.00 per share	45,656,218
Laclede Gas Company	Common Stock, par value $1.00 per share (all owned by Spire Inc.)	24,577
Alabama Gas Corporation	Common Stock, par value $0.01 per share (all owned by Spire Inc.)	1,972,052

DOCUMENTS INCORPORATED BY REFERENCE

Portions of proxy statement for Spire Inc. to be filed on or about December 15, 2016 — Part III.

Exhibit Index is found on page 142.

This combined Form 10-K represents separate filings by Spire Inc., Laclede Gas Company, and Alabama Gas Corporation. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrant, except that information relating to Laclede Gas Company and Alabama Gas Corporation is also attributed to Spire Inc.

TABLE OF CONTENTS		Page
GLOSSARY OF KEY TERMS AND ABBREVIATIONS		2
PART I
FORWARD-LOOKING STATEMENTS		3
Item 1	Business	4
Item 1A	Risk Factors	10
Item 1B	Unresolved Staff Comments	19
Item 2	Properties	19
Item 3	Legal Proceedings	20
Executive Officers of the Registrant (Item 401(b) of Regulation S-K)		21
PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6	Selected Financial Data	25
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	50
Item 8	Financial Statements and Supplementary Data	51
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	134
Item 9A	Controls and Procedures	134
Item 9B	Other Information	135
PART III
Item 10	Directors, Executive Officers and Corporate Governance	136
Item 11	Executive Compensation	136
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	136
Item 13	Certain Relationships and Related Transactions, and Director Independence	137
Item 14	Principal Accounting Fees and Services	137
PART IV
Item 15	Exhibits, Financial Statement Schedules	138
SIGNATURES		139
EXHIBIT INDEX		142

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GLOSSARY OF KEY TERMS AND ABBREVIATIONS

Alabama Utilities	Alagasco and Mobile Gas	MGP	Manufactured gas plant
Alagasco	Alabama Gas Corporation	Missouri Utilities	Laclede Gas Company (including MGE), the utilities serving the Missouri region
AOCI	Accumulated other comprehensive income or loss	MMBtu	Million British thermal units
APSC	Alabama Public Service Commission	Mobile Gas	Mobile Gas Service Corporation
ASC	Accounting Standards Codification	MoPSC	Missouri Public Service Commission
ASU	Accounting Standards Update	MSPSC	Mississippi Public Service Commission
Bcf	Billion cubic feet	MRT	Enable Mississippi River Transmission LLC
BVCP	Brownfields/Voluntary Cleanup Program	NYSE	New York Stock Exchange
CCM	Cost control mechanism	NYMEX	New York Mercantile Exchange, Inc.
Degree days	The average of a day’s high and low temperature below 65, subtracted from 65, multiplied by the number of days impacted	O&M	Operations and maintenance
EnergySouth	EnergySouth, Inc.	OCI	Other comprehensive income or loss
EPA	US Environmental Protection Agency	OPC	Missouri Office of the Public Counsel
EPS	Earnings per share	OTCBB	Over-the-counter bulletin board
ESR	Enhanced stability reserve	PEPL	Panhandle Eastern Pipe Line Company, LP
FASB	Financial Accounting Standards Board	PGA	Purchased gas adjustment
FERC	Federal Energy Regulatory Commission	PRP	Potential Responsible Party
GAAP	Accounting principles generally accepted in the United States of America	REX	Rockies Express Pipeline, LLC
Gas Marketing	Segment including LER, a subsidiary engaged in the non-regulated marketing of natural gas and related activities	RSA	Rate stabilization adjustment
Gas Utility	Segment including the regulated operations of the Utilities	RSE	Rate stabilization and equalization
GSA	Gas supply adjustment	SEC	US Securities and Exchange Commission
ICE	Intercontinental Exchange	Southern Natural Gas	Southern Natural Gas Company, LLC
ISRS	Infrastructure system replacement surcharge	Southern Star	Southern Star Central Gas Pipeline, Inc.
Laclede Gas	Laclede Gas Company, or Missouri Utilities	TGIT	Tallgrass Interstate Gas Transmission, LLC
LER	Laclede Energy Resources, Inc.	TSR	Total shareholder return
LIBOR	London Inter-Bank Offered Rate	Transco	Transcontinental Gas Pipe Line Company, LLC
LNG	Liquefied natural gas	US	United States
MDNR	Missouri Department of Natural Resources	Utilities	Laclede Gas Company, Alabama Gas Corporation and the subsidiaries of EnergySouth, Inc.
MGE	Missouri Gas Energy	Willmut Gas	Willmut Gas and Oil Company

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PART I

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this report, excluding historical information, include forward-looking statements. Certain words, such as “may,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “seek,” and similar words and expressions identify forward-looking statements that involve uncertainties and risks. Future developments may not be in accordance with our current expectations or beliefs and the effect of future developments may not be those anticipated. Among the factors that may cause results to differ materially from those contemplated in any forward-looking statement are:

• Weather conditions and catastrophic events, particularly severe weather in the natural gas producing areas of the country;

• Volatility in gas prices, particularly sudden and sustained changes in natural gas prices, including the related impact on margin deposits associated with the use of natural gas derivative instruments;

• The impact of changes and volatility in natural gas prices on our competitive position in relation to suppliers of alternative heating sources, such as electricity;

• Changes in gas supply and pipeline availability, including decisions by natural gas producers to reduce production or shut in producing natural gas wells, expiration of existing supply and transportation arrangements that are not replaced with contracts with similar terms and pricing, as well as other changes that impact supply for and access to the markets in which our subsidiaries transact business;

• The recent acquisitions may not achieve their intended results, including anticipated cost savings;

• Legislative, regulatory and judicial mandates and decisions, some of which may be retroactive, including those affecting

• allowed rates of return

• incentive regulation

• industry structure

• purchased gas adjustment provisions

• rate design structure and implementation

• regulatory assets

• non-regulated and affiliate transactions

• franchise renewals

• environmental or safety matters, including the potential impact of legislative and regulatory actions related to climate change and pipeline safety

• taxes

• pension and other postretirement benefit liabilities and funding obligations

• accounting standards;

• The results of litigation;

• The availability of and access to, in general, funds to meet our debt obligations prior to or when they become due and to fund our operations and necessary capital expenditures, either through (i) cash on hand, (ii) operating cash flow, or (iii) access to the capital or credit markets;

• Retention of, ability to attract, ability to collect from, and conservation efforts of, customers;

• Our ability to comply with all covenants in our indentures and credit facilities any violations of which, if not cured in a timely manner, could trigger a default of our obligation;

• Capital and energy commodity market conditions, including the ability to obtain funds with reasonable terms for necessary capital expenditures and general operations and the terms and conditions imposed for obtaining sufficient gas supply;

• Discovery of material weakness in internal controls; and

• Employee workforce issues, including but not limited to labor disputes and future wage and employee benefit costs, including changes in discount rates and returns on benefit plan assets.

Readers are urged to consider the risks, uncertainties, and other factors that could affect our business as described in this report. All forward-looking statements made in this report rely upon the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. We do not, by including this statement, assume any obligation to review or revise any particular forward-looking statement in light of future events.

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Item 1. Business

OVERVIEW

Spire Inc. (Spire or the Company) was formerly The Laclede Group, Inc., an entity formed in 2000 that, effective October 1, 2001, became the public utility holding company for Laclede Gas Company (Laclede Gas or the Missouri Utilities). Laclede Gas was founded in 1857 as The Laclede Gas Light Company and it was listed on the New York Stock Exchange (NYSE) in 1889, making the Company successor to the eighth longest listed stock on the NYSE. The Laclede Gas Light Company was renamed Laclede Gas Company in 1950.

Spire is committed to transforming its business and pursuing growth by 1) growing its gas utility business through prudent investment in infrastructure upgrades and organic growth initiatives, 2) acquiring and integrating gas utilities, 3) modernizing its gas assets, and 4) investing in innovation.

The Company has two key business segments: Gas Utility and Gas Marketing.

The Gas Utility segment includes the regulated operations of Laclede Gas, Alabama Gas Corporation (Alagasco), and EnergySouth, Inc. (EnergySouth) (collectively, the Utilities). The business of the Utilities is subject to seasonal fluctuations with the peak period occurring in the winter heating season, typically November through April of each fiscal year. Laclede Gas, a public utility engaged in the purchase, retail distribution and sale of natural gas, is the largest natural gas distribution utility system in Missouri, serving more than 1.1 million residential, commercial and industrial customers, and is headquartered in St. Louis, Missouri. Laclede Gas serves St. Louis and eastern Missouri and, through Missouri Gas Energy (MGE), Kansas City and western Missouri. Alagasco is a public utility engaged in the purchase, retail distribution and sale of natural gas principally in central and northern Alabama, serving more than 0.4 million residential, commercial and industrial customers with primary offices located in Birmingham, Alabama. The Company purchased 100% of the common shares of Alagasco from Energen Corporation (Energen) effective on August 31, 2014. Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas and Oil Company (Willmut Gas) are utilities engaged in the purchase, retail distribution and sale of natural gas to 0.1 million customers in southern Alabama and south central Mississippi. Mobile Gas and Willmut Gas are wholly owned subsidiaries of EnergySouth. The Company purchased 100% of the common shares of EnergySouth from Sempra U.S. Gas & Power, LLC, a subsidiary of Sempra Global (Sempra), on September 12, 2016.

The Gas Marketing segment includes Laclede Energy Resources, Inc. (LER), a wholly owned subsidiary engaged in the marketing of natural gas and related activities on a non-regulated basis.

As of September 30, 2016, Spire had 3,296 employees, Laclede Gas had 2,229 employees, and Alagasco had 825 employees.

Consolidated operating revenues contributed by each segment for the last three fiscal years are presented below. For more detailed financial information regarding the segments, see Note 14, Information by Operating Segment, of the Notes to Financial Statements in Item 8.

(In millions)	2016*		2015		2014**
Gas Utility	$	1,457.2	$	1,891.8	$	1,462.6
Gas Marketing and other	80.1		84.6		164.6
Total Operating Revenues	$	1,537.3	$	1,976.4	$	1,627.2

* 2016 Gas Utility operating results include EnergySouth revenues since the September 12, 2016 acquisition date.

** 2014 Gas Utility operating results include Alagasco revenues for the month of September only.

Spire’s common stock is listed on the NYSE and trades under the ticker symbol “SR.” The following table reflects Spire shares issued during the two most recent fiscal years:

	2016	2015
Common Stock Issuance	2,185,000	—
Dividend Reinvestment and Stock Purchase Plan (DRIP)	22,878	31,166
Equity Incentive Plan	107,752	125,441
Total Shares Issued	2,315,630	156,607

During fiscal 2016 and 2015, shares were issued at historically consistent levels for Spire’s DRIP and Equity Incentive Plan. Shares were issued during 2016 to effect the EnergySouth acquisition.

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During fiscal 2016 and 2015, neither Laclede Gas nor Alagasco issued shares to Spire. For more detailed common stock information of Spire, Laclede Gas and Alagasco, see Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities.

The information Spire, Laclede Gas and Alagasco file or furnish to the Securities and Exchange Commission (SEC), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and their amendments, and proxy statements are available free of charge under “Filings and Annual Reports” in the Investors section of Spire’s website, SpireEnergy.com, as soon as reasonably practical after the information is filed with or furnished to the SEC. Information contained on Spire’s website is not incorporated by reference in this report.

GAS UTILITY

Natural Gas Supply

The Utilities’ fundamental gas supply strategy is to meet the two-fold objective of 1) ensuring a dependable gas supply is available for delivery when needed and 2) insofar as is compatible with that dependability, purchasing gas that is economically priced. In structuring their natural gas supply portfolio, the Utilities focus on natural gas assets that are strategically positioned to meet the Utilities’ primary objectives.

Laclede Gas focuses its gas supply portfolio around a number of large natural gas suppliers with equity ownership or control of assets strategically situated to complement its regionally diverse firm transportation arrangements. In eastern Missouri, Laclede Gas utilizes both Mid-Continent and Gulf Coast gas sources to provide a level of supply diversity that facilitates the optimization of pricing differentials as well as protecting against the potential of regional supply disruptions. In western Missouri, both Mid-Continent and Rocky Mountain gas sources are utilized by MGE to provide a level of supply diversity that accesses low cost supplies.

In fiscal year 2016, Laclede Gas purchased natural gas from 35 different suppliers to meet its total service area current gas sales and storage injection requirements. Laclede Gas entered into firm agreements with suppliers including major producers and marketers providing flexibility to meet the temperature sensitive needs of its customers. Natural gas purchased by Laclede Gas for delivery to its service area through the Enable Mississippi River Transmission LLC (MRT) system totaled 47.3 billion cubic feet (Bcf). Laclede Gas also holds firm transportation on several other interstate pipeline systems that provide access to gas supplies upstream of MRT. In addition to natural gas deliveries from MRT, 48.2 Bcf was purchased on the Southern Star Central Gas Pipeline, Inc. (Southern Star), 4.7 Bcf was purchased on the Tallgrass Interstate Gas Transmission, LLC (TGIT) system, 10.4 Bcf was purchased on the Panhandle Eastern Pipe Line Company, LP (PEPL) system, and 0.6 Bcf was purchased on the Rockies Express Pipeline, LLC (REX) system. Some of Laclede Gas’ commercial and industrial customers purchased their own gas with Laclede Gas transporting 48.8 Bcf to them through its distribution system.

The fiscal year 2016 peak day send out of natural gas to Laclede Gas customers in both eastern and western Missouri, including transportation customers, occurred on January 17, 2016. The average temperature was 11 degrees Fahrenheit in St. Louis and 8 degrees Fahrenheit in Kansas City. On that day, the Missouri Utilities’ customers consumed 1.55 Bcf of natural gas. For eastern Missouri, about 77% of this peak day demand was met with natural gas transported to St. Louis through the MRT, MoGas Pipeline LLC, and Southern Star transportation systems, and the other 23% was met from Laclede Gas’ on-system storage and peak shaving resources. For western Missouri, this peak day demand was met with natural gas transported to Kansas City through the Southern Star, PEPL, TGIT, and REX transportation systems.

Alagasco’s distribution system is connected to two major interstate natural gas pipeline systems, Southern Natural Gas Company, L.L.C. (Southern Natural Gas) and Transcontinental Gas Pipe Line Company, LLC (Transco). It is also connected to two intrastate natural gas pipeline systems.

Alagasco purchases natural gas from various natural gas producers and marketers. Certain volumes are purchased under firm contractual commitments with other volumes purchased on a spot market basis. The purchased volumes are delivered to Alagasco’s system using a variety of firm transportation, interruptible transportation and storage capacity arrangements designed to meet the system’s varying levels of demand.

In fiscal year 2016, Alagasco purchased natural gas from 15 different suppliers to meet current gas sales, storage injection, and liquefied natural gas (LNG) liquefaction requirements, of which seven are under long-term supply agreements. Approximately 59.5 Bcf was transported by Southern Natural Gas, 4.3 Bcf by Transco, and 5.2 Bcf through intrastate pipelines to the Alagasco delivery points for its residential, commercial, and industrial customers.

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The fiscal year 2016 peak day send out for Alagasco was 0.5 Bcf on January 23, 2016, when the average temperature was 30 degrees Fahrenheit in Birmingham, of which 100% was met with supplies transported through Southern Natural Gas, Transco and intrastate facilities, while supplies from Alagasco’s four LNG peak shaving facilities were not required.

Mobile Gas’ distribution system is directly connected to interstate pipelines, natural gas processing plants and gas storage facilities. Mobile Gas buys from a variety of producers and marketers, with BP Energy Company being the primary supplier.

Natural Gas Storage

For its eastern service area, Laclede Gas has a contractual right to store 21.6 Bcf of gas in MRT’s storage facility located in Unionville, Louisiana, and for its western service area 16.3 Bcf of gas storage in Southern Star’s system storage facilities located in Kansas and Oklahoma, as well as 1.4 Bcf of firm storage on PEPL’s system storage. MRT’s tariffs allow injections into storage from May 16 through November 15 and require the withdrawal from storage of all but 2.1 Bcf from November 16 through May 15. Southern Star tariffs allow both injections and withdrawals into storage year round with ratchets that restrict the associated flows dependent upon the underlying inventory level per the contracts.

In addition, in eastern Missouri, Laclede Gas supplements pipeline gas with natural gas withdrawn from its own underground storage field located in St. Louis and St. Charles Counties in Missouri. The field is designed to provide approximately 0.3 Bcf of natural gas withdrawals on a peak day and maximum annual net withdrawals of approximately 4.0 Bcf of natural gas based on the inventory level that Laclede Gas plans to maintain.

Alagasco has a contractual right to store 12.5 Bcf of gas with Southern Natural Gas, 0.2 Bcf of gas with Transco and 0.2 Bcf of gas with Tennessee Gas Pipeline. In addition, Alagasco has 1.8 Bcf of LNG storage that can provide the system with up to an additional 0.2 Bcf of natural gas daily to meet peak day demand.

Gulf South Pipeline Company, LP, at multiple interconnections, provides No-Notice Service which includes 240,000 Dth of storage capacity to Mobile Gas. Through a direct connection with Sempra’s Bay Gas Storage, Mobile Gas has 800,000 Dth of maximum storage and 80,000 Dth of maximum daily withdrawal.

Regulatory Matters

For details on regulatory matters, see Note 15, Regulatory Matters, of the Notes to Financial Statements in Item 8.

Other Pertinent Matters

Laclede Gas is the only distributor of natural gas within its franchised service areas, while Alagasco is the main distributor of natural gas in its service areas. The principal competition for the Utilities comes from the local electric companies. Other competitors in the service areas include suppliers of fuel oil, coal, propane, natural gas pipelines that can directly connect to large volume customers, for the Missouri Utilities, district steam systems in the downtown areas of both St. Louis and Kansas City, and for Alagasco, from municipally or publicly owned gas distributors located adjacent to its service territory. Coal is price competitive as a fuel source for very large boiler plant loads, but environmental requirements for coal have shifted the economic advantage to natural gas. Oil and propane can be used to fuel boiler loads and certain direct-fired process applications, but these fuels require on-site storage, thus limiting their competitiveness. In certain cases, district steam has been competitive with gas for downtown St. Louis and Kansas City area heating users.

Laclede Gas’ residential, commercial, and small industrial markets represented approximately 91% of its operating revenue for fiscal 2016. Alagasco’s residential, commercial, and small industrial markets represented approximately 78% of its operating revenue for the twelve months ended September 30, 2016. Given the current level of natural gas supply and market conditions, the Utilities believe that the relative comparison of natural gas equipment and operating costs with those of competitive fuels will not change significantly in the foreseeable future, and that these markets will continue to be supplied by natural gas. In new multi-family and commercial rental markets, the Utilities’ competitive exposures are presently limited to space and water heating applications. Certain alternative heating systems can be cost competitive in traditional markets.

Laclede Gas offers gas transportation service to its large-user industrial and commercial customers. The tariff approved for that type of service produces a margin similar to that which the Missouri Utilities would have received under their regular sales rates. Alagasco’s transportation tariff allows it to transport gas for large commercial and industrial customers rather than buying and reselling it to them and is based on Alagasco’s sales profit margin so

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that operating margins are unaffected. During fiscal 2016, substantially all of Alagasco’s large commercial and industrial customer deliveries involved the transportation of customer-owned gas.

The Utilities are subject to various environmental laws and regulations that, to date, have not materially affected the Utilities’ or the Company’s financial position and results of operations. For a detailed discussion of environmental matters, see Note 16, Commitment and Contingencies, of the Notes to Financial Statements in Item 8.

Union Agreements

As of September 30, 2016, the Company had approximately 1,975 employees represented by organized labor unions. The Company believes labor relations with its employees are good. Should that condition change, the Company could experience labor disputes, work stoppages or other disruptions in production that could negatively impact the Company’s results of operations and cash flows.

The following table presents the Company’s various labor agreements as of September 30, 2016:

Union	Local	Employees Covered	Contract Start Date	Contract End Date
Laclede Gas
United Steel, Paper and Forestry, Rubber Manufacturing, Allied-Industrial and Service Workers International Union (USW)	884	60	August 1, 2015	July 31, 2018
USW	11-6	924	August 1, 2015	July 31, 2018
USW	11-194	96	August 1, 2015	July 31, 2018
USW	12561	134	August 16, 2016	July 31, 2019
USW	14228	40	August 16, 2016	July 31, 2019
USW	11-267	27	August 16, 2016	July 31, 2019
Gas Workers Metal Trades locals of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada	781-Kansas City	191	August 16, 2016	July 31, 2019
Gas Workers Metal Trades locals of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada	781-Monett	46	August 16, 2016	July 31, 2019
International Brotherhood of Electrical Workers (IBEW)	53	3	April 30, 2014	July 31, 2016
Total Laclede Gas Company		1,521
Alagasco
USW	12030	210	December 14, 2014	April 30, 2017
USW	12030-A	57	May 1, 2014	April 30, 2017
United Association of Gas Fitters	548	114	July 1, 2016	April 30, 2019
Total Alabama Gas Corporation		381
Mobile Gas
USW	3-541	73	December 1, 2013	November 30, 2017
Total Spire		1,975

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Operating Revenues and Customer Information

The following information about revenues and therms sold and transported (before intersegment eliminations), and annual average numbers of customers, includes data of acquired utilities for only the period of ownership (beginning August 31, 2014 for Alagasco and September 12, 2016 for the utilities of EnergySouth).

Gas Utility Operating Revenues
(In millions)	2016		2015			2014
Residential	$	979.0	$	1,263.1		$	974.3
Commercial & Industrial	331.3		462.3			357.1
Interruptible	2.0		2.3			2.1
Transportation	93.1		92.2			32.4
Off-System and Other Incentive	50.7		76.2			79.5
Provisions for Refunds and Other	3.3		(0.3		)	22.4
Total Gas Utility Operating Revenues	$	1,459.4	$	1,895.8		$	1,467.8
Gas Utility Therms Sold and Transported
(In millions)	2016		2015			2014
Residential	867.5		1,065.1			952.9
Commercial & Industrial	420.4		491.6			435.6
Interruptible	4.6		3.6			3.5
Transportation	1,089.8		989.0			484.6
System Therms Sold and Transported	2,382.3		2,549.3			1,876.6
Off-System	183.3		193.5			125.8
Total Gas Utility Therms Sold and Transported	2,565.6		2,742.8			2,002.4
Gas Utility Customers	2016		2015			2014
Residential	1,540,366		1,434,584			1,418,422
Commercial & Industrial	137,450		132,388			133,799
Interruptible	42		18			18
Transportation	824		796			795
Total Gas Utility Customers	1,678,682		1,567,786			1,553,034

Total annual average number of customers for Laclede Gas and Alagasco for fiscal 2016 was 1,155,048 and 420,497, respectively.

Laclede Gas has franchises in nearly all the communities where it provides service with terms varying from five years to an indefinite duration. Generally, a franchise allows Laclede Gas, among other things, to install pipes and construct other facilities in the community. All of the franchises are free from unduly burdensome restrictions and are adequate for the conduct of Laclede Gas’ current public utility businesses in the state of Missouri. In recent years, although certain franchise agreements have expired, including Clayton, North Kansas City, Cameron, and Riverside, Laclede Gas has continued to provide service in those communities without formal franchises.

Alagasco has franchises in nearly all the communities where it provides service with terms varying from five years to an indefinite duration. Generally, a franchise allows Alagasco, among other things, to install pipes and construct other facilities in the community. All of the franchises are free from unduly burdensome restrictions and are adequate for the conduct of Alagasco’s current public utility business in the state of Alabama.

GAS MARKETING

LER is engaged in the marketing of natural gas and providing energy services to both on-system utility transportation customers and customers outside of the Utilities’ traditional service areas. During fiscal year 2016, Gas Marketing utilized 30 interstate and intrastate pipelines and over 125 suppliers to market natural gas to more than 200 retail customers and 120 wholesale customers, primarily in the central US. Through its retail operations, LER offers natural gas marketing services to large commercial and industrial customers, while its wholesale business consists of producers, pipelines, power generators, municipalities, storage operators, and utility companies. Wholesale activities currently represent a majority of the total Gas Marketing business.

In the course of its business, LER enters into agreements to purchase natural gas at a future date in order to lock up supply to cover future sales commitments to its customers. To secure access to the markets it serves, LER contracts

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for transportation capacity on various pipelines from both pipeline companies and through the secondary capacity market from third parties. Throughout fiscal year 2016, this business held approximately 0.4 Bcf per day of firm transportation capacity. In addition, to ensure reliability of service and to provide operational flexibility, LER enters into firm storage contracts and interruptible park and loan transactions with various companies, where it is able to buy and retain gas to be delivered at a future date, at which time it sells the natural gas to third parties. As of September 30, 2016, Gas Marketing has contracted for approximately 5.4 Bcf of such storage and park and loan capacity for the 2016-2017 winter period.

The Gas Marketing strategy is to leverage its market expertise and risk management skills to manage and optimize the value of its portfolio of commodity, transportation, park and loan, and storage contracts while controlling costs and acting on new marketplace opportunities. Overall, Gas Marketing saw significant growth in volumes in 2016 primarily due to increased business with producers and power generators and was also able to take advantage of the flexibility that its overall portfolio of assets provided.

OTHER

The principal drivers of the Other results for fiscal 2016 and fiscal 2015 has been interest expense related to the 2014 debt issue to finance the Alagasco acquisition and other expenses attributable to acquisition transactions and integration.

Other also includes Laclede Pipeline Company, a wholly owned subsidiary of Spire, which operates a propane pipeline under Federal Energy Regulatory Commission (FERC) jurisdiction. This pipeline allows Laclede Gas to receive propane that may be used to supplement its natural gas supply and meet peak demands on its distribution system. Laclede Pipeline Company also provides propane transportation services to third parties.

Further, Other includes Spire STL Pipeline LLC, a wholly owned subsidiary of Spire that is planning construction of a 70-mile pipeline to connect to the Rockies Express Pipeline in Scott County, Illinois and end in St. Louis County, Missouri. The proposed pipeline, which will operate under FERC jurisdiction, will be capable of delivering up to 400,000 dekatherms per day of natural gas into eastern Missouri, and Laclede Gas is anticipated to be the foundational shipper.

Additionally, this category includes Spire’s subsidiaries that are engaged in compression of natural gas and risk management, among other activities.

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Item 1A. Risk Factors

Spire’s and the Utilities’ business and financial results are subject to a number of risks and uncertainties, including those set forth below. The risks described below are those the Company and the Utilities consider to be material. When considering any investment in Spire or the Utilities’ securities, investors should carefully consider the following information, as well as information contained in the caption “Forward-Looking Statements,” Item 7A, and other documents Spire, Laclede Gas, and Alagasco file with the SEC. This list is not exhaustive, and Spire’s and the Utilities’ respective management places no priority or likelihood based on the risk descriptions, order of presentation or grouping by subsidiary. All references to dollar amounts are in millions.

RISKS AND UNCERTAINTIES THAT RELATE TO THE BUSINESS AND FINANCIAL RESULTS OF SPIRE AND ITS SUBSIDIARIES

As a holding company, Spire depends on its operating subsidiaries to meet its financial obligations.

Spire is a holding company with no significant assets other than the stock of its operating subsidiaries and cash investments. Spire, and Laclede Gas prior to the holding company’s formation in 2000, have paid dividends continuously since 1946. Spire’s ability to pay dividends to its shareholders is dependent on the ability of its subsidiaries to generate sufficient net income and cash flows to pay upstream dividends and make loans or loan repayments. In addition, because it is a holding company and the substantial portion of its assets are represented by its holdings in the Utilities, the risks faced by the Utilities as described under RISKS THAT RELATE TO THE GAS UTILITY SEGMENT below may also adversely affect Spire’s cash flows, liquidity, financial condition and results of operations.

A downgrade in Spire’s and/or its subsidiaries’ credit ratings may negatively affect its ability to access capital.

Currently, Spire and its utility subsidiaries have investment grade credit ratings, which are subject to review and change by the rating agencies. Spire, Laclede Gas and Alagasco each has a working capital line of credit to meet its short-term liquidity needs. Spire’s line of credit may also be used to meet the liquidity needs of any of its subsidiaries. If the rating agencies lowered the credit rating at any of these entities, particularly below investment grade, it might significantly limit such entity’s ability to secure new or additional credit facilities and would increase its costs of borrowing. Spire’s or the Utilities’ ability to borrow under current or new credit facilities and costs of that borrowing have a direct impact on their ability to execute their operating strategies. In the fourth quarter of 2014, Spire issued its first public debt and received its first senior unsecured debt ratings. Standard & Poor’s rated Spire debt BBB+, one notch lower than its issuer rating of A-, while Fitch also rated the Spire debt at BBB+, equal to its issuer rating, and Moody’s (which does not use issuer ratings) rated the Spire debt at Baa2. These rating levels have no specific implications for Spire’s corporate funding ability or our ability to access the capital markets, nor do they trigger any collateralization requirements under Spire’s corporate guarantees. There is no assurance that such credit ratings for any of the Spire companies will remain in effect for any given period of time or that such ratings will not be lowered, suspended or withdrawn entirely by the rating agencies, if, in each rating agency’s judgment, circumstances so warrant.

Unexpected losses may adversely affect Spire’s or its subsidiaries’ financial condition and results of operations.

As with most businesses, there are operations and business risks inherent in the activities of Spire’s subsidiaries. If, in the normal course of business, Spire or any of its subsidiaries becomes a party to litigation, such litigation could result in substantial monetary judgments, fines, or penalties or be resolved on unfavorable terms. In accordance with customary practice, Spire and its subsidiaries maintain insurance against a significant portion of, but not all, risks and losses. In addition, in the normal course of its operations, Spire and its subsidiaries may be exposed to loss from other sources, such as bad debt expense or the failure of a counterparty to meet its financial obligations. Spire and its operating companies employ many strategies to gain assurance that such risks are appropriately managed, mitigated, or insured, as appropriate. To the extent a loss is not fully covered by insurance or other risk mitigation strategies, that loss could adversely affect the Company’s and/or its subsidiaries’ financial condition and results of operations.

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Increased inter-dependence on technology may hinder Spire’s and its subsidiaries’ business operations and adversely affect their financial condition and results of operations if such technologies fail or are compromised.

Over the last several years, Spire and its subsidiaries have implemented or acquired a variety of technological tools including both Company-owned information technology and technological services provided by outside parties. These tools and systems support critical functions including Spire and its subsidiaries’ integrated planning, scheduling and dispatching of field resources, its automated meter reading system, customer care and billing, procurement and accounts payable, operational plant logistics, management reporting, and external financial reporting. The failure of these or other similarly important technologies, or the Company’s or its subsidiaries’ inability to have these technologies supported, updated, expanded, or integrated into other technologies, could hinder their business operations and adversely impact their financial condition and results of operations.

Although the Company and its subsidiaries have, when possible, developed alternative sources of technology and built redundancy into their computer networks and tools, there can be no assurance that these efforts to date would protect against all potential issues related to the loss of any such technologies or the Utilities’ use of such technologies.

Furthermore, the Company and its subsidiaries are subject to cyber-security risks primarily related to breaches of security pertaining to sensitive customer, employee, and vendor information maintained by the Company and its subsidiaries in the normal course of business, as well as breaches in the technology that manages natural gas distribution operations and other business processes. A loss of confidential or proprietary data or security breaches of other technology business tools could adversely affect the Company’s and its subsidiaries’ reputation, diminish customer confidence, disrupt operations, and subject the Company and its subsidiaries to possible financial liability, any of which could have a material effect on the Company’s and its subsidiaries’ financial condition and results of operations. The Company and its subsidiaries closely monitor both preventive and detective measures to manage these risks and maintain cyber risk insurance to mitigate a significant portion, but not all, of these risks and losses. To the extent that the occurrence of any of these cyber events is not fully covered by insurance, it could adversely affect the Company’s and its subsidiaries’ financial condition and results of operations.

Resources expended to pursue business acquisitions, investments or other business arrangements may adversely affect Spire’s financial position and results of operations and return on investments made may not meet expectations.

From time to time, Spire may seek to grow through strategic acquisitions, investments or other business arrangements, including the recent acquisitions, the development of the Spire STL Pipeline, or other future opportunities. Attractive acquisition and investment opportunities may be difficult to complete on economically acceptable terms. It is possible for Spire to expend considerable resources pursuing acquisitions and investments but, for a variety of reasons, decide not to move forward. Similarly, investment opportunities may be hindered or halted by regulatory or legal actions. To the extent that acquisitions or investments are made, such transactions involve a number of risks, including but not limited to, the assumption of material liabilities, the diversion of management’s attention from daily operations, difficulties in assimilation and retention of employees, securing adequate capital to support the transaction, and regulatory approval. Uncertainties exist in assessing the value, risks, profitability, and liabilities associated with certain businesses or assets and there is a possibility that anticipated operating and financial efficiencies expected to result from an acquisition or investment do not develop. The failure to complete an acquisition successfully or to integrate future acquisitions or investments that it may undertake could have an adverse effect on the Company’s financial condition and results of operations and the market’s perception of the Company’s execution of its strategy.

In order to manage and diversify the risks of certain development projects, Spire may use partnerships or other investments. Such business arrangements may limit Spire’s ability to fully direct the management and policies of the business relationship. These arrangements may cause additional risks such as operating agreements limiting Spire’s control or Spire’s ability to appropriately value the business drivers or assets of the business arrangement.

In addition, to the extent Spire engages in any of the above activities together with or through one or more of its subsidiaries, including the Utilities, such subsidiaries may face the same risks.

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Workforce risks may affect the Company’s financial results.

The Company and its subsidiaries are subject to various workforce risks, including, but not limited to, the risk that it will be unable to attract and retain qualified personnel; that it will be unable to effectively transfer the knowledge and expertise of an aging workforce to new personnel as those workers retire; and that it will be unable to reach collective bargaining arrangements with the unions that represent certain of its workers, which could result in work stoppages.

Acquisition activity subjects the Company and its subsidiaries to risks related to the level of indebtedness.

In connection with past acquisitions, Spire and Laclede Gas incurred additional debt to pay a portion of the acquisition cost and transaction expenses. On September 9, 2016 Spire issued unsecured debt in the aggregate principal amount of $165.0 to finance a portion of the EnergySouth acquisition. On August 19, 2014, Spire issued unsecured debt in the aggregate principal amount of $625.0 to finance a portion of the acquisition of Alagasco. On August 13, 2013, Laclede Gas issued secured debt in the aggregate principal amount of $450.0 to finance a portion of the acquisition of MGE. Spire’s total consolidated indebtedness as of September 30, 2016 was $2,482.4 ($398.7 of short-term borrowings and $2,083.7 of long-term debt, including current portion) and Laclede Gas’ total indebtedness as of September 30, 2016 was $1,052.0 ($243.7 of short-term borrowings, including borrowings from affiliates, and $808.3 of long-term debt).

Spire’s and Laclede Gas’ debt service obligations with respect to this increased indebtedness could have an adverse impact on their earnings and cash flows (which after the acquisitions include the earnings and cash flows of the acquired businesses) for as long as the indebtedness is outstanding. Among other risks, the increase in indebtedness may:

• make it more difficult for Spire or Laclede Gas to pay or refinance their debts as they become due during adverse economic and industry conditions;

• limit Spire’s or Laclede Gas’ flexibility to pursue other strategic opportunities or react to changes in its business and the industry in which they operate and, consequently, place them at a competitive disadvantage to competitors with less debt;

• require an increased portion of Spire’s or Laclede Gas’ cash flows from operations of their respective subsidiaries to be used for debt service payments, thereby reducing the availability of their cash flows to fund working capital, capital expenditures, dividend payments and other general corporate activities;

• result in a downgrade in the credit rating of Spire’s or the Utilities’ indebtedness, which could limit the Utilities’ ability to borrow additional funds or increase the interest rates applicable to Utilities’ indebtedness;

• result in higher interest expense in the event of an increase in market interest rates for both long-term floating rate debt and short-term commercial paper or bank loans;

• reduce the amount of credit available to support hedging activities; and

• require that additional terms, conditions or covenants be placed on Spire or Laclede Gas.

Based upon current levels of operations, Spire and Laclede Gas expect to be able to generate sufficient cash through earnings on a consolidated basis or through refinancing to make all of the principal and interest payments when such payments are due under their existing credit agreements, indentures and other instruments governing outstanding indebtedness; but there can be no assurance that Spire or Laclede Gas will be able to repay or refinance such borrowings and obligations in future periods.

In addition, in order to maintain investment-grade credit ratings, Spire and Laclede Gas may consider it appropriate to reduce the amount of indebtedness outstanding following acquisitions. This may be accomplished in several ways, including, in the case of Spire, issuing additional shares of common stock or securities convertible into shares of common stock, or in the case of Spire or Laclede Gas, reducing discretionary uses of cash or a combination of these and other measures. Issuances of additional shares of common stock or securities convertible into shares of common stock would have the effect of diluting the ownership percentage that shareholders hold in the Company, increasing the Company’s dividend payment obligations and perhaps reducing the reported earnings per share.

Recent acquisitions may not achieve their intended results, including anticipated efficiencies and cost savings.

Although the Company and its subsidiaries expect that the recent acquisitions will result in various benefits, including a significant cost savings and other financial and operational benefits, there can be no assurance regarding when or the extent to which the Company and its subsidiaries will be able to realize or retain these

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benefits. Achieving and retaining the anticipated benefits, including cost savings, is subject to a number of uncertainties, including whether the assets acquired can be operated in the manner the Company and its subsidiaries intended. Events outside of the control of the Company and its subsidiaries, including but not limited to regulatory changes or developments, could also adversely affect their ability to realize the anticipated benefits from the acquisitions.

Thus, the integration of acquired businesses may be unpredictable, subject to delays or changed circumstances, and the Company and its subsidiaries can give no assurance that the acquisitions will perform in accordance with their expectations or that their expectations with respect to integration or cost savings as a result of the acquisitions will materialize. In addition, the anticipated costs to the Company and its subsidiaries to achieve the integration of the acquired businesses may differ significantly from current estimates. The integration may place an additional burden on management and internal resources, and the diversion of management’s attention during the integration process could have an adverse effect on the Company’s and its subsidiaries’ business, financial condition and expected operating results.

In connection with acquisitions, Laclede Gas and Spire, respectively, recorded goodwill and long-lived assets that could become impaired and adversely affect its financial condition and results of operations.

Spire and Laclede Gas will assess goodwill for impairment annually or more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The Company and Laclede Gas will assess their long-lived assets for impairment whenever events or circumstances indicate that an asset’s carrying amount may not be recoverable. To the extent the value of goodwill or long-lived assets becomes impaired, the Company and Laclede Gas may be required to incur impairment charges that could have a material impact on their results of operations.

Since interest rates are a key component, among other assumptions, in the models used to estimate the fair values of the Company’s reporting units, as interest rates rise, the calculated fair values decrease and future impairments may occur. Due to the subjectivity of the assumptions and estimates underlying the impairment analysis, Spire and Laclede Gas cannot provide assurance that future analyses will not result in impairment. These assumptions and estimates include projected cash flows, current and future rates for contracted capacity, growth rates, weighted average cost of capital and market multiples. For additional information, see Item 7, Critical Accounting Estimates.

Changes in accounting standards may adversely impact the Utilities’ financial condition and results of operations.

Spire and its subsidiaries are subject to changes in US Generally Accepted Accounting Principles (GAAP), SEC regulations and other interpretations of financial reporting requirements for public utilities.  Neither the Company nor any of its subsidiaries have any control over the impact these changes may have on their financial condition or results of operations nor the timing of such changes. The potential issues associated with rate-regulated accounting, along with other potential changes to GAAP that the US Financial Accounting Standards Board (FASB) continues to consider may be significant.

Climate change and regulatory and legislative developments in the energy industry related to climate change may in the future adversely affect operations and financial results. 

Climate change, and the extent regulatory or legislative changes occur to address the potential for climate change, could adversely affect operations and financial results of the Company. Management believes it is likely that any such resulting impacts would occur very gradually over a long period of time and thus would be difficult to quantify with any degree of specificity. To the extent climate change results in warmer temperatures, financial results could be adversely affected through lower gas volumes and revenues and lack of marketing opportunities. Another possible impact of climate change may be more frequent and more severe weather events, such as hurricanes and tornadoes, which could increase costs to repair damaged facilities and restore service to customers. If the Company were unable to deliver natural gas to customers, financial results would be impacted by lost revenues, and the Utilities generally would have to seek approval from regulators to recover restoration costs. To the extent the Utilities would be unable to recover those costs, or if higher rates resulting from recovery of such costs would result in reduced demand for the Company’s services, the Company’s and the Utilities’ future business, financial condition or financial results could be adversely impacted. In addition, there have been a number of federal and state legislative and regulatory initiatives proposed in recent years in an attempt to control or limit the effects of global warming and overall climate change, including greenhouse gas emissions, such as carbon dioxide. The adoption of this type of legislation by Congress or similar legislation by states or the adoption of related regulations by federal or

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state governments mandating a substantial reduction in greenhouse gas emissions in the future could have far-reaching and significant impacts on the energy industry. Such new legislation or regulations could result in increased compliance costs or additional operating restrictions, affect the demand for natural gas or impact the prices charged to customers. At this time, we cannot predict the potential impact of such laws or regulations that may be adopted on the Company’s and the Utilities’ future business, financial condition or financial results.

RISKS THAT RELATE TO THE GAS UTILITY SEGMENT

Regulation of the Utilities’ businesses may impact rates they are able to charge, costs, and profitability.

The Utilities are subject to regulation by federal, state and local authorities. At the state level, the Utilities are regulated in Missouri by the Missouri Public Service Commission (MoPSC), in Alabama by the Alabama Public Service Commission (APSC), and in Mississippi by the Mississippi Public Service Commission (MSPSC). These state public service commissions regulate many aspects of the Utilities’ distribution operations, including construction and maintenance of facilities, operations, safety, the rates that the Utilities may charge customers, the terms of service to their customers, transactions with their affiliates, and the rate of return that they are allowed to realize; as well as the accounting treatment for certain aspects of their operations. For further discussion of these accounting matters, see Item 7, Critical Accounting Estimates pertaining to the Utilities’ operations.

The Utilities’ ability to obtain and timely implement rate increases and rate supplements to maintain the current rate of return is subject to regulatory review and approval. There can be no assurance that they will be able to obtain rate increases or rate supplements or continue earning the current authorized rates of return. The first Missouri Utilities general rate case filed after October 1, 2015 must be for both the legacy Laclede Gas and the MGE operations. Alagasco’s and Mobile Gas’ rate setting process, Rate Stabilization and Equalization (RSE), is subject to regulation by the APSC and is implemented pursuant to an APSC order that will continue beyond September 30, 2018 and September 30, 2017, respectively, unless the APSC enters an order to the contrary in a manner consistent with the law. Willmut Gas is subject to regulation by the MSPSC and utilizes the Rider Rate Stabilization Adjustment (RSA). For further details, see Regulatory and Other Matters in Item 7.

The Utilities could incur additional costs if required to adjust to new laws or regulations, revisions to existing laws or regulations or changes in interpretations of existing laws or regulations such as the Dodd-Frank Act. In addition, as the regulatory environment for the natural gas industry increases in complexity, the risk of inadvertent noncompliance could also increase. If the Utilities fail to comply with applicable laws and regulations, whether existing or new, they could be subject to fines, penalties or other enforcement action by the authorities that regulate the Utilities’ operations.

The Utilities are involved in legal or administrative proceedings before various courts and governmental bodies that could adversely affect their results of operations, cash flows and financial condition.

The Utilities are involved in legal or administrative proceedings before various courts and governmental bodies with respect to general claims, rates, environmental issues, gas cost prudence reviews and other matters. Adverse decisions regarding these matters, to the extent they require the Utilities to make payments in excess of amounts provided for in their financial statements, or to the extent they are not covered by insurance, could adversely affect the Utilities’ results of operations, cash flows and financial condition.

The Utilities’ liquidity may be adversely affected by delays in recovery of their costs, due to regulation.

In the normal course of business, there is a lag between when the Utilities incur increases in certain of their costs and the time in which those costs are considered for recovery in the ratemaking process. Cash requirements for increased operating costs, increased funding levels of defined benefit pension and postretirement costs, capital expenditures, and other increases in the costs of doing business can require outlays of cash prior to the authorization of increases in rates charged to customers, as approved by the MoPSC, APSC, and MSPSC. Accordingly, the Utilities’ liquidity can be adversely impacted to the extent higher costs are not timely recovered from their customers.

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The Utilities’ ability to meet their customers’ natural gas requirements may be impaired if contracted gas supplies, interstate pipeline and/or storage services are not available or delivered in a timely manner.

In order to meet their customers’ annual and seasonal natural gas demands, the Utilities must obtain sufficient supplies, interstate pipeline capacity, and storage capacity. If they are unable to obtain these, either from their suppliers’ inability to deliver the contracted commodity or the inability to secure replacement quantities, the Utilities’ financial condition and results of operations may be adversely impacted. If a substantial disruption in interstate natural gas pipelines’ transmission and storage capacity were to occur during periods of heavy demand, the Utilities’ financial results could be adversely impacted.

The Utilities’ liquidity and, in certain circumstances, the Utilities’ results of operations may be adversely affected by the cost of purchasing natural gas during periods in which natural gas prices are rising significantly.

The tariff rate schedules of the Missouri Utilities, Mobile Gas and Willmut Gas contain Purchased Gas Adjustment (PGA) clauses and Alagasco’s tariff rate schedule contains a Gas Supply Adjustment (GSA) rider that permit the Utilities to file for rate adjustments to recover the cost of purchased gas. Changes in the cost of purchased gas are flowed through to customers and may affect uncollectible amounts and cash flows and can therefore impact the amount of capital resources.

Currently, the Missouri Utilities are allowed to adjust the gas cost component of rates up to four times each year while the Alabama Utilities and Willmut Gas may adjust the gas cost component of their rates on a monthly basis. The Missouri Utilities must make a mandatory gas cost adjustment at the beginning of the winter, in November, and during the next twelve months may make up to three additional discretionary gas cost adjustments, so long as each of these adjustments is separated by at least two months.

The MoPSC typically approves the Missouri Utilities’ PGA changes on an interim basis, subject to refund and the outcome of a subsequent audit and prudence review. Due to such review process, there is a risk of a disallowance of full recovery of these costs. Any material disallowance of purchased gas costs would adversely affect revenues. The Alabama Utilities’ gas supply charges are submitted for APSC review on a monthly basis, regardless of whether there is a request for a change, so prudence review occurs on an ongoing basis. Willmut Gas’ PGA is adjusted on a monthly basis for the most recent charges, and is filed at the MSPSC on a monthly basis.

Increases in the prices the Utilities charge for gas may also adversely affect revenues because they could lead customers to reduce usage and cause some customers to have trouble paying the resulting higher bills. These higher prices may increase bad debt expenses and ultimately reduce earnings. Rapid increases in the price of purchased gas may result in an increase in short-term debt.

To lower financial exposure to commodity price fluctuations, Laclede Gas enters into contracts to hedge the forward commodity price of its natural gas supplies. As part of this strategy, Laclede Gas may use fixed-price, forward, physical purchase contracts, swaps, futures, and option contracts. However, Laclede Gas does not hedge the entire exposure of energy assets or positions to market price volatility, and the coverage will vary over time. Any costs, gains, or losses experienced through hedging procedures, including carrying costs, generally flow through the PGA clause, thereby limiting the Missouri Utilities’ exposure to earnings volatility. However, variations in the timing of collections of such gas costs under the PGA clause and the effect of cash payments for margin deposits associated with the Missouri Utilities’ use of natural gas derivative instruments may cause short-term cash requirements to vary. These procedures remain subject to prudence review by the MoPSC.

Alagasco currently does not utilize risk mitigation strategies that incorporate commodity hedge instruments, but has the ability to do so through its GSA. Mobile Gas hedges gas supply for up to 30 months in advance, and Willmut Gas utilizes hedging for the upcoming heating season.

The Utilities’ business activities are concentrated in three states.

The Utilities provide natural gas distribution services to customers in Missouri, Alabama and Mississippi. Changes in the regional economies, politics, regulations and weather patterns of these states could negatively impact the Utilities’ growth opportunities and the usage patterns and financial condition of customers and could adversely affect the Utilities’ earnings, cash flow, and financial position.

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The Utilities may be adversely affected by economic conditions.

Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies, a loss of existing customers, fewer new customers especially in newly constructed buildings. As a consequence, national or regional recessions or other downturns in economic activity could adversely affect the Utilities’ revenues and cash flows or restrict their future growth. Economic conditions in the Utilities’ service territories may also adversely impact the Utilities’ ability to collect accounts receivable, resulting in an increase in bad debt expenses.

Environmental laws and regulations may require significant expenditures or increase operating costs.

The Utilities are subject to federal, state and local environmental laws and regulations affecting many aspects of their present and future operations. These laws and regulations require the Utilities to obtain and comply with a wide variety of environmental licenses, permits, inspections, and approvals. Failure to comply with these laws and regulations and failure to obtain any required permits and licenses may result in costs to the Utilities in the form of fines, penalties or business interruptions, which may be material. In addition, existing environmental laws and regulations could be revised or reinterpreted and/or new laws and regulations could be adopted or become applicable to the Utilities or their facilities, thereby impacting the Utilities’ cost of compliance. The discovery of presently unknown environmental conditions, including former manufactured gas plant sites, and claims against the Utilities under environmental laws and regulations may result in expenditures and liabilities, which could be material. To the extent environmental compliance costs are not fully covered by insurance or recovered in rates from customers, those costs may have an adverse effect on the Utilities’ financial condition and results of operations.

The Utilities are subject to pipeline safety and system integrity laws and regulations that may require significant expenditures or significant increases in operating costs.

Such laws and regulations affect various aspects of the Utilities’ present and future operations. These laws and regulations require the Utilities to maintain pipeline safety and system integrity by identifying and reducing pipeline risks. Compliance with these laws and regulations, or future changes in these laws and regulations, may result in increased capital, operating and other costs which may not be recoverable in a timely manner from customers in rates.

Failure to comply may result in fines, penalties, or injunctive measures that would not be recoverable from customers in rates and could result in a material effect on the Utilities’ financial condition and results of operations.

Transporting, distributing, and storing natural gas and transporting and storing propane involves numerous risks that may result in accidents and other operating risks and costs.

There are inherent in gas distribution activities a variety of hazards and operations risks, such as leaks, accidental explosions, including third party damages, and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, impairment of operations, and substantial losses to the Utilities. The location of pipelines and storage facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. Similar risks also exist for Laclede Gas’ propane storage and transmission operations. These activities may subject the Utilities to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines, or penalties against the Utilities or be resolved on unfavorable terms. The Utilities are subject to federal and state laws and regulations requiring the Utilities to maintain certain safety and system integrity measures by identifying and managing storage and pipeline risks. Compliance with these laws and regulations, or future changes in these laws and regulations, may result in increased capital, operating and other costs which may not be recoverable in a timely manner from customers in rates. In accordance with customary industry practices, the Utilities maintain insurance against a significant portion, but not all, of these risks and losses. To the extent that the occurrence of any of these events is not fully covered by insurance, it could adversely affect the Utilities’ financial condition and results of operations.

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Because of the highly competitive nature of its business, the Utilities may not be able to retain existing customers or acquire new customers, which would have an adverse impact on their business, operating results and financial condition.

The Utilities face the risk that customers may bypass gas distribution services by gaining distribution directly from interstate pipelines or, in the case of Alagasco and Mobile Gas, also from municipally or publicly owned gas distributors located adjacent to its service territory. The Utilities cannot provide any assurance that increased competition or other changes in legislation, regulation or policies will not have a material adverse effect on their business, financial condition or results of operation.

The Utilities compete with distributors offering a broad range of services and prices, from full-service distributors to those offering delivery only. The Utilities also compete for retail customers with suppliers of alternative energy products, principally propane and electricity. If they are unable to compete effectively, the Utilities may lose existing customers and/or fail to acquire new customers, which could have a material adverse effect on their business, operating results and financial condition.

Changes in the wholesale costs of purchased natural gas supplies may adversely impact the Utilities’ competitive position compared with alternative energy sources.

Changes in wholesale natural gas prices compared with prices for electricity, fuel oil, coal, propane, or other energy sources may affect the Utilities’ retention of natural gas customers and may adversely impact their financial condition and results of operations.

Significantly warmer-than-normal weather conditions, the effects of climate change, legislative and regulatory initiatives in response to climate change or in support of increased energy efficiency, and other factors that influence customer usage may affect the Utilities’ sale of heating energy and adversely impact their financial position and results of operations.

The Utilities’ earnings are primarily generated by the sale of heating energy. The Missouri Utilities have weather mitigation rate designs and the Alabama Utilities have Temperature Adjustment Riders (TARs), each of which is approved by the respective state regulatory body, which provide better assurance of the recovery of fixed costs and margins during winter months despite variations in sales volumes due to the impacts of weather and other factors that affect customer usage. However, significantly warmer-than-normal weather conditions in the Utilities’ service areas and other factors, such as climate change, alternative energy sources and increased efficiency of gas furnaces and other appliances, may result in reduced profitability and decreased cash flows attributable to lower gas sales. Furthermore, continuation of the weather mitigation rate design at Laclede Gas, the rate design where distribution costs are recovered predominantly through fixed monthly charges at MGE, or the Rate Stabilization and Equalization (RSE) at Alagasco and Mobile are subject to regulatory discretion.

In addition, the promulgation of regulations by the U. S. Environmental Protection Agency (EPA), particularly those regulating the emissions of greenhouse gases, and by the U. S. Department of Energy supporting higher efficiency for residential gas furnaces and other gas appliances or the potential enactment of congressional legislation addressing global warming and climate change may decrease customer usage, encourage fuel switching from gas to other energy forms, and may result in future additional compliance costs that could impact the Utilities’ financial conditions and results of operations.

Regional supply/demand fluctuations and changes in national infrastructure, as well as regulatory discretion, may adversely affect the Missouri Utilities’ ability to profit from off-system sales and capacity release.

The Missouri Utilities’ income from off-system sales and capacity release is subject to fluctuations in market conditions and changing supply and demand conditions in areas the Missouri Utilities hold pipeline capacity rights. Specific factors impacting the Missouri Utilities’ income from off-system sales and capacity release include the availability of attractively-priced natural gas supply, availability of pipeline capacity, and market demand. Income from off-system sales and capacity release is shared with customers. The Missouri Utilities are allowed to retain 15% to 25% of the first $6.0 in annual income earned (depending on the level of income earned) and 30% of income exceeding $6.0 annually. In accordance with an agreement approved by the MoPSC, Laclede Gas deferred, until fiscal year 2017, its ability to retain 15% of the first $2.0. MGE is allowed to retain 15% to 25% of the first $3.6 in annual income earned (depending on the level of income earned) and 30% of income exceeding $3.6 annually. The Missouri Utilities’ ability to retain such income in the future is subject to regulatory discretion in a base rate proceeding.

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Catastrophic events may adversely affect the Utilities’ facilities and operations.

Catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes, tropical storms, terrorist acts, pandemic illnesses or other similar occurrences could adversely affect the Utilities’ facilities and operations. The Utilities have emergency planning and training programs in place to respond to events that could cause business interruptions. However, unanticipated events or a combination of events, failure in resources needed to respond to events, or slow or inadequate response to events may have an adverse impact on the Utilities’ operations, financial condition, and results of operations. The availability of insurance covering catastrophic events may be limited or may result in higher deductibles, higher premiums, and more restrictive policy terms.

RISKS THAT RELATE TO THE GAS MARKETING SEGMENT

Increased competition, fluctuations in natural gas commodity prices, expiration of supply and transportation arrangements, and infrastructure projects may adversely impact the future profitability of Gas Marketing.

Competition in the marketplace and fluctuations in natural gas commodity prices have a direct impact on the Gas Marketing business. Changing market conditions and prices, the narrowing of regional and seasonal price differentials and limited future price volatility may adversely impact its sales margins or affect its ability to procure gas supplies and/or to serve certain customers, which may reduce sales profitability and/or increase certain credit requirements caused by reductions in netting capability. Also, Gas Marketing profitability may be impacted by the effects of the expiration, in the normal course of business, of certain of its natural gas supply contracts if those contracts cannot be replaced and/or renewed with arrangements with similar terms and pricing. Although the Federal Energy Regulatory Commission (FERC) regulates the interstate transportation of natural gas and establishes the general terms and conditions under which LER may use interstate gas pipeline capacity to purchase and transport natural gas, it must occasionally renegotiate its transportation agreements with a concentrated group of pipeline companies. Renegotiated terms of new agreements, or increases in FERC-authorized rates of existing agreements, may impact Gas Marketing’s future profitability. Profitability may also be adversely impacted if pipeline capacity or future storage capacity secured is not fully utilized and/or its costs are not fully recovered.

Reduced access to credit and/or capital markets may prevent the Gas Marketing business from executing operating strategies.

The Gas Marketing segment relies on its cash flows, netting capability, parental guarantees, and access to Spire’s liquidity resources to satisfy its credit and working capital requirements. LER’s ability to rely on parental guarantees is dependent upon Spire’s financial condition and credit ratings. If the rating agencies lowered Spire’s credit ratings, particularly below investment grade, counterparty acceptance of parental guarantees may diminish, resulting in decreased availability of credit. Additionally, under such circumstances, certain counterparties may require LER to provide prepayments or cash deposits, amounts of which would be dependent upon natural gas market conditions. Reduced access to credit or increased credit requirements, which may also be caused by factors such as higher overall natural gas prices, may limit LER’s ability to enter into certain transactions. In addition, LER has concentrations of counterparty credit risk in that a significant portion of its transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. LER also has concentrations of credit risk in certain individually significant counterparties. LER closely monitors its credit exposure and, although uncollectible amounts have not been significant, increased counterparty defaults are possible and may result in financial losses and/or capital limitations.

Risk management policies, including the use of derivative instruments, may not fully protect Gas Marketing’s sales and results of operations from volatility and may result in financial losses.

In the course of its business, LER enters into contracts to purchase and sell natural gas at fixed prices and index-based prices. Commodity price risk associated with these contracts has the potential to impact earnings and cash flows. To minimize this risk, LER has a risk management policy that provides for daily monitoring of a number of business measures, including fixed price commitments.

LER currently manages the commodity price risk associated with fixed-price commitments for the purchase or sale of natural gas by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of natural gas futures, options, and swap contracts traded on or cleared through the NYMEX and ICE to lock in margins. These exchange-traded/cleared contracts may be designated as cash flow hedges of

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forecasted transactions. However, market conditions and regional price changes may cause ineffective portions of matched positions to result in financial losses. Additionally, to the extent that LER’s natural gas contracts are classified as trading activities or do not otherwise qualify for the normal purchases or normal sales designation (or the designation is not elected), the contracts are recorded as derivatives at fair value each period. Accordingly, the associated gains and losses are reported directly in earnings and may cause volatility in results of operations. Gains or losses (realized and unrealized) on certain wholesale purchase and sale contracts, consisting of those classified as trading activities, are required to be presented on a net basis (instead of a gross basis) in the statements of consolidated income. Such presentation could result in volatility in the Company’s operating revenues.

LER’s ability to meet its customers’ natural gas requirements may be impaired if contracted gas supplies and interstate pipeline services are not available or delivered in a timely manner.

LER’s ability to deliver natural gas to its customers is contingent upon the ability of natural gas producers, other gas marketers, and interstate pipelines to fulfill delivery obligations to LER under firm contracts. If these counterparties fail to perform, they have a contractual obligation to reimburse LER for adverse consequences. LER will attempt to use such reimbursements to obtain the necessary supplies so that it may fulfill its customer obligations. To the extent that it is unable to obtain the necessary supplies, LER’s financial position and results of operations may be adversely impacted.

Regulatory and legislative developments pertaining to the energy industry may adversely impact Gas Marketing’s results of operations, financial condition and cash flows.

The Gas Marketing business is non-regulated in that the rates it charges its customers are not established by or subject to approval by any regulatory body. However, it is subject to various laws and regulations affecting the energy industry. New regulatory and legislative actions may adversely impact Gas Marketing’s results of operations, financial condition, and cash flows by potentially reducing customer growth opportunities and/or increasing the costs of doing business.

LER could incur additional costs to comply with new laws and regulations, such as the Dodd-Frank Act, which regulates derivative transactions, including instruments it uses to manage risk. The Dodd-Frank Act contemplates that most swaps will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility, subject to certain exceptions for entities that use swaps to hedge or mitigate commercial risk. Although the Dodd-Frank Act includes significant new provisions regarding the regulation of derivatives, the impact of those requirements will not be known definitively until regulations have been adopted and fully implemented by both the SEC and the Commodities Futures Trading Commission, and market participants establish registered clearing facilities under those regulations. Although LER may qualify for exceptions, its derivatives counterparties may be subject to new capital, margin and business conduct requirements imposed as a result of the Dodd-Frank Act, which may increase its transaction costs, make it more difficult to enter into hedging transactions on favorable terms or affect the number and/or creditworthiness of available counterparties. LER’s inability to enter into derivative instruments on favorable terms, or at all, could increase operating expenses and expose it to risks of adverse changes in commodity prices.

In addition, as the regulatory environment for the natural gas industry increases in complexity, the risk of inadvertent noncompliance could also increase. If the business fails to comply with applicable laws and regulations, whether existing or new ones, it could be subject to fines, penalties or other enforcement action by the authorities that regulate its operations.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Spire

Refer to the information below about the principal properties of Laclede Gas and Alagasco. The EnergySouth utilities own approximately 5,500 miles of pipelines. Other properties of Spire and its subsidiaries, including LER and EnergySouth, do not constitute a significant portion of its properties. The current leases for office space in downtown St. Louis commenced in early 2015, with terms ranging from 10 to 20 years, with multiple renewal options. For further information on leases see Note 16, Commitments and Contingencies, of the Notes to Financial Statements in Item 8.

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Laclede Gas

The principal properties of Laclede Gas consist of its gas distribution system, which includes more than 30,000 miles of main and related service lines, odorization and regulation facilities, and customer meters. The mains and service lines are located in municipal streets or alleys, public streets or highways, or on lands of others for which we have obtained the necessary legal rights to place and operate our facilities on such property. Laclede Gas has an underground storage facility, several operating centers, and other related properties. Substantially all of Laclede Gas’ utility plant is subject to the liens of its mortgage. All of the properties of Laclede Gas are held in fee, or by easement, or under lease agreements. The principal lease agreements include underground storage rights that are of indefinite duration.

Alagasco

The properties of Alagasco consist primarily of its gas distribution system, which includes approximately 23,000 miles of main and related service lines, odorization and regulation facilities, and customer meters. The mains and service lines are located in municipal streets or alleys, public streets or highways, or on lands of others for which we have obtained the necessary legal rights to place and operate our facilities on such property. Alagasco also has four LNG facilities, several operating centers, and other related properties. All of the properties of Alagasco are held in fee, or by easement, or under lease agreements.

Item 3. Legal Proceedings

For a description of pending regulatory matters of Spire, see Note 15, Regulatory Matters, of the Notes to Financial Statements in Item 8. For a description of environmental matters, see Note 16, Commitments and Contingencies, of the Notes to Financial Statements in Item 8.

Spire and its subsidiaries are involved in litigation, claims, and investigations arising in the normal course of business. Management, after discussion with counsel, believes the final outcome will not have a material effect on the consolidated financial position or results of operations reflected in the consolidated financial statements presented herein.

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EXECUTIVE OFFICERS OF THE REGISTRANT – Listed below are executive officers as defined by the SEC for Spire, Laclede Gas and Alagasco. Their ages, at September 30, 2016, and positions are listed below along with their business experience during the past five years.

Name	Age	Position with Company *	Appointed (1)
S. Sitherwood	56	Spire
		President and Chief Executive Officer	February 2012
		President	September 2011
		Laclede Gas
		Chairman of the Board	January 2015
		Chairman of the Board and Chief Executive Officer	October 2012
		Chairman of the Board, Chief Executive Officer and President	February 2012
		Alagasco
		Chairman of the Board	September 2014
S. L. Lindsey (2)	50	Spire
		Executive Vice President, Chief Operating Officer, Distribution Operations	October 2012
		Laclede Gas
		Chief Executive Officer and President	January 2015
		President	October 2012
		Alagasco
		Chief Executive Officer	September 2014
S. P. Rasche	56	Spire
		Executive Vice President, Chief Financial Officer	November 2013
		Senior Vice President, Chief Financial Officer	October 2013
		Senior Vice President, Finance and Accounting	May 2012
		Laclede Gas
		Chief Financial Officer	May 2012
		Vice President, Finance	November 2009
		Alagasco
		Chief Financial Officer	September 2014
M. C. Darrell (3)	58	Spire
		Senior Vice President, General Counsel and Chief Compliance Officer	May 2012
		General Counsel	May 2004

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Name	Age	Position with Company *	Appointed (1)
L. C. Dowdy (4)	60	Spire
		Senior Vice President, External Affairs, Corporate Communications and Marketing	January 2014
M. C. Geiselhart	57	Spire
		Senior Vice President, Strategic Planning and Corporate Development	January 2015
		Vice President, Strategic Planning and Corporate Development	February 2014
		Vice President, Strategic Development and Planning	August 2006
K. A. Smith	58	Alagasco
		President	April 2015
		Vice President, System Integrity	August 2011
		Vice President, Operations	January 2008

* The information provided relates to the Company and its principal subsidiaries. Many of the executive officers have served or currently serve as officers or directors for other subsidiaries of the Company.

(1) Officers of Spire are normally reappointed by the Board of Directors in November of each year. Officers of Laclede Gas and Alagasco are normally reappointed by the Board of Directors in January of each year.

(2) Mr. Lindsey served as Senior Vice President, Southern Operations of AGL Resources, Inc. and President of its Atlanta Gas Light, Chattanooga Gas and Florida City Gas subsidiaries from December 2011 to October 2012. He also served as Vice President and General Manager of Atlanta Gas Light and Chattanooga Gas from 2005 to 2011.

(3) Mr. Darrell served as Senior Vice President and General Counsel of Laclede Gas from October 2007 to July 2012.

(4) Mr. Dowdy served as Partner at the law firm McKenna Long & Aldridge LLP until December 2013. He also served as Senior Vice President of Laclede Gas from January 2014 to January 2015.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

Spire

Spire’s common stock trades on The New York Stock Exchange (NYSE) under the symbol “SR.” The high and the low sales price for the common stock for each quarter in the two most recent fiscal years were:

	2016				2015
	High		Low		High		Low
1st Quarter	$	61.04	$	53.86	$	55.22	$	46.00
2nd Quarter	68.79		57.10		55.75		49.07
3rd Quarter	70.87		61.00		54.32		50.04
4th Quarter	71.21		61.96		56.31		49.66

The number of holders of record as of November 11, 2016 was 3,405.

Dividends declared on common stock for the two most recent fiscal years were:

	2016		2015
1st Quarter	$	0.49	$	0.46
2nd Quarter	0.49		0.46
3rd Quarter	0.49		0.46
4th Quarter	0.49		0.46

We have continuously paid a cash dividend to our common stockholders since 1946, with 2016 marking the 13th consecutive year of increasing the dividend on an annualized basis. Dividends are payable at the discretion of our Board of Directors. Future payment of dividends, and the amount of these dividends, will depend on our financial condition, results of operations, capital requirements, and other factors. We declared quarterly cash dividends on our common stock in 2016 and 2015, totaling $1.96 per share and $1.84 per share, respectively.

For disclosures related to securities authorized for issuance under equity compensation plans, see Item 12, page 136.

The only repurchases of Spire’s common stock during the three months ended September 30, 2016 would be pursuant to elections by employees to have shares of stock withheld to cover employee tax withholding obligations upon the vesting of performance-based and time-vested restricted stock and stock units. During the three months ended September 30, 2016, there were no such repurchases of Spire’s common stock.

Laclede Gas

Laclede Gas common stock is owned by its parent, Spire Inc., and is not traded on any stock exchange.

Dividends declared on common stock for the two most recent fiscal years were:

	2016		2015
1st Quarter	$	864.30	$	808.84
2nd Quarter	866.20		810.93
3rd Quarter	909.86		810.71
4th Quarter	569.64		811.21

Laclede Gas’ mortgage contains restrictions on its ability to pay cash dividends on its common stock, as described in further detail in Note 5, Stockholder’s Equity, of the Notes to Financial Statements in Item 8. As of September 30, 2016 and 2015, the amount under the mortgage’s formula that was available to pay dividends was 916.8 and $891.7, respectively.

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Spire periodically purchases common stock of Laclede Gas with the price set at the book value of Laclede Gas common stock as of the most recently completed fiscal quarter. The details on sales of common stock of Laclede Gas to Spire during the past three fiscal years are set forth below:

Date of Sale	Aggregate Purchase Price (In millions)		Number of Shares
2014
December 10, 2013	$	0.3	9
February 6, 2014	0.4		9
May 12, 2014	0.4		10
2015, 2016 (1)	—		—

(1) There were no purchases of Laclede Gas common stock during fiscal 2016 and 2015.

Exemption from registration for the sale of stock was claimed under section 4(a)(2) of the Securities Act of 1933.

Alagasco

Alagasco common stock is owned by its parent, Spire Inc., and is not traded on any stock exchange.

Dividends declared on common stock for the two most recent fiscal years were:

	2016		2015
1st Quarter	$	3.80	$	—
2nd Quarter	4.06		—
3rd Quarter	4.06		—
4th Quarter	4.06		—

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Item 6. Selected Financial Data

Spire

	Fiscal Years Ended September 30
(Dollars in millions, except per share amounts)	2016(1)			2015			2014(2)			2013(3)			2012
Statements of Income data
Total Operating Revenues	$	1,537.3		$	1,976.4		$	1,627.2		$	1,017.0		$	1,125.5
Net Income	144.2			136.9			84.6			52.8			62.6
Common Stock data
Diluted Earnings Per Share of Common Stock	$	3.24		$	3.16		$	2.35		$	2.02		$	2.79
Dividends Declared Per Share of Common Stock	1.96			1.84			1.76			1.70			1.66
Balance Sheet data
Total Assets	$	6,077.4		$	5,290.2		$	5,074.0		$	3,125.4		$	1,880.3
Long-Term Debt (less current portion)	1,833.7			1,771.5			1,851.0			912.7			339.4
Net Economic Earnings data (4)
Net Income (GAAP)	$	144.2		$	136.9		$	84.6		$	52.8		$	62.6
Unrealized (gain) loss on energy-related derivatives	(0.1		)	(2.8		)	(1.6		)	1.0			(0.5		)
Lower of cost or market inventory adjustments	0.2			0.4			(1.1		)	1.4			—
Realized (gain) loss on economic hedges prior to the sale of the physical commodity	(1.6		)	2.4			(0.4		)	—			0.3
Acquisition, divestiture and restructuring activities	9.2			9.8			29.5			17.3			0.2
Gain on sale of property	—			(7.6		)	—			—			—
Income tax effect of adjustments	(2.8		)	(0.8		)	(10.9		)	(7.6		)	—
Net Economic Earnings (Non-GAAP)	$	149.1		$	138.3		$	100.1		$	64.9		$	62.6
Diluted Earnings per Share of Common Stock:
Net Income (GAAP)	$	3.24		$	3.16		$	2.35		$	2.02		$	2.79
Unrealized (gain) loss on energy-related derivatives	—			(0.07		)	(0.04		)	0.04			(0.02		)
Lower of cost or market inventory adjustments	0.01			0.01			(0.03		)	0.05			—
Realized (gain) loss on economic hedges prior to the sale of the physical commodity	(0.04		)	0.06			(0.01		)	—			0.01
Acquisition, divestiture and restructuring activities	0.21			0.23			0.82			0.67			0.01
Gain on sale of property	—			(0.18		)	—			—			—
Income tax effect of adjustments	(0.06		)	(0.02		)	(0.31		)	(0.29		)	—
Weighted average shares adjustment	0.06			—			0.27			0.38			—
Net Economic Earnings (Non-GAAP)	$	3.42		$	3.19		$	3.05		$	2.87		$	2.79

(1) Effective September 12, 2016, Spire completed the purchase of 100% of the outstanding common stock of EnergySouth for $344 (including assumed debt of $67.0). Spire funded the purchase price with a combination of the issuance of approximately 2.2 million shares of common stock on May 17, 2016, the issuance of $165.0 aggregate principal amount of senior notes on September 9, 2016, and cash on hand.

(2) Effective August 31, 2014, Spire completed the purchase of 100% of the outstanding common stock of Alagasco for $1,590.3 (including assumed debt of $264.8), funded with a combination of the issuance of approximately 10.4 million shares of common stock and approximately 2.8 million equity units completed on June 11, 2014, the issuance of $625.0 aggregate principal amount of senior notes on August 19, 2014, and cash on hand.

(3) Effective September 1, 2013, Laclede Gas completed the purchase of substantially all of the assets and liabilities of MGE for $940.2, supported by a combination of the issuance of approximately 10 million shares of common stock completed on May 29, 2013 and the issuance by Laclede Gas of $450.0 of first mortgage bonds on August 13, 2013.

(4) This section contains the non-GAAP financial measures of net economic earnings (NEE) and net economic earnings per share (NEEPS). NEEPS are calculated by replacing consolidated net income with consolidated NEE in the GAAP diluted earnings per share calculation. Each reconciling item between NEE and net income is shown pre-tax, with total related income taxes calculated by applying effective federal, state, and local income tax rates applicable to ordinary income to those amounts.

2016 NEEPS excludes the impact of the May 2016 equity offering to fund the acquisition of EnergySouth. 2014 NEEPS excludes the impact of the June 2014 equity offerings to fund the acquisition of Alagasco. 2013 NEEPS excludes the impact of the May 2013 equity offering to fund the MGE acquisition. The weighted-average diluted shares used in the NEEPS calculation for fiscal years 2016, 2015, and 2013 were 43.5, 32.7, and 22.5, respectively, compared to 44.3, 35.9, and 26.0, respectively, used in the GAAP EPS calculations for those years.

For more information on net economic earnings data, refer to the Earnings section of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

(Dollars in millions, except per share amounts)

INTRODUCTION

This section analyzes the financial condition and results of operations of Spire Inc. (Spire or the Company), Laclede Gas Company (Laclede Gas or the Missouri Utilities), and Alabama Gas Corporation (Alagasco). Laclede Gas, Alagasco, and EnergySouth, Inc. (EnergySouth) are wholly owned subsidiaries of the Company. Laclede Gas, Alagasco and the subsidiaries of EnergySouth, are collectively referred to as the Utilities. This section includes management’s view of factors that affect the respective businesses of the Company, Laclede Gas, and Alagasco, explanations of financial results including changes in earnings and costs from the prior periods, and the effects of such factors on the Company’s, Laclede Gas’ and Alagasco’s overall financial condition and liquidity.

Reference is made to “Item 1A. Risk Factors” and “Forward-Looking Statements,” which describe important factors that could cause actual results to differ from expectations and non-historical information contained herein. In addition, the following discussion should be read in conjunction with the audited financial statements and accompanying notes thereto of Spire, Laclede Gas and Alagasco included in “Item 8. Financial Statements and Supplementary Data.”

RESULTS OF OPERATIONS

Overview

The Company has two key business segments: Gas Utility and Gas Marketing. Spire’s earnings are primarily derived from its Gas Utility segment, which reflects the regulated activities of the Utilities. The Gas Utility segment consists of the regulated businesses of Laclede Gas, Alagasco and the subsidiaries of EnergySouth. Due to the seasonal nature of the Utilities’ business, earnings of Spire, Laclede Gas and Alagasco are typically concentrated during the heating season of November through April each fiscal year.

Gas Utility - Laclede Gas

Laclede Gas is Missouri’s largest natural gas distribution company and is regulated by the Missouri Public Service Commission (MoPSC). Laclede Gas serves St. Louis and eastern Missouri through Laclede Gas and serves Kansas City and western Missouri through Missouri Gas Energy (MGE). Laclede Gas delivers natural gas to retail customers at rates and in accordance with tariffs authorized by the MoPSC. The earnings of Laclede Gas are primarily generated by the sale of heating energy. The rate design for each service territory serves to lessen the impact of weather volatility on its customers during cold winters and stabilize Laclede Gas’ earnings.

Gas Utility - Alagasco

On August 31, 2014, the Company purchased from Energen 100% of the outstanding common stock of Alagasco. Alagasco is the largest natural gas distribution utility in the state of Alabama. Alagasco’s service territory is located in central and northern Alabama. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. Alagasco is regulated by the Alabama Public Service Commission (APSC). Alagasco purchases natural gas through interstate and intrastate suppliers and distributes the purchased gas through its distribution facilities for sale to residential, commercial, and industrial customers and other end-users of natural gas. Alagasco also provides transportation services to large industrial and commercial customers located on its distribution system. These transportation customers, using Alagasco as their agent or acting on their own, purchase gas directly from marketers or suppliers and arrange for delivery of the gas into the Alagasco distribution system. Alagasco charges a fee to transport such customer-owned gas through its distribution system to the customers’ facilities.

Gas Marketing

Laclede Energy Resources, Inc. (LER) is engaged in the marketing of natural gas and related activities on a non-regulated basis and is reported in the Gas Marketing segment. LER markets natural gas across the country with the core of its footprint located in and around the central US. It holds firm transportation and storage contracts in order to effectively manage its customer base, which consists of producers, pipelines, power generators, storage operators, municipalities, utility companies, and large commercial and industrial customers.

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Business Evaluation Factors

Based on the nature of the business of the Company and its subsidiaries, as well as current economic conditions, management focuses on the following key variables in evaluating the financial condition and results of operations and managing the business.

Gas Utility segment:

• the Utilities’ ability to recover the costs of purchasing and distributing natural gas from their customers;

• the impact of weather and other factors, such as customer conservation, on revenues and expenses;

• changes in the regulatory environment at the federal, state, and local levels, as well as decisions by regulators, that impact the Utilities’ ability to earn its authorized rate of return in all service territories they serve;

• the Utilities’ ability to access credit markets and maintain working capital sufficient to meet operating requirements;

• the effect of natural gas price volatility on the business; and

• the ability to integrate the operations of all acquisitions.

Gas Marketing segment:

• the risks of competition;

• fluctuations in natural gas prices;

• new national infrastructure projects;

• the ability to procure firm transportation and storage services at reasonable rates;

• credit and/or capital market access;

• counterparty risks; and

• the effect of natural gas price volatility on the business.

Further information regarding how management seeks to manage these key variables is discussed below.

Gas Utility

The Utilities seek to provide reliable natural gas services at a reasonable cost, while maintaining and building secure and dependable infrastructures. The Utilities’ strategies focus on improving both performance and the ability to recover their authorized distribution costs and rates of return. The Utilities’ distribution costs are the essential, primarily fixed, expenditures it must incur to operate and maintain more than 58,000 miles of mains and services comprising the natural gas distribution systems and related storage facilities for Laclede Gas, Alagasco and the subsidiaries of EnergySouth.

The Utilities’ distribution costs include wages and employee benefit costs, depreciation and maintenance expenses, and other regulated utility operating expenses, excluding natural and propane gas expense. Distribution costs are considered in the rate-making process, and recovery of these types of costs is included in revenues generated through the Utilities’ tariff rates. Laclede Gas’ tariff rates are approved by the MoPSC, whereas Alagasco’s tariff rates are approved by the APSC. The subsidiaries of EnergySouth, Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas and Oil Company (Willmut Gas), have tariff rates that are approved by the APSC and Mississippi Public Service Commission (MSPSC), respectively. Laclede Gas also has an off-system sales and capacity release income stream that is regulated by tariff.

Laclede Gas’ income from off-system sales and capacity release remains subject to fluctuations in market conditions. Laclede Gas is allowed to retain the following portions of annual income (shown by service territory):

	Customer Share	Company Share
Eastern Missouri
First $2.0* of pre-tax income	100%	—%
Next $2.0 of pre-tax income	80%	20%
Next $2.0 of pre-tax income	75%	25%
Amounts of pre-tax income exceeding $6.0	70%	30%
* Customer share reverts to 85% and company share reverts to 15% in 2017.
Western Missouri
First $1.2 of pre-tax income	85%	15%
Next $1.2 of pre-tax income	80%	20%
Next $1.2 of pre-tax income	75%	25%
Amounts of pre-tax income exceeding $3.6	70%	30%

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Some of the factors impacting the level of off-system sales include the availability and cost of Laclede Gas’ natural gas supply, the weather in its service area, and the weather in other markets. When Laclede Gas’ service area experiences warmer-than-normal weather while other markets experience colder weather or supply constraints, some of Laclede Gas’ natural gas supply is available for off-system sales.

The Utilities work actively to reduce the impact of wholesale natural gas price volatility on their costs by strategically structuring their natural gas supply portfolios to increase their gas supply availability and pricing alternatives. They may also use derivative instruments to hedge against significant changes in the commodity price of natural gas. Nevertheless, the overall cost of purchased gas remains subject to fluctuations in market conditions. The Purchased Gas Adjustment (PGA) clause of Laclede Gas, Mobile Gas and Willmut Gas and Alagasco’s Gas Supply Adjustment (GSA) rider allow the Utilities to flow through to customers, subject to prudence review by the public service commissions, the cost of purchased gas supplies, including costs, cost reductions, and related carrying costs associated with the use of derivative instruments to mitigate volatility in the cost of natural gas, as well as gas inventory carrying costs. As of September 30, 2016, Laclede Gas had active derivative positions, but Alagasco has had no gas supply derivative instrument activity since 2010. The Utilities believe they will continue to be able to obtain sufficient gas supply. The price of natural gas supplies and other economic conditions may affect sales volumes, due to the conservation efforts of customers, and cash flows associated with the timing of collection of gas costs and related accounts receivable from customers.

The Utilities rely on short-term credit and long-term capital markets, as well as cash flows from operations, to satisfy their seasonal cash requirements and fund their capital expenditures. The Utilities’ ability to issue commercial paper, access their lines of credit, issue long-term bonds, or obtain new lines of credit is dependent on current conditions in the credit and capital markets. Management focuses on maintaining a strong balance sheet and believes it currently has adequate access to credit and capital markets and will have sufficient capital resources to meet their foreseeable obligations. See the Liquidity and Capital Resources section on page 44 for additional information.

Gas Marketing

LER is engaged in the marketing of natural gas and providing energy services to both on-system utility transportation customers and customers outside of the Utilities’ traditional service areas. LER utilizes its natural gas supply agreements, transportation agreements, park and loan agreements, storage agreements, and other executory contracts to support a variety of services to its customers at competitive prices. It closely monitors and manages the natural gas commodity price and volatility risks associated with providing such services to its customers through the use of a variety of risk management activities, including the use of exchange-traded/cleared derivative instruments and other contractual arrangements. LER is committed to managing commodity price risk while it seeks to expand the services that it now provides. Nevertheless, income from the Gas Marketing operations is subject to more fluctuations in market conditions than the Utilities’ operations.

The Gas Marketing business is directly impacted by the effects of competition in the marketplace, the impacts of new infrastructure, surplus natural gas supplies, and the addition of new demand from exports, power generation and industrial load. LER’s management expects a growing need for marketing services across the country as customers manage seasonal variability and marketplace volatility.

In addition to its operating cash flows, LER relies on Spire’s parental guarantees to secure its purchase and sales obligations of natural gas, and it also has access to Spire’s liquidity resources. A large portion of LER’s receivables are from customers in the energy industry. It also enters into netting arrangements with many of its energy counterparties to reduce overall credit and collateral exposure. Although LER’s uncollectible amounts are closely monitored and have not been significant, increases in uncollectible amounts from customers are possible and could adversely affect Gas Marketing’s liquidity and results of operations.

LER carefully monitors the creditworthiness of counterparties to its transactions. It performs in-house credit reviews of potential customers and may require credit assurances such as prepayments, letters of credit, or parental guarantees when appropriate. Credit limits for customers are established and monitored.

As a result of infrastructure optimization activities and an abundance of natural gas supply, LER cannot be certain that all of its wholesale purchase and sale transactions will settle physically. As such, certain transactions entered into in fiscal years 2016, 2015, and 2014 are designated as trading activities for financial reporting purposes, due to their settlement characteristics. Results of operations from trading activities are reported on a net basis in Gas Marketing operating revenues (or expenses, if negative), which may cause volatility in the Company’s operating revenues, but have no effect on operating income or net income.

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In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. In accordance with generally accepted accounting principles (GAAP), some of its purchase and sale transactions are not recognized in earnings until the natural gas is physically delivered, while other energy-related transactions, including those designated as trading activities, are required to be accounted for as derivatives, with the changes in their fair value (representing unrealized gains or losses) recorded in earnings in periods prior to settlement. Because related transactions of a purchase and sale strategy may be accounted for differently, there may be timing differences in the recognition of earnings under GAAP and economic earnings realized upon settlement. The Company reports both GAAP and net economic earnings (non-GAAP), as discussed below.

Other

In addition to the Gas Utility and Gas Marketing segments, the Company’s business includes certain other non-utility and corporate activities and costs, including:

• unallocated corporate costs, including certain debt and associated interest costs,

• Laclede Pipeline Company, a subsidiary of Spire which operates a propane pipeline under Federal Energy Regulatory Commission (FERC) jurisdiction,

• Spire STL Pipeline, a subsidiary of Spire planning construction of a 70-mile FERC-regulated pipeline to deliver natural gas into eastern Missouri, and

• Spire’s subsidiaries that are engaged in compression of natural gas and risk management, among other activities. All subsidiaries are wholly owned.

EARNINGS

Net income reported by Spire, Laclede Gas and Alagasco is determined in accordance with accounting principles generally accepted in the United States of America (GAAP). Management also uses the non-GAAP measures of net economic earnings, net economic earnings per share and operating margin when internally evaluating and reporting results of operations. These non-GAAP operating metrics should not be considered as an alternative to, or more meaningful than, GAAP measures such as net income.

Non-GAAP Measures - Net Economic Earnings and Net Economic Earnings Per Share

Net economic earnings and net economic earnings per share are non-GAAP measures that exclude from net income the after-tax impacts of fair value accounting and timing adjustments associated with energy-related transactions as well as acquisition, divestiture, and restructuring activities. These fair value and timing adjustments are made in instances where the accounting treatment differs from the economic substance of the underlying transaction, including the following:

• Net unrealized gains and losses on energy-related derivatives that are required by GAAP fair value accounting associated with current changes in the fair value of financial and physical transactions prior to their completion and settlement. These unrealized gains and losses result primarily from two sources:

1) changes in the fair values of physical and/or financial derivatives prior to the period of settlement; and,

2) ineffective portions of accounting hedges, required to be recorded in earnings prior to settlement, due to differences in commodity price changes between the locations of the forecasted physical purchase or sale transactions and the locations of the underlying hedge instruments;

• Lower of cost or market adjustments to the carrying value of commodity inventories resulting when the market price of the commodity falls below its original cost, to the extent that those commodities are economically hedged; and

• Realized gains and losses resulting from the settlement of economic hedges prior to the sale of the physical commodity.

These adjustments eliminate the impact of timing differences and the impact of current changes in the fair value of financial and physical transactions prior to their completion and settlement. Unrealized gains or losses are recorded in each period until being replaced with the actual gains or losses realized when the associated physical transactions occur. While management uses these non-GAAP measures to evaluate both the Utilities and Gas Marketing, the net effect of adjustments on the Utilities’ earnings is minimal. This is due to gains or losses on Laclede Gas’ natural gas derivative instruments being deferred pursuant to its PGA clause, as authorized by the MoPSC.

Management believes that excluding the earnings volatility caused by recognizing changes in fair value prior to settlement and other timing differences associated with related purchase and sale transactions provides a useful

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representation of the economic effects of only the actual settled transactions and their effects on results of operations. In addition, management excludes the impact related to unique acquisition, divestiture, and restructuring activities when evaluating on-going performance, and therefore excludes these impacts from net economic earnings. Net economic earnings per share also exclude the impacts of the May 2016, June 2014 and May 2013 equity offerings to fund the acquisitions of EnergySouth, Alagasco, and MGE, respectively. Management believes that this presentation provides a useful representation of operating performance by facilitating comparisons of year-over-year results. The definition and measurement of net economic earnings provided above is consistent with that used by management and the Board of Directors in assessing the Company’s, Laclede Gas’ and Alagasco’s performance as well as determining performance under the Company’s, Laclede Gas’ and Alagasco’s incentive compensation plans. Further, the Company believes this better enables an investor to view the Company’s, Laclede Gas’ and Alagasco’s performance in that period on a basis that would be comparable to prior periods.

Reconciliations of net economic earnings and net economic earnings per share to the Company’s most directly comparable GAAP measures are provided on the following pages.

Non-GAAP Measure - Operating Margin

In addition to operating revenues and operating expenses, management also uses the non-GAAP measure of operating margin when evaluating result of operations, as shown in the table below. The Utilities pass to their customers (subject to prudence review by, as applicable, the MoPSC, APSC, or MSPSC) increases and decreases in the wholesale cost of natural gas in accordance with their PGA clauses or GSA rider. The volatility of the wholesale natural gas market results in fluctuations from period to period in the recorded levels of, among other items, revenues and natural gas cost expense. Nevertheless, increases and decreases in the cost of gas associated with system gas sales volumes and gross receipts tax expense, which are calculated as a percentage of revenues, with the same amount, excluding immaterial timing differences, included in revenues, has no direct effect on operating income. As these costs are included in revenue and operating expenses and management does not have any control over these amounts for the Utilities, management believes that beginning with operating margins is a useful supplemental measure. In addition, it is management’s belief that operating margins and the remaining operating expenses that calculate operating income are useful assessing the Company’s and the Utilities’ performance as management has more ability to influence control over these revenues and expenses.

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SPIRE

Overview – Net Income (Loss)

		Gas Utility			Gas Marketing			Other			Consol-idated			Per Diluted Share
Year Ended September 30, 2016
	Net Income (Loss) (GAAP)	$	159.0		$	7.1		$	(21.9	)	$	144.2		$	3.24
	Adjustments, pre-tax:
	Unrealized (gain) loss on energy-related derivatives	(0.3		)	0.2			—			(0.1		)	—
	Lower of cost or market inventory adjustments	—			0.2			—			0.2			0.01
	Realized gain on economic hedges prior      to the sale of the physical commodity	—			(1.6		)	—			(1.6		)	(0.04		)
	Acquisition, divestiture and restructuring activities	2.3			—			6.9			9.2			0.21
	Income tax effect of adjustments*	(0.7		)	0.5			(2.6		)	(2.8		)	(0.06		)
	Weighted average shares adjustment**	—			—			—			—			0.06
	Net Economic Earnings (Loss) (Non-GAAP)	$	160.3		$	6.4		$	(17.6	)	$	149.1		$	3.42
Year Ended September 30, 2015
	Net Income (Loss) (GAAP)	$	153.3		$	4.1		$	(20.5	)	$	136.9		$	3.16
	Adjustments, pre-tax:
	Unrealized gain on energy-related derivatives	(0.1		)	(2.7		)	—			(2.8		)	(0.07		)
	Lower of cost or market inventory adjustments	—			0.4			—			0.4			0.01
	Realized loss on economic hedges prior    to the sale of the physical commodity	—			2.4			—			2.4			0.06
	Acquisition, divestiture and restructuring activities	3.1			—			6.7			9.8			0.23
	Gain on sale of property	(7.6		)	—			—			(7.6		)	(0.18		)
	Income tax effect of adjustments*	1.7			—			(2.5		)	(0.8		)	(0.02		)
	Net Economic Earnings (Loss) (Non-GAAP)	$	150.4		$	4.2		$	(16.3	)	$	138.3		$	3.19
Year Ended September 30, 2014
	Net Income (Loss) (GAAP)	$	87.1		$	12.2		$	(14.7	)	$	84.6		$	2.35
	Adjustments, pre-tax:
	Unrealized loss (gain) on energy-related derivatives	0.2			(1.8		)	—			(1.6		)	(0.04		)
	Lower of cost or market inventory adjustments	—			(1.1		)	—			(1.1		)	(0.03		)
	Realized gain on economic hedges prior      to the sale of the physical commodity	—			(0.4		)	—			(0.4		)	(0.01		)
	Acquisition, divestiture and restructuring activities	10.7			—			18.8			29.5			0.82
	Income tax effect of adjustments*	(5.2		)	1.3			(7.0		)	(10.9		)	(0.31		)
	Weighted average shares adjustment***	—			—			—			—			0.27
	Net Economic Earnings (Non-GAAP)	$	92.8		$	10.2		$	(2.9	)	$	100.1		$	3.05

* Income tax effect is calculated by applying federal, state, and local income tax rates applicable to ordinary income to the amounts of the pre-tax reconciling items.

** 2016 net economic earnings per share excludes the impact of the May 2016 equity offerings to fund the acquisition of EnergySouth. The weighted average diluted shares used in the net economic earnings per share calculation for the fiscal year ended September 30, 2016 was 43.5 compared to 44.3 in the GAAP EPS calculation.

*** 2014 net economic earnings per share excludes the impact of the June 2014 equity offerings to fund the acquisition of Alagasco. The weighted average diluted shares used in the net economic earnings per share calculation for the fiscal year ended September 30, 2014 was 32.7 compared to 35.9 in the GAAP EPS calculation.

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2016 vs. 2015

Consolidated

Spire’s net income was $144.2 in fiscal year 2016, compared with $136.9 in fiscal year 2015. Basic and diluted earnings per share were $3.26 and $3.24, respectively, for fiscal year 2016 compared with basic and diluted earnings per share of $3.16 for fiscal year 2015. Net economic earnings were $149.1 (or $3.42 per share) in fiscal year 2016, compared with $138.3 (or $3.19 per share) in fiscal year 2015. Net income increased in fiscal year 2016 compared to fiscal year 2015 primarily due to $5.7 income growth in the Gas Utility segment and $3.0 income growth in the Gas Marketing segment, partly offset by a $1.4 larger loss from other activities.

Gas Utility

Gas Utility net income and net economic earnings increased by $5.7 and $9.9, respectively, in 2016, compared to 2015. The increases to net income and net economic earnings were driven by higher Infrastructure System Replacement Surcharge (ISRS) charges at the Missouri Utilities and net favorable regulatory adjustments at Alagasco, partly offset by lower volumes resulting from warmer winter temperatures. The segment also benefited from a decrease in other operating expenses, which includes effects of the warmer weather. These impacts were partly offset by an increase in depreciation and amortization expenses. Additionally, interest expense was higher due to the increase experienced by Laclede Gas. Income taxes were also higher due to higher pre-tax income for both the Missouri and Alabama Utilities. Further details are discussed in the Gas Utility, Laclede Gas, and Alagasco sections below.

Gas Marketing

Gas Marketing reported net income totaling $7.1, an increase of $3.0 compared with the same period last year. Net economic earnings for fiscal year 2016 increased $2.2 from fiscal year 2015. The increases in net income and net economic earnings were primarily attributable to increases in operating margin, with the impact to net economic earnings being partly offset by mark-to-market activity as discussed in the Gas Marketing section below.

Other

The combined increase in net loss and net economic loss for the Company’s other non-utility activities were $1.4 and $1.3, respectively, for the 2016 fiscal year compared to the same period last year. The increase was primarily the result of higher interest charges.

Operating Revenues and Operating Expenses

Reconciliations of operating margin to the most directly comparable GAAP measure are shown below.

		Gas Utility		Gas Marketing		Other			Eliminations			Consolidated
Year Ended September 30, 2016
	Operating Revenues	$	1,459.4	$	78.5	$	4.8		$	(5.4	)	$	1,537.3
	Natural and propane gas expense	539.7		60.7		0.2			(3.0		)	597.6
	Gross receipts tax expense	75.3		0.1		—			—			75.4
	Operating margin (non-GAAP)	844.4		17.7		4.6			(2.4		)	864.3
	Depreciation and amortization	136.9		0.1		0.5			—			137.5
	Other operating expenses	429.2		5.8		11.9			(2.4		)	444.5
	Operating income (loss) (GAAP)	$	278.3	$	11.8	$	(7.8	)	$	—		$	282.3

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		Gas Utility		Gas Marketing		Other			Eliminations			Consolidated
Year Ended September 30, 2015
	Operating revenues	$	1,895.8	$	153.4	$	3.7		$	(76.5	)	$	1,976.4
	Natural and propane gas expense	957.6		140.5		0.3			(75.5		)	1,022.9
	Gross receipts tax expense	96.1		0.2		—			—			96.3
	Operating margin (non-GAAP)	842.1		12.7		3.4			(1.0		)	857.2
	Depreciation and amortization	129.9		0.3		0.6			—			130.8
	Other operating expenses	437.6		5.6		11.7			(1.0		)	453.9
	Operating income (loss) (GAAP)	$	274.6	$	6.8	$	(8.9	)	$	—		$	272.5

		Gas Utility		Gas Marketing		Other			Eliminations			Consolidated
Year Ended September 30, 2014
	Operating revenues	$	1,467.8	$	246.6	$	3.8		$	(91.0	)	$	1,627.2
	Natural and propane gas expense	821.8		220.4		—			(90.2		)	952.0
	Gross receipts tax expense	75.2		0.2		—			—			75.4
	Operating margin (non-GAAP)	570.8		26.0		3.8			(0.8		)	599.8
	Depreciation and amortization	82.4		0.4		0.5			—			83.3
	Other operating expenses	325.5		5.4		20.0			(0.8		)	350.1
	Operating income (loss) (GAAP)	$	162.9	$	20.2	$	(16.7	)	$	—		$	166.4

Consolidated

Spire reported operating revenues of $1,537.3 for the fiscal year ended September 30, 2016 compared with $1,976.4 for the same period last year. The decrease was driven primarily by the Utilities, the result of lower volumes and lower gas costs passed on to customers. Spire’s operating margin increased $7.1 for the twelve months ended September 30, 2016, compared to the same period last year. The increase was primarily due to higher operating margin of $5.0 and $2.3 for the Gas Marketing and Gas Utility segments, respectively, slightly offset by the lower operating margin reported in Other. Other operating expenses decreased $9.4 for the twelve months ended September 30, 2016 as compared to the same period last year, as discussed below. The decrease in other operating expenses was partially offset by $6.7 higher depreciation and amortization expense, driven principally by continued infrastructure investment at the Utilities in 2016.

Gas Utility

Operating Revenues – Gas Utility operating revenues for fiscal year 2016 decreased $436.4 compared to fiscal year 2015, and was primarily attributable to the following factors:

Lower wholesale gas costs passed on to customers	$	(262.8	)
Lower system sales volumes	(147.4		)
Missouri Utilities - Lower off-system sales and capacity release	(25.3		)
Lower gross receipts tax	(21.8		)
Missouri Utilities - Higher Infrastructure System Replacement Surcharge (ISRS) charges	13.8
Alagasco - Lower Rate Stabilization and Equalization (RSE) revenue adjustments	4.5
New customer revenue from EnergySouth acquisition	3.3
All other	(0.7		)
Total Variation	$	(436.4	)

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Operating Margin – Gas Utility operating margin was $844.4 for fiscal year 2016, a $2.3 increase over the same period last year. The increase was attributable to the following factors:

Lower system sales volumes	$	(18.0	)
Missouri Utilities - Higher Infrastructure System Replacement Surcharge (ISRS) charges	13.8
Alagasco - Lower Rate Stabilization and Equalization (RSE) revenue adjustments	4.5
Operating margin from EnergySouth acquisition	2.2
All other	(0.2		)
Total Variation	$	2.3

The increase was primarily attributable to benefits of higher ISRS charges for the Missouri Utilities in 2016 of $13.8, lower Rate Stabilization and Equalization (RSE) revenue adjustments, beneficial Cost Control Mechanism (CCM) and return on capital impacts totaling $4.5 for Alagasco, and $2.2 of operating margin resulting from the EnergySouth acquisition, which were mostly offset by the negative impact of lower sales volume. A $6.0 gain related to a legal settlement was recorded in other income, but operating margin was reduced by a revenue adjustment corresponding to the $6.0 gain, resulting in no impact on net income. Temperatures in the Laclede Gas and Alagasco service areas in 2016 were 19.7% and 30% warmer than in the same period in the prior year, respectively, significantly contributing to the $18.0 negative volume impact on operating margin in the current year.

Operating Expenses – Depreciation and amortization expenses for the twelve months-ended September 30, 2016 increased $7.0 from the same period last year, due principally to continued infrastructure capital spending in fiscal year 2016. Other operating expenses decreased $8.4 for the twelve months ended September 30, 2016 compared to the same period in the prior year. Excluding the impact of a $7.6 gain on the sale of property in the prior year, other operating expenses were $16.0 below prior year levels due primarily to lower bad debt expense (reflecting the impact of warmer weather experienced during the heating season) and employee-related costs.

Gas Marketing

Operating Revenues –Gas Marketing operating revenue for the twelve months ended September 30, 2016 decreased $74.9 from the same period last year. The decrease in revenues reflects the impact of higher total volumes being more than offset by lower commodity pricing levels, the effect of increased trading activities, and favorable mark-to-market adjustments on derivatives. Average pricing for the twelve months ended September 30, 2016 was approximately $2.286/MMBtu versus approximately $3.066/MMBtu for 2015, a $0.781 decline.

Operating Margin – Gas Marketing operating margin was $17.7 for fiscal year 2016, a $5.0 increase compared to the same period last year. Favorable wholesale trading volumes and storage optimization resulted in an $11.7 increase more than offsetting $7.9 of negative pricing impacts. Fair value adjustments accounted for an additional$1.2 favorable impact in the current year.

Other

Operating Revenue and Operating Expenses–Other operating revenue increased $1.1 for the twelve months ended September 30, 2016 compared to the same period in 2015. The increase was driven by new business activity at the Company’s insurance risk services subsidiary. Other operating expenses were essentially flat with the prior year.

Interest Charges

Interest charges during the twelve months ended September 30, 2016 increased $2.6 from the same period last year. Interest expense reductions from the refinancing of $115.0 in Alagasco long-term debt in September and December of 2015, along with lower average short-term borrowings, have been offset by higher rates on short-term borrowings, interest on debt issued to help finance the EnergySouth acquisition, interest on acquired debt, and charges related to a temporary bridge facility commitment obtained and terminated during the third quarter of this year related to the EnergySouth acquisition. For the twelve months ended September 30, 2016 and 2015, average short-term borrowings were $273.9 and $300.6, respectively, and the average interest rates on those borrowings were 0.9% and 0.7%, respectively.

Income Taxes

Consolidated Income tax expense increased $7.3 in fiscal year 2016 from fiscal year 2015 primarily due to higher pre-tax income and a higher effective tax rate. The current year effective tax rate of 32.5% is approximately 1.3

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percentage points higher than the prior year period. The higher current-year rate includes tax expense associated with a valuation allowance on deferred tax assets.

LACLEDE GAS

Summary Operating Results

Year ended September 30,	2016		2015
Operating revenues	$	1,087.5	$	1,416.6
Natural and propane gas expense	471.3		786.1
Gross receipts tax expense	57.4		73.5
Operating margin (non-GAAP)	558.8		557.0
Depreciation and amortization	88.6		82.6
Other operating expenses	283.3		289.0
Operating income (GAAP)	$	186.9	$	185.4
Net Income	$	105.9	$	105.3

Operating revenues during the twelve months ended September 30, 2016 decreased $329.1 from the same period last year. Revenues were impacted primarily by lower gas costs of $207.0 passed on to customers, $92.3 lower system volumes, $25.3 lower off system and capacity release sales, and lower gross receipts taxes of $17.1. These impacts were slightly offset by higher ISRS charges of $13.8.

Operating margin for the twelve months ended September 30, 2016 increased $1.8 from the same period last year. Higher ISRS charges of $13.8 were mostly offset by $11.7 lower system volumes in the current year.

Other operating expenses for the twelve months ended September 30, 2016 decreased $5.7 versus the same period last year. Excluding the benefit of last year’s gain on sale of property, the other operating expense decrease was $13.3. The decrease in other operating expenses was driven by lower bad debts (reflecting the impact of warmer weather experienced during the heating season) and lower employee-related costs. Depreciation and amortization increased $6.0, reflecting continued infrastructure investments. Interest expense in the current year was $1.0 greater than prior year, the result of lower short-term borrowings being offset by higher effective interest rates. Income taxes were $2.2 higher for the twelve months ended September 30, 2016 versus the comparable prior year period due to higher pre-tax book income and a slightly higher effective tax rate.

Temperatures experienced in the Missouri Utilities’ service area during 2016 were 19.7% warmer than the same period last year and 19.6% warmer than normal. Total system therms sold and transported were 1,479.3 million for fiscal year 2016 compared with 1,684.3 million for fiscal year 2015. Total off-system therms sold and transported outside of Laclede Gas’ service area were 183.3 million for fiscal year 2016 compared with 193.5 million for fiscal year 2015.

ALAGASCO

Summary Operating Results

Year ended September 30,	2016		2015
Operating revenues	$	368.5	$	479.2
Natural gas expense	67.3		171.5
Gross receipts tax expense	17.9		22.6
Operating margin (non-GAAP)	283.3		285.1
Depreciation and amortization	47.8		47.3
Other operating expenses	144.0		148.6
Operating income (GAAP)	$	91.5	$	89.2
Net Income	$	53.2	$	48.0

Operating revenues for the twelve months ended September 30, 2016 decreased $110.7 versus comparable period ended September 30, 2015. Of the decrease, $55.8 was attributable to lower costs passed onto customers and $55.1 was the result of lower current year volumes. Lower gross receipts taxes were offset by lower rate stabilization and equalization (RSE) revenue adjustments.

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Operating margin decreased $1.8 versus prior year, due primarily to the impact of lower volume not being completely offset by the favorable RSE and CCM adjustments. The RSE adjustments, although favorable, were negatively impacted by a reduction in revenues relating to a legal settlement of $6.0. There was no impact to net income, as this revenue adjustment offset a corresponding $6.0 gain recorded in other income.

Other operating expenses for the twelve months ended September 30, 2016 decreased $4.6 versus the year ended September 30, 2015. The decrease in other operating expenses was driven primarily by lower employee-related costs. Depreciation and amortization and interest expense were both slightly higher versus the same period last year. Income tax expense increased $3.1, primarily due to the higher pre-tax book income earned in the current year.

Temperatures in Alagasco’s service area during the twelve months ended September 30, 2016 were 24% warmer than normal and 30% warmer than the same period a year earlier. Alagasco’s total therms sold and transported were 878.1 million for the twelve months ended September 30, 2016, compared with 865.0 million for the same period last year.

For further information on the GSA, RSE and CCM mechanisms, please see Note 1, Summary of Significant Accounting Policies, and Note 15, Regulatory Matters, in the Notes to Financial Statements.

2015 vs. 2014

SPIRE

Consolidated

Spire’s net income was $136.9 in fiscal year 2015, compared with $84.6 in fiscal year 2014. Basic and diluted earnings per share were $3.16 for fiscal year 2015 compared with basic and diluted earnings per share of $2.36 and $2.35, respectively, for fiscal year 2014. Net economic earnings were $138.3 (or $3.19 per share) in fiscal year 2015, compared with $100.1 (or $3.05 per share) in fiscal year 2014. Net income increased in fiscal year 2015 compared to fiscal year 2014 primarily due to $66.2 income growth in the Gas Utility segment, which reflects $50.9 improvement relating to the inclusion of a full year of Alagasco earnings versus the $2.9 Alagasco loss included in 2014 for the month of September. Gas Utility also benefited from $15.3 income growth from the Missouri Utilities. The increased net income from Gas Utility was partially offset by an $8.1 decrease in Gas Marketing net income and a $5.8 higher loss from other non-utility activities, principally due to interest expense relating to the 2014 financing of the Alagasco acquisition.

Gas Utility

Gas Utility net income and net economic earnings increased by $66.2 and $60.6, respectively, in 2015, compared to 2014. The increases to net income and net economic earnings were primarily due to higher operating margin (a non-GAAP measure, as discussed below) of $271.3, which reflects the inclusion of Alagasco operating margin of $285.1 for twelve months in 2015 versus $14.8 for one month in 2014, and a $1.0 increase in Laclede Gas operating margin. The increase in operating margin was partially offset by an increase in other operating expenses of $112.1 and an increase in depreciation and amortization expenses totaling $47.5, as discussed in the Gas Utility section below. Additionally, interest expense for 2015 was $11.6 higher than 2014 due to the inclusion of full year Alagasco results offsetting the $1.0 decline experienced by Laclede Gas. Income taxes were also higher by $38.8, due to higher Missouri Utilities operating results and from the inclusion of twelve months of Alagasco operating results in 2015 versus only the month of September in 2014.

Gas Marketing

Gas Marketing reported GAAP earnings totaling $4.1, a decrease of $8.1 compared with the year ended September 30, 2014. Net economic earnings for fiscal year 2015 decreased $6.0 from fiscal year 2014. The decreases in net income and net economic earnings were primarily attributable to decreases in operating margin, with the impact to net economic earnings being partly mitigated by mark-to-market activity as discussed in the Gas Marketing section below.

Other

The combined net loss and net economic loss for the Company’s other non-utility activities were $5.8 and $16.4 larger, respectively, for the 2015 fiscal year compared to fiscal 2014. The increase in net loss was primarily the result

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of $16.6 increased interest expense related to the 2014 debt issued to finance the Alagasco acquisition, partially offset by lower transaction and integration expenses in fiscal year 2015 as compared to 2014.

Operating Revenues and Operating Expenses

Reconciliations of the Company’s operating margin to the most directly comparable GAAP measure are shown above.

Consolidated

Spire reported operating revenues of $1,976.4 for the fiscal year ended September 30, 2015 compared with $1,627.2 for the year ended September 30, 2014. Spire’s operating margin increased $257.4 for fiscal 2015, compared to fiscal 2014 primarily due to higher Gas Utility operating margin, slightly offset by the lower operating margin reported by Gas Marketing as discussed below. Other operating expenses and depreciation and amortization increased $103.8 and $47.5, respectively, for the twelve months ended September 30, 2015 as compared to the same period in fiscal 2014. These increases were primarily due to the impact of eleven additional months of Alagasco other operating expenses and depreciation and amortization expenses in fiscal 2015 totaling $134.4 and $43.4, respectively. The increase in other operating expenses was partially offset by $22.3 lower expenses in the Missouri Utilities and a $8.3 decrease in expenses in Other, as discussed below. The remaining increase in depreciation and amortization was related to higher capital spending within the Missouri Utilities in 2015.

Gas Utility

Operating Revenues – Gas Utility Operating Revenues for fiscal year 2015 increased $428.0, compared to fiscal year 2014, was primarily attributable to the following factors:

New customer revenue from Alagasco acquisition	$	459.5
Variance due to Missouri Utilities:
Lower system volumes and off-system pricing	(42.2		)
Base rate increases and Infrastructure System Replacement Surcharge (ISRS) charges	10.9
Higher wholesale gas prices passed to customers	7.1
Higher optimization of assets in the prior year	(6.2		)
Lower gross receipts tax	(1.8		)
All other variance	0.7
Total Variation	$	428.0

Operating Margin – Gas Utility operating margin was $842.1 for fiscal year 2015, a $271.3 increase over the same period of fiscal year 2014. The increase was attributable to the following factors:

Operating margin from Alagasco	$	270.3
Variance due to Missouri Utilities:
Base rate increases and ISRS charges	10.9
Lower system volumes and off-system pricing	(8.3		)
Higher optimization of assets in the prior year	(3.1		)
All other variance	1.5
Total Variation	$	271.3

The increase was primarily attributable to the acquisition of Alagasco totaling $270.3. Temperatures in the Laclede Gas service area in 2015 were 11.2% warmer than in the same period in 2014, negatively impacting current year revenues by $8.3. The prior year also benefited $3.1 due to a higher level of asset optimization. These negative impacts to revenue were mostly offset by base rate increases and ISRS charges of $10.9.

Operating Expenses – Gas Utility other operating expenses in fiscal year 2015 increased $112.1 from fiscal year 2014, with $134.4 attributable to the Alagasco acquisition offset by a decrease in other operating expenses within the Missouri Utilities. Of the $22.3 decrease in Missouri, $7.6 was due to a gain on the sale of property, $7.5 was the result of lower payroll and benefits expenses, and $9.8 resulted from cost efficiencies. Depreciation and amortization expense increased $4.1 at the Missouri Utilities primarily due to higher levels of capital expenditures, with the remaining $43.4 increase reflecting the inclusion of Alagasco for the full 2015 fiscal year.

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Gas Marketing

Operating Revenues – Gas Marketing operating revenue for the twelve months ended September 30, 2015 decreased $93.2 from the twelve months ended September 30, 2014 due to higher per unit gas sales prices in 2014 as the colder weather in the Midwest created higher market volatility and basis differentials (pricing differences between supply regions). Gas commodity pricing declined $1.35/MMBtu in fiscal 2015. Overall gas commodity pricing in 2015 was below 2014, negatively impacting revenues in 2015. Fiscal year 2014 also included a $3.3 higher benefit from mark-to-market impact on derivatives and inventory.

Operating Margin – Gas Marketing operating margin was $12.7 for fiscal year 2015, a $13.3 decrease compared to fiscal year 2014. Of this decrease, $10.0 was primarily attributable to higher sales margins (operating margin less fair value adjustments) in fiscal 2014 reflecting higher market volatility and basis differentials of natural gas prices and the expiration of a favorable gas supply contract in the first quarter of fiscal 2014. The remaining variance was due to $3.3 higher pre-tax income in 2014 associated with unrealized gains on derivatives and lower-of-cost-or-market adjustments to inventory.

Other

Operating Revenue and Operating Expenses–Other operating revenue was essentially flat with 2014, as volume increases at the Company’s Spire LNG fueling operations were offset by lower prices. Other operating expenses decreased $8.3 primarily due to the Alagasco acquisition-related transaction expenses in 2014 being higher than the MGE and Alagasco integration related expenses incurred in fiscal 2015.

Interest Charges

Interest charges during the twelve months ended September 30, 2015 increased $28.4 from the twelve months ended September 30, 2014. The increase was primarily due to the Company’s August 2014 issuance of long-term debt totaling $625.0, and the June 2014 issuance of equity units totaling $143.8. These increases were partially offset by Laclede Gas’ early redemption of $80.0 of 6.35% first mortgage bonds on January 6, 2014. The assumption of Alagasco debt contributed $12.6 to the increase in interest expense. For the twelve months ended September 30, 2015 and 2014, average short-term borrowings were $300.6 and $82.3, respectively, and the average interest rates on those borrowings were 0.7% and 0.5%, respectively.

Income Taxes

Consolidated income tax expense increased $29.9 in fiscal year 2015 from fiscal year 2014 primarily due to higher pre-tax income and a higher effective tax rate. The 2015 effective tax rate of 31.2% is approximately 3.6 percentage points higher than 2014 primarily due to the full-year inclusion of Alagasco, which has a higher effective tax rate than Laclede Gas.

In connection with the acquisition of 100% of the common stock of Alagasco, the Company and Energen made an election under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended, to treat the acquisition as a deemed purchase and sale of assets for tax purposes. As a result of the election, goodwill was generated for tax purposes at Alagasco. For book purposes, goodwill was recorded on the Spire parent entity balance sheet and not pushed down to Alagasco. Consequently, a deferred tax asset (DTA) was recorded at Alagasco related to the excess of tax deductible goodwill over book goodwill for the stand-alone entity. That initial goodwill DTA is eliminated (along with the investment in subsidiary and Alagasco’s equity) in the Spire consolidated balance sheet because, at that consolidated level, there is no excess of tax deductible goodwill over book goodwill. As the tax goodwill is amortized and deducted for tax purposes, the DTA at Alagasco is reduced, and for Spire, a deferred tax liability (DTL) is created. For both Alagasco and consolidated Spire, the change to the goodwill DTA/DTL is reported as a component of deferred tax expense in the statements of income. Because the deferred tax expense impact is offset by an opposite current tax expense impact, there is no significant impact on the effective tax rate of the Company.

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of our financial condition, results of operations, liquidity, and capital resources are based upon our financial statements, which have been prepared in accordance with GAAP, which requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates on an ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. We

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believe the following represent the more significant items requiring the use of judgment and estimates in preparing our financial statements:

Regulatory Accounting – The Utilities account for their regulated operations in accordance with FASB ASC Topic 980, “Regulated Operations.” The provisions of this accounting guidance require, among other things, that financial statements of a rate-regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-rate-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities). Management believes that the current regulatory environment supports the continued use of these regulatory accounting principles and that all regulatory assets and regulatory liabilities are recoverable or refundable through the regulatory process. For Laclede Gas and Alagasco, management believes the following represent the more significant items recorded through the application of this accounting guidance:

PGA Clause – Laclede Gas’ PGA clauses allows the Missouri Utilities to flow through to customers, subject to a prudence review by the MoPSC, the cost of purchased gas supplies, including the costs, cost reductions, and related carrying costs associated with the Missouri Utilities’ use of natural gas derivative instruments to hedge the purchase price of natural gas. The difference between actual costs incurred and costs recovered through the application of the PGA clauses are recorded as regulatory assets and regulatory liabilities that are recovered or refunded in a subsequent period. The PGA clauses also permit the application of carrying costs to all over- or under-recoveries of gas costs, including costs and cost reductions associated with the use of derivative instruments, and also provide for a portion of income from off-system sales and capacity release revenues to be flowed through to customers. Laclede Gas’ PGA clauses also authorizes it to recover costs it incurs to finance its investment in gas supplies that are purchased during the storage injection season for sale during the heating season.

GSA Rider –Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the GSA rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Alagasco. Alagasco currently has no active gas supply derivative positions.

Goodwill – Goodwill is measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities, and adjustments are recorded during the measurement period to finalize the allocation of purchase price. Laclede Gas has recorded goodwill related to the 2013 acquisition of MGE and Spire also has recorded goodwill related to the 2016 and 2014 acquisitions of EnergySouth and Alagasco, respectively. Neither EnergySouth nor Alagasco have goodwill on their balance sheets as push down accounting was not applied. Spire and Laclede Gas evaluate goodwill for impairment as of July 1st of each year, or more frequently if events and circumstances indicate that goodwill might be impaired. The goodwill impairment test compares the fair value of each reporting unit to its carrying amount, including goodwill. At July 1, 2016, 2015 and 2014, Spire and Laclede Gas each applied a quantitative goodwill evaluation model to their reporting units and concluded goodwill was not impaired because the fair value exceeded the carrying amounts. Testing for the goodwill associated with the September 2016 acquisition of EnergySouth will commence in 2017.

Employee Benefits and Postretirement Obligations – Pension and postretirement obligations are calculated by actuarial consultants that utilize several statistical factors and other assumptions provided by management related to future events, such as discount rates, returns on plan assets, compensation increases, and mortality rates. For the Utilities, the amount of expense recognized and the amounts reflected in other comprehensive income are dependent upon the regulatory treatment provided for such costs, as discussed further below. Certain liabilities

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related to group medical benefits and workers’ compensation claims, portions of which are self-insured and/or contain “stop-loss” coverage with third-party insurers to limit exposure, are established based on historical trends.

The amount of net periodic pension and other postretirement benefit cost recognized in the financial statements related to the Utilities’ qualified pension plans and other postretirement benefit plans is based upon allowances, as approved by the MoPSC (for Laclede Gas) and as approved by the APSC (for Alagasco). The allowances have been established in the rate-making process for the recovery of these costs from customers. The differences between these amounts and actual pension and other postretirement benefit costs incurred for financial reporting purposes are deferred as regulatory assets or regulatory liabilities. GAAP also requires that changes that affect the funded status of pension and other postretirement benefit plans, but that are not yet required to be recognized as components of pension and other postretirement benefit cost, be reflected in other comprehensive income. For the Utilities’ qualified pension plans and other postretirement benefit plans, amounts that would otherwise be reflected in other comprehensive income are deferred with entries to regulatory assets or regulatory liabilities.

The tables below reflect the sensitivity of Spire’s plans to potential changes in key assumptions:

Pension Plan Benefits:
Actuarial Assumptions	Increase/ (Decrease)		Estimated Increase/ (Decrease) to Projected Benefit Obligation			Estimated Increase/ (Decrease) to Annual Net Pension Cost*
Discount Rate	0.25	%	$	(19.5	)	$	0.4
	(0.25	)%	20.5			(0.4		)
Rate of Future Compensation Increase	0.25	%	7.3			0.5
	(0.25	)%	(7.1		)	(0.5		)
Expected Return on Plan Assets	0.25	%	—			(1.2		)
	(0.25	)%	—			1.2

Postretirement Benefits:
Actuarial Assumptions	Increase/ (Decrease)		Estimated Increase/ (Decrease) to Projected Postretirement Benefit Obligation			Estimated Increase/ (Decrease) to Annual Net Postretirement Benefit Cost*
Discount Rate	0.25	%	$	(5.6	)	$	—
	(0.25	)%	5.8			—
Expected Return on Plan Assets	0.25	%	—			(0.6		)
	(0.25	)%	—			0.6
Annual Medical Cost Trend	1.00	%	11.0			1.5
	(1.00	)%	(10.2		)	(1.4		)

* Excludes the impact of regulatory deferral mechanism. See Note 13, Pension Plans and Other Postretirement Benefits, of the Notes to Financial Statements for information regarding the regulatory treatment of these costs.

For further discussion of significant accounting policies, see Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements.

REGULATORY AND OTHER MATTERS

Laclede Gas

On November 12, 2015, the MoPSC approved an incremental Infrastructure System Replacement Surcharge (ISRS) amount of $4.4 for Laclede Gas’ eastern Missouri service territory and $1.9 for MGE, effective December 1, 2015, bringing total annualized ISRS revenue to $19.6 for Laclede Gas’ eastern Missouri service territory and $6.7 for MGE’s service territory. On January 15, 2016, the Missouri Office of the Public Counsel (OPC) filed an appeal to Missouri’s Western District Court of Appeals of the MoPSC’s decision permitting Laclede Gas to update its ISRS applications during the pendency of the case. On September 27, 2016, the Western District affirmed the report and order of the MoPSC.

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On May 19, 2016, the MoPSC approved an incremental ISRS amount of $5.4 for Laclede Gas’ eastern Missouri service territory and $3.6 for MGE, effective May 31, 2016, bringing total annualized ISRS revenue to $25.0 for Laclede Gas’ eastern Missouri service territory and $10.3 for MGE’s service territory. On June 30, 2016, the OPC filed an appeal to Missouri’s Western District Court of Appeals of the MoPSC’s decision permitting Laclede Gas to update its ISRS applications during the pendency of the case. Laclede Gas believes the MoPSC’s decision was lawful and reasonable, and believes the updating process will again be upheld by the Western District and intends to vigorously oppose the appeal.

On September 30, 2016 Laclede Gas filed to increase its ISRS revenues, by $5.0 for Laclede Gas’ eastern Missouri service territory and $3.4 for MGE, related to ISRS investments from March 2016 through October 2016. The MoPSC suspended the tariff until January 28, 2017 and directed the MoPSC Staff (Staff) to file a recommendation no later than November 29, 2016.

Laclede Gas previously had authority from the MoPSC to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in capital, and enter into capital lease agreements, all for a total of up to $518.0. This authority was scheduled to expire June 30, 2015. On April 15, 2015, Laclede Gas applied to the MoPSC for a new financing authorization in the amount of $550.0, and on June 24, 2015, the MoPSC granted an extension of the current authorization until the pending application was resolved. On February 10, 2016, the MoPSC issued an order, by a 3-2 vote, authorizing Laclede financing authority for $300.0 for financings placed any time before September 30, 2018. Laclede Gas filed an application for rehearing, which was denied on March 9, 2016. On March 31, 2016, Laclede Gas filed an appeal with the Western District Court of Appeals concerning this matter. On July 20, 2016, Laclede Gas filed its initial brief before the Court. The MoPSC filed its reply brief on September 19, 2016. Laclede Gas filed its final brief on October 4, 2016. Oral arguments are scheduled for November 17, 2016. Laclede Gas issued no securities under this authorization since the decision and $300.0 remained available for issuance as of November 11, 2016.

On April 26, 2016, the OPC filed a Complaint with the MoPSC alleging that Laclede Gas was over-earning in its eastern Missouri and MGE service territories. OPC asked the MoPSC to “direct Staff to conduct whatever investigation and recommendations are necessary under the circumstances” concerning the allegation. On April 28, 2016, the MoPSC ordered Laclede Gas to answer the complaint by May 31, 2016. On May 20, 2016, the MoPSC Staff filed a response stating that “OPC has not adequately supported its claims of overearning by Laclede and MGE” and asked the MoPSC to deny OPC’s request to have Staff do an investigation. On May 31, 2016, Laclede Gas filed its answer as well as a motion to dismiss. On July 12, 2016, the MoPSC denied Laclede Gas’ motion to dismiss but affirmed that the OPC will have to carry the burden of proving the complaint. On September 29, 2016, the OPC filed a motion to stay proceedings. On October 5, 2016, the MoPSC approved OPC’s request to stay its complaint. Laclede Gas continued to assert throughout the proceeding that there was no valid basis for the complaint.

On June 16, 2016, the OPC filed a motion to open an investigation of the announced acquisition of EnergySouth and the completed acquisition of Alagasco by Spire, to determine whether or not the proposed or completed transactions are likely to be detrimental to the public interest and the interests of Missouri ratepayers. On June 27, Spire filed a response opposing OPC’s motion asserting, among other things, that the MoPSC lacked jurisdiction over those transactions. On July 11, 2016, the Staff filed a response asserting that the MoPSC did have jurisdiction and requested that MoPSC open a docket for the investigation of the acquisition of Alagasco and the announced acquisition of EnergySouth by Spire, to determine whether they are, or are likely to be, detrimental to the public interest and the interests of Missouri ratepayers. On July 20, 2016, the MoPSC granted the Staff’s motion and, while making no finding on the MoPSC’s jurisdiction over the transaction, ordered Staff to file a report no later than September 2, 2016. On September 1, 2016, the Staff filed its report alleging that Spire was in violation of its holding company stipulation by not seeking MoPSC approval of such transactions. Staff also summarized certain “potential detriments” to ratepayers and noted that it will pursue a complaint for the violation in the holding company case. On September 6, 2016, Spire filed a response to the investigation report noting that the Staff’s summary was incorrect and directly conflicted with the views in the Staff report expressed by its own experts that failed to identify any detriments associated with the transactions. On September 7, 2016, the MoPSC closed the file without sanctioning a complaint or making a determination on jurisdiction. No further formal actions have taken place at this time.

Alagasco

Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s current RSE order has a term extending beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control, the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco’s

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allowed range of return on average common equity is 10.5% to 10.95% with an adjusting point of 10.8%. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4% of prior-year revenues.There was no RSE reduction for the January 31, 2016 quarterly point of test. Related to the April 30, 2016 quarterly point of test, Alagasco recorded a $5.8 RSE reduction to operating revenues, which the APSC directed, by order dated June 20, 2016, be applied to the Gas Supply Adjustment (GSA) balance. The RSE reduction for the July 31, 2016 quarterly point of test was $4.8. As of September 30, 2016, Alagasco recorded a $2.7 RSE reduction to operating revenues to bring the expected rate of return on average common equity at the end of the year to within the allowed range of return. The quarterly point of test reductions from rate year 2016 went into effect October 1, 2016 for $4.8 and will go into effect December 1, 2016 for $2.7. On October 26, 2016, as part of their annual update for RSE, Alagasco filed a $1.3 reduction for rate year 2017, which is subject to review by APSC Staff and becomes effective December 1, 2016 unless otherwise ordered by the APSC.

The inflation-based Cost Control Mechanism (CCM), established by the APSC, allows for annual increases to operations and maintenance (O&M) expense. The CCM range is Alagasco’s 2007 actual rate year O&M expense (Base Year) inflation-adjusted using the June Consumer Price Index For All Urban Consumers each rate year plus or minus 1.75% (Index Range). If rate year O&M expense falls within the Index Range, no adjustment is required. If rate year O&M expense exceeds the Index Range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent that rate year O&M is less than the Index Range, Alagasco benefits by one-half of the difference through future rate adjustments. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. A CCM benefit to the company for such cost saving of $7.8 related to 2016 will be reflected in rates effective December 1, 2016. The CCM benefit was $4.7 for 2015.

On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, and a regulatory liability set up for Alagasco, with the revised prospective composite depreciation rate approximating 3.1%. Refunds from such negative salvage liability will be passed back to eligible customers on a declining basis through lower tariff rates through rate year 2019 pursuant to the terms of this Negative Salvage Rebalancing (NSR) rider. The total amount refundable to customers is subject to adjustments over the remaining period for charges made to the Enhanced Stability Reserve (ESR) and other APSC-approved charges. The refunds are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements. This order also required a comprehensive depreciation study to occur every 5 years. This was completed and provided to the APSC in a timely manner in fiscal 2015. For fiscal year 2016, $8.3 of the customer refund has been returned to customers, and $18.7 is remaining to be refunded to customers. The NSR pass back for fiscal year 2017 is $9.3 and will be reflected in rates effective December 1, 2016 through March 31, 2017.

The APSC approved an ESR in 1998, which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self-insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self-insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $0.3 and $0.4, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $0.4 during a rate year. Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which prescribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine-year period and subject to APSC authorization, Alagasco expects to be able to recover underfunded ESR balances over a five-year amortization period with an annual limitation of $0.7. Amounts in excess of this limitation are deferred for recovery in future years.

On September 7, 2016, Alagasco filed an application with the APSC for accounting authorization relating to $6.0 of legal proceeds. The APSC approved the application September 13, 2016, ordering Alagasco to apply the proceeds as a credit of $2.8 to the ESR and a credit of $3.2 to the GSA.

On March 25, 2016, Alagasco filed an application with the APSC for an intercompany revolving credit agreement allowing Alagasco to borrow from Spire in a principal amount not to exceed $200.0 at any time outstanding in combination with its bank line of credit, and to loan to Spire in a principal amount not to exceed $25.0 at any time

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outstanding. Borrowings may be used for the following purposes: (a) increasing working capital requirements; (b) financing construction requirements related to additions, extensions, and replacements of the distribution systems; and (c) financing other expenditures that may arise from time to time in the normal course of business. The application was approved by an APSC order dated April 5, 2016.

Spire

In addition to the matters described above, the following regulatory matters affect Spire.

Mobile Gas has similar rate regulation to Alagasco’s. The RSE allowed range of return on average common equity is 10.45% to 10.95% with an adjusting point of 10.8%. The CCM has the same return and recovery provisions when expenses exceed or are under a band of +/- 1.75% around the CPI-U inflated O&M expense level from September 30, 2013, excluding expenses for pensions and gas bad debt. Additionally, it has a Cast Iron Main Replacement (CIMR) factor that provides an enhanced return on the pro-rata costs associated with cast iron main replacement for miles over 10 miles per year based on a 75% weighting for the equity content. Mobile Gas also has an ESR for negative revenue variances over $o.1 or a force majeure event expense of $0.1 (or two events that exceed $0.15), a Self Insurance Reserve (SIR) for general liability coverage, and an Environmental Cost Recovery Factor (ECRF) as part of its PGA that recovers 90% of prudently incurred costs for compliance with environmental laws, rules and regulations. It also has an intercompany revolving credit agreement with Spire to borrow in a principal amount not to exceed $50.0, and to loan up to $25.0.

Willmut Gas utilizes a formula rate-making process under Rider RSA. It is based on a formulaically derived ROE, and is updated on an annual basis if the equity return on an end of period rate base is beyond the allowed ROE by 1.0%, with 75% of any shortfall back to the midpoint being put into a rate increase and 50% of any excess back to the midpoint resulting in a rate decrease. Updates are made based on known and measurable adjustments to historic costs from 12-months ended June 30th, submitted September 15th for an effective date of November 1st, unless disputed by the Mississippi Public Utilities Staff, with any disputes to be resolved by the MSPSC by January 15th of the following year. Willmut Gas had approved December 3, 2015 a Supplemental Growth Rider (SGR) for a 3-year period to provide enhanced returns of a 12.0% ROE for a period of 10 years on certain system expansion projects.

On July 22, 2016, the proposed project of Spire STL Pipeline LLC, a wholly owned subsidiary of Spire, was accepted into the pre-filing process at the FERC. The proposal outlined the plan to build, own, operate, and maintain a pipeline interconnecting with the Rockies Express pipeline to deliver natural gas to the St. Louis, Missouri area. As an interstate project, the Spire STL Pipeline will be reviewed for siting and permitting by the FERC, which will be the lead agency for other federal, state, and local permitting authorities.

ACCOUNTING PRONOUNCEMENTS

The Company, Laclede Gas and Alagasco have evaluated or are in the process of evaluating the impact that recently issued accounting standards will have on their financial position or results of operations upon adoption. For disclosures related to the adoption of new accounting standards, see the New Accounting Pronouncements section of Note 1 of the Notes to Financial Statements.

INFLATION

The accompanying financial statements reflect the historical costs of events and transactions, regardless of the purchasing power of the dollar at the time. Due to the capital-intensive nature of the businesses of the Company, Laclede Gas and Alagasco, the most significant impact of inflation is on the depreciation of utility plant. Rate regulation, to which the Utilities are subject, allows recovery through its rates of only the historical cost of utility plant as depreciation. The Utilities expect to incur significant capital expenditures in future years, primarily related to the planned increased replacements of distribution plant. The Company, Laclede Gas and Alagasco believe that any higher costs experienced upon replacement of existing facilities will be recovered through the normal regulatory process.

FINANCIAL CONDITION

CASH FLOWS

Spire

The Company’s short-term borrowing requirements typically peak during colder months when the Utilities borrow money to cover the lag between when it purchases its natural gas and when its customers pay for that gas. Changes in the wholesale cost of natural gas (including cash payments for margin deposits associated with Laclede Gas’ use

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of natural gas derivative instruments), variations in the timing of collections of gas cost under Laclede Gas’ PGA clause and Alagasco’s GSA rider, the seasonality of accounts receivable balances, and the utilization of storage gas inventories cause short-term cash requirements to vary during the year and from year to year, and may cause significant variations in the Company’s cash provided by or used in operating activities.

Cash Flow Summary	2016			2015			2014
Net cash provided by operating activities	$	328.3		$	322.4		$	122.6
Net cash used in investing activities	(612.7		)	(298.7		)	(1,437.6		)
Net cash provided by (used in) financing activities	275.8			(26.0		)	1,278.1

Net cash provided by operating activities increased $5.9 from 2015 to 2016. This increase was primarily driven by increased net income, higher depreciation and favorable fluctuations in working capital components, largely offset by the timing of collections of gas costs under the PGA. The $199.8 increase in net cash provided by operating activities from 2014 to 2015 was primarily due to the inclusion of a full year of Alagasco cash flows in 2015 versus only one month in 2014, which provided $96.3 of incremental cash from operating activities. The remaining increase was driven by the timing of collections of gas costs under the PGA and changes in natural gas inventory values.

Cash used in investing activities increased $314.0 in 2016 versus 2015. The primary driver of the increase was the $317.7 net cash paid for the acquisition of EnergySouth, against a prior year final working capital adjustment of $8.2 related to the Alagasco acquisition. The remaining increase related to slightly higher capital expenditures supporting Spire’s infrastructure upgrades. Excluding $1,305.2 for the 2014 acquisition of Alagasco, cash used in investing activities increased $166.3 in 2015 versus 2014. The increase was driven by higher capital expenditures of approximately $118.8, which includes the incremental increase of $80.2 for Alagasco and an increase of $35.6 at Laclede Gas. Additionally, 2015 included the previously referenced final adjustment associated with the Alagasco acquisition, whereas 2014 included the cash receipts associated with the MGE acquisition and the sale of New England Gas Company to Algonquin Power & Utility Corp. Spire estimates its capital expenditures for fiscal 2017 will be approximately $410, including approximately $370 for Gas Utilities. The increase in investment for Gas Utilities in 2017 reflects the continued ramp-up of infrastructure upgrades across both Missouri and Alabama, and the addition of capital expenditures to support EnergySouth.

Cash provided by 2016 financing activities was $275.8, an increase of $301.8 over the $26.0 cash used in 2015. Excluding the proceeds from the 2016 common stock issuance of 2.185 million shares of $133.0 and the 2016 issuance of long-term debt of $165.0 related to funding of the EnergySouth acquisition, the difference between net cash provided by financing activities in 2016 versus the net use of cash in 2015 was $3.8. This difference was the result of slightly higher short-term borrowings in the current year, partially offset by an increase in dividends paid. Excluding the proceeds from the 2014 common stock issuance of 10.350 million shares of $457.1 and the 2014 issuance of long-term debt of $768.8 to help fund the acquisition of Alagasco, the difference between net cash used in 2015 and net cash provided in 2014 was $78.2. This change primarily reflects the decrease in short-term borrowing and the increase in dividends paid, partially offset by the lower repayment of long term-debt.

LIQUIDITY AND CAPITAL RESOURCES

Cash and Cash Equivalents

Spire had no temporary cash investments as of September 30, 2016, but the balance of its short-term investments ranged between $0.0 and $100.0 during fiscal 2016. The invested funds were the result of the issue and sale by the Company of 2,185,000 shares of the Company’s common stock in preparation for the EnergySouth acquisition. Due to lower yields available to Spire on short-term investments, the Company elected to provide a portion of Laclede Gas and Alagasco’s short-term funding through intercompany lending during the past fiscal year. Neither Laclede Gas nor Alagasco had any temporary cash investments during fiscal year 2016.

Bank deposits were used to support working capital needs of the business.

Short-term Debt

The Utilities’ short-term borrowings requirements typically peak during the colder months, while the Company’s needs are less seasonal. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. At September 30, 2016, Laclede Gas had a syndicated line of credit in place of $450.0 from ten banks. The largest portion provided by a single bank

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under the line is 15.6%. The Laclede Gas line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. As defined in the line of credit, total debt was 49.7% of total capitalization on September 30, 2016.

At September 30, 2016, Alagasco had a $150.0 syndicated line of credit with twelve banks. The largest portion provided by a single bank is 10%. The line of credit, which matures on September 2, 2019, has a covenant limiting total debt to 70% of Alagasco’s total capitalization. As defined in the line of credit, this ratio stood at 27.8% on September 30, 2016.

At September 30, 2016, Spire had a $150.0 syndicated line of credit from nine banks, with the largest portion provided by a single bank being 15.6%. The line of credit has a covenant limiting the total debt of the consolidated Spire to no more than 70% of the Company’s total capitalization. As defined in the line of credit, this ratio stood at 54.2% on September 30, 2016. Spire’s line may be used to provide for the funding needs of various subsidiaries.

Information about Spire’s consolidated short-term borrowings during the twelve months ended September 30, 2016 and 2015 and as of September 30, 2016 and 2015 is presented below:

	Laclede Gas Commercial Paper Borrowings	Spire* Bank Line Borrowings	Alagasco Bank Line Borrowings	Total Short-Term Borrowings
Year Ended September 30, 2016
Weighted average borrowings outstanding	$201.0	$42.7	$30.2	$273.9
Weighted average interest rate	0.7%	1.6%	1.4%	0.9%
Range of borrowings outstanding	$43.0 - $307.2	$0.0 - $82.0	$0.0 - $82.0	$73.1 - $427.2
As of September 30, 2016
Borrowings outstanding at end of period	$243.7	$73.0	$82.0	$398.7
Weighted average interest rate	0.8%	1.8%	1.5%	1.1%
Year Ended September 30, 2015
Weighted average borrowings outstanding	$212.7	$65.6	$22.3	$300.6
Weighted average interest rate	0.4%	1.4%	1.1%	0.7%
Range of borrowings outstanding	$ 102.1 - $341.0	$32.5 - $80.0	$0.0 - $69.5	$180.1 - $488.5
As of September 30, 2015
Borrowings outstanding at end of period	$233.0	$74.0	$31.0	$338.0
Weighted average interest rate	0.5%	1.5%	1.2%	0.8%

* Spire Inc., excluding its wholly owned subsidiaries.

Based on average short-term borrowings for the year ended September 30, 2016, an increase in the average interest rate of 100 basis points would decrease Spire’s pre-tax earnings and cash flows by approximately $2.7 on an annual basis, portions of which may be offset through the application of PGA carrying costs.

Long-term Debt and Equity

Spire

At September 30, 2016, including the current portion but excluding unamortized discounts and net hedging gains, Spire had fixed-rate long-term debt totaling $1,835.8 and floating rate debt totaling $250.0, of which $810.0 was issued by Laclede Gas and $250.0 was issued by Alagasco. With the exception of the $250.0 floating rate senior notes issued by Spire in August 2014, the long-term debt issues are fixed-rate and are subject to changes in their fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if the Company were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to the Utilities’ regulated operations, losses or gains on early redemptions of long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period. Of the Company’s $1,942.0 senior long-term debt, $25.0 has no call options, $937.0 has make-whole call options, $730.0 are callable at par one to six months prior to maturity and $250.0 are callable at par currently. The remainder of the Company’s long-term debt is $143.8 of junior subordinated notes associated with the equity units. None of the debt has any put options.

Spire has a shelf registration statement on Form S-3 on file with the SEC for the issuance and sale of up to 168,698 shares of its common stock under its Dividend Reinvestment and Direct Stock Purchase Plan. There were 106,535

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and 101,439 shares at September 30, 2016 and November 11, 2016, respectively, remaining available for issuance under its Form S-3. Spire also has a shelf registration statement on Form S-3 on file with the SEC for the issuance of equity and debt securities.

Consolidated capitalization at September 30, 2016 consisted of 49.1% of Spire common stock equity and 50.9% of long-term debt, compared to 47.0% of Spire common stock equity and 53.0% of long-term debt at September 30, 2015.

Laclede Gas

Of Laclede Gas’ $810.0 in long-term debt, $25.0 has no call option, $435.0 has make-whole call options, and $350.0 are callable at par one to six months prior to maturity. None of the debt has any put options.

Laclede Gas has authority from the MoPSC to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in capital, and enter into capital lease agreements, all for a total of up to $300.0. This authority became effective March 11, 2016, but is under appeal by Laclede Gas, as discussed under Regulatory and Other Matters above. During the year ended September 30, 2016, Laclede Gas issued no securities under this (or its prior) authorization, so that as of November 15, 2015, $300.0 remains available under the current authorization.

Laclede Gas filed a shelf registration on Form S-3 with the SEC on September 23, 2016, for issuance of first mortgage bonds, unsecured debt, and preferred stock, which expires on September 23, 2019. The amount, timing, and type of additional financing to be issued under this shelf registration will depend on cash requirements and market conditions, as well as future MoPSC authorizations.

Laclede Gas capitalization at September 30, 2016 consisted of 56.9% of common stock equity and 43.1% of long-term debt compared to 56.2% of common stock equity and 43.8% of long-term debt at September 30, 2015.

Alagasco

All of Alagasco’s $250.0 long-term debt has make-whole call options. None of the debt has any put options.

Alagasco has no standing authority to issue long-term debt and must petition the APSC for planned issuances. On February 3, 2015, Alagasco received authorization and approval from the APSC to borrow $80.0 for the purpose of refinancing $80.0 of existing debt scheduled to mature on December 1, 2015. Pursuant to this authorization and an earlier authorization for a $35.0 debt issuance, Alagasco entered into a master note purchase agreement on June 5, 2015 with certain institutional purchasers pursuant to which Alagasco committed to issue $115.0 unsecured notes in the private placement market: $35.0 at a rate of 3.21% for 10 years issued on September 15, 2015, and $80.0 at a rate of 4.31% for 30 years settling December 1, 2015. As of September 30, 2015, the current portion of long-term debt for Alagasco consisted of this $80.0 fixed-rate note maturing on December 1, 2015. Alagasco used the net proceeds of the private placements to refinance existing indebtedness and for general corporate purposes.

Alagasco’s capitalization at September 30, 2016 consisted of 77.6% of common stock equity and 22.4% of long-term debt compared to 83.7% of common stock equity and 16.3% of long-term debt at September 30, 2015.

The Company’s, Laclede Gas’ and Alagasco’s access to capital markets, including the commercial paper market, and their respective financing costs, may depend on the credit rating of the entity that is accessing the capital markets. The credit ratings of the Company, Laclede Gas and Alagasco remain at investment grade, but are subject to review and change by the rating agencies.

It is management’s view that the Company, Laclede Gas, and Alagasco have adequate access to capital markets and will have sufficient capital resources, both internal and external, to meet anticipated capital requirements, which primarily include capital expenditures, interest payments of long-term debt, scheduled maturities of long-term debt, short-term seasonal needs, and dividends.

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CONTRACTUAL OBLIGATIONS

As of September 30, 2016, Spire had contractual obligations with payments due as summarized below:

			Payments due by period
Contractual Obligations	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Principal Payments on Long-Term Debt	$	2,085.8	$	250.0	$	280.0	$	95.0	$	1,460.8
Interest Payments on Long-Term Debt (a)	1,068.3		79.7		142.7		125.6		720.3
Operating Leases (b)	90.9		10.5		14.7		12.3		53.4
Purchase Obligations – Natural Gas (c)	1,647.8		924.9		460.0		146.2		116.7
Purchase Obligations – Other (d)	112.2		66.9		36.1		8.8		0.4
Asset Retirement Obligations	206.4		5.2		8.9		12.5		179.8
Other Long-Term Liabilities	6.1		3.9		2.2		—		—
Total (e)	$	5,217.5	$	1,341.1	$	944.6	$	400.4	$	2,531.4

(a) Includes interest payments over the terms of the debt and payments on related stock purchase contracts. Interest is calculated using the applicable interest rate or forward interest rate curve at September 30, 2016 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 6, Long-Term Debt, of the Notes to Financial Statements. Does not reflect Spire’s ability to defer quarterly interest and contract adjustment payments related to its equity units, as discussed in Note 5, Stockholders’ Equity.

(b) Lease obligations are primarily for office space, vehicles, and power operated equipment. Additional payments will be incurred if renewal options are exercised under the provisions of certain agreements.

(c) These purchase obligations represent the minimum payments required under existing natural gas transportation and storage contracts and natural gas supply agreements in the Gas Utility and Gas Marketing segments. These amounts reflect fixed obligations as well as obligations to purchase natural gas at future market prices, calculated using September 30, 2016 forward market prices. Each of the Utilities generally recovers costs related to its purchases, transportation, and storage of natural gas through the operation of its PGA clause or GSA rider, subject to prudence review by the appropriate regional public service commission. Variations in the timing of collections of gas costs from customers may affect short-term cash requirements. Additional contractual commitments are generally entered into prior to or during the heating season.

(d) These purchase obligations primarily reflect miscellaneous agreements for the purchase of materials and the procurement of services necessary for normal operations.

(e) Long-term liabilities associated with unrecognized tax benefits, totaling $10.0, have been excluded from the table above because the timing of future cash outflows, if any, cannot be reasonably estimated. Also, commitments related to pension and postretirement benefit plans have been excluded from the table above. The Company expects to contribute $29.0 to its qualified, trusteed pension plans and $0.6 to its non-qualified pension plans during fiscal year 2017. With regard to the postretirement benefits, the Company anticipates it will contribute $10.3 to the qualified trusts and $0.4 directly to participants from Laclede Gas funds during fiscal year 2017. For further discussion of the Company’s pension and postretirement benefit plans, refer to Note 13, Pension Plans and Other Postretirement Benefits, of the Notes to Financial Statements.

MARKET RISK

Commodity Price Risk

Gas Utility

The Utilities’ commodity price risk, which arises from market fluctuations in the price of natural gas, is primarily managed through the operation of the Missouri Utilities’ PGA clauses and Alagasco’s GSA rider. The PGA clauses and GSA rider allows the Utilities to flow through to customers, subject to prudence review by the MoPSC and APSC, the cost of purchased gas supplies, as well as gas inventory carrying costs. Laclede Gas is allowed the flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months. Laclede Gas is able to mitigate, to some extent, changes in commodity prices through the use of physical storage supplies and regional supply diversity. The Utilities also have risk management policies that allow for the purchase of natural gas derivative instruments with the goal of managing its price risk associated with purchasing natural gas on behalf of its customers. These policies prohibit speculation. As of September 30, 2016, Laclede Gas had active natural gas derivative positions, but Alagasco did not. Costs and cost reduction, including carrying costs, associated with the use of natural gas derivative instruments are allowed to be passed on to customers through the operation of the PGA clauses or GSA rider.

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Accordingly, the Utilities do not expect any adverse earnings impact as a result of the use of these derivative instruments. However, the timing of recovery for cash payments related to margin requirements may cause short-term cash requirements to vary. For more information about the Utilities’ natural gas derivative instruments, see Note 10, Derivative Instruments and Hedging Activities, of the Notes to Financial Statements.

Gas Marketing

In the course of its business, Spire’s non-regulated gas marketing subsidiary, LER, enters into contracts to purchase and sell natural gas at fixed prices and natural gas index-based prices. Commodity price risk associated with these contracts has the potential to impact earnings and cash flows. To minimize this risk, LER has a risk management policy that provides for daily monitoring of a number of business measures, including fixed price commitments. In accordance with the risk management policy, LER manages the price risk associated with its fixed price commitments. This risk is currently managed either by closely matching the offsetting physical purchase or sale of natural gas at fixed-prices or through the use of natural gas futures, options, and swap contracts traded on or cleared through the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE) to lock in margins. At September 30, 2016 and 2015, LER’s unmatched fixed-price positions were not material to Spire’s financial position or results of operations.

As mentioned above, LER uses natural gas futures, options, and swap contracts traded on or cleared through the NYMEX and ICE to manage the commodity price risk associated with its fixed-price natural gas purchase and sale commitments. These derivative instruments may be designated as cash flow hedges of forecasted purchases or sales. Such accounting treatment, if elected, generally permits a substantial portion of the gain or loss to be deferred from recognition in earnings until the period that the associated forecasted purchase or sale is recognized in earnings. To the extent a hedge is effective, gains or losses on the derivatives will be offset by changes in the value of the hedged forecasted transactions. Information about the fair values of LER’s exchange-traded/cleared natural gas derivative instruments is presented below:

	Derivative Fair Values			Cash Margin			Derivatives and Cash Margin
Net balance of derivative assets at September 30, 2015	$	5.5		$	(1.6	)	$	3.9
Changes in fair value	1.4			—			1.4
Settlements/purchases - net	(8.2		)	—			(8.2		)
Changes in cash margin	—			5.7			5.7
Net balance of derivative assets at September 30, 2016	$	(1.3	)	$	4.1		$	2.8

	As of September 30, 2016
Maturity by Fiscal Year	Total			2017			2018			2019
Fair values of exchange-traded/cleared natural gas derivatives - net	$	(3.6	)	$	(3.4	)	$	(0.2	)	$	—
Fair values of basis swaps - net	2.3			1.9			0.3			0.1
Position volumes:
MMBtu – net (short) long futures/swap/option positions	(8.4		)	(7.6		)	(0.8		)	—
MMBtu - net (short) long basis swap positions	3.6			4.7			1.1			(2.2		)

Certain of LER’s physical natural gas derivative contracts are designated as normal purchases or normal sales, as permitted by GAAP. This election permits the Company to account for the contract in the period the natural gas is delivered. Contracts not designated as normal purchases or normal sales, including those designated as trading activities, are accounted for as derivatives with changes in fair value recognized in earnings in the periods prior to settlement.

Below is a reconciliation of the beginning and ending balances for physical natural gas contracts accounted for as derivatives, none of which will settle beyond fiscal year 2020:

Net balance of derivative assets at September 30, 2015	$	(0.5	)
Changes in fair value	12.2
Settlements	(5.4		)
Net balance of derivative assets at September 30, 2016	$	6.3

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For further details related to LER’s derivatives and hedging activities, see Note 10, Derivative Instruments and Hedging Activities, of the Notes to Financial Statements.

Counterparty Credit Risk

LER has concentrations of counterparty credit risk in that a significant portion of its transactions are with energy producers, utility companies, and pipelines. These concentrations of counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. LER also has concentrations of credit risk with certain individually significant counterparties. To the extent possible, LER enters into netting arrangements with its counterparties to mitigate exposure to credit risk. It is also exposed to credit risk associated with its derivative contracts designated as normal purchases and normal sales. LER closely monitors its credit exposure and, although uncollectible amounts have not been significant, increased counterparty defaults are possible and may result in financial losses and/or capital limitations. For more information on these concentrations of credit risk, including how LER manages these risks, see Note 11, Concentrations of Credit Risk, of the Notes to Financial Statements.

Interest Rate Risk

The Company is subject to interest rate risk associated with its long-term and short-term debt issuances. Based on average short-term borrowings during fiscal year 2016, an increase of 100 basis points in the underlying average interest rate for short-term debt would have caused an increase in interest expense of approximately $2.7 on an annual basis. Portions of such increases may be offset through the application of PGA carrying costs. At September 30, 2016, Spire had $250.0 of variable rate long-term debt due August 15, 2017. An increase of 100 basis points in the underlying average interest rate for the variable long-term note would have caused an increase in interest expense of approximately $2.5 on an annual basis. At September 30, 2016, Spire had fixed-rate long-term debt totaling $1,835.8, which includes $67.0 of fixed-rate long-term debt assumed through the acquisition of EnergySouth. Laclede Gas had fixed-rate long-term debt totaling $810.0 and Alagasco has fixed rate long-term debt of $250.0, which are both included with Spire total long-term debt. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if the Company were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to the Utilities’ regulated operations, losses or gains on early redemptions of long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period.

In 2014 the Company entered into and settled certain interest rate swap transactions to protect itself against adverse movements in interest rates associated with the issuance of long-term debt to fund the acquisition of Alagasco. In 2015, Alagasco entered into and settled interest swaps to protect itself against adverse movements in interest rates in anticipation of the issuance of $115.0 in debt. During the second quarter of fiscal 2016, Spire entered into five-year interest rate swap transactions with a fixed interest rate of 1.776% and a notional amount of $105.0 to protect itself against adverse movement in interest rates in anticipation of the issuance of long-term debt in 2017. During the third quarter of 2016, the Company entered into seven-year swap transactions with an average fixed interest rate of 1.501% and a notional amount of $120.0 to hedge against additional debt expected to be issued in 2017 or early 2018. Refer to Note 10, Derivative Instruments and Hedging Activities, of the Notes to Financial Statements for additional details on these interest rate swap transactions.

ENVIRONMENTAL MATTERS

The Utilities own and operate natural gas distribution, transmission, and storage facilities, the operations of which are subject to various environmental laws, regulations, and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company’s, Laclede Gas’, or Alagasco’s financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Utilities may be required to incur additional costs. For information relative to environmental matters, see Note 16, Commitments and Contingencies, of the Notes to Financial Statements.

OFF-BALANCE SHEET ARRANGEMENTS

At September 30, 2016, the Company had no off-balance sheet financing arrangements, other than operating leases and letters of credit entered into in the ordinary course of business. The Company does not expect to engage in any significant off-balance sheet financing arrangements in the near future.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

For this discussion, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk, on page 47 of this report.

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Item 8. Financial Statements and Supplementary Data
		Page
	Management Reports on Internal Control over Financial Reporting	52
	Reports of Independent Registered Public Accounting Firm	53
	Financial Statements:
	Spire Inc. (for years ended September 30, 2016, 2015, and 2014)
	Consolidated Statements of Income	57
	Consolidated Statements of Comprehensive Income	58
	Consolidated Balance Sheets	59
	Consolidated Statements of Capitalization	61
	Consolidated Statements of Common Shareholders’ Equity	62
	Consolidated Statements of Cash Flows	63
	Laclede Gas Company (for years ended September 30, 2016, 2015, and 2014)
	Statements of Income	64
	Statements of Comprehensive Income	65
	Balance Sheets	66
	Statements of Capitalization	68
	Statements of Common Shareholder's Equity	69
	Statements of Cash Flows	70
	Alabama Gas Corporation (for the years ended September 30, 2016, September 30, 2015, and the nine months ended September 30, 2014)
	Statements of Income	71
	Balance Sheets	72
	Statements of Capitalization	74
	Statements of Common Shareholder's Equity	75
	Statements of Cash Flows	76
	Notes to Financial Statements
	Note 1 Summary of Significant Accounting Policies	77
	Note 2 Acquisitions	85
	Note 3 Stock-Based Compensation	86
	Note 4 Earnings Per Common Share	89
	Note 5 Stockholders’ Equity	90
	Note 6 Long-Term Debt	92
	Note 7 Notes Payable and Credit Agreements	94
	Note 8 Fair Value of Financial Instruments	96
	Note 9 Fair Value Measurements	97
	Note 10 Derivative Instruments and Hedging Activities	100
	Note 11 Concentrations of Credit Risk	108
	Note 12 Income Taxes	109
	Note 13 Pension Plans and Other Postretirement Benefits	114
	Note 14 Information By Operating Segment	125
	Note 15 Regulatory Matters	127
	Note 16 Commitments and Contingencies	130
	Note 17 Interim Financial Information (Unaudited)	133

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Management Reports on Internal Control over Financial Reporting

Spire

Management is responsible for establishing and maintaining adequate internal controls over financial reporting. Spire Inc.’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Spire Inc.’s management, including our Chief Executive Officer and Chief Financial Officer, conducted an assessment of the effectiveness of Spire’s internal control over financial reporting as of September 30, 2016. In making this assessment, management used the criteria in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013). As permitted, that assessment excluded the business operations of EnergySouth, Inc., which was acquired on September 12, 2016, and whose net assets, total assets and revenues constitute 5.1 percent, 4.9 percent and 0.2 percent, respectively, of the consolidated financial statement amounts as of and for the year ended September 30, 2016. Refer to Note 2, Acquisitions, in the Notes to Financial Statements for further discussion of the acquisition. Based on that assessment, management concluded that Spire Inc.’s internal control over financial reporting was effective as of September 30, 2016. Deloitte & Touche LLP, an independent registered public accounting firm, has issued an attestation report on Spire Inc.’s internal control over financial reporting, which is included herein.

Laclede Gas Company

Management is responsible for establishing and maintaining adequate internal controls over financial reporting. Laclede Gas Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Laclede Gas Company’s management, including our Chief Executive Officer and Chief Financial Officer, conducted an assessment of the effectiveness of Laclede Gas Company’s internal control over financial reporting as of September 30, 2016. In making this assessment, management used the criteria in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013). Based on that assessment, management concluded that Laclede Gas Company’s internal control over financial reporting was effective as of September 30, 2016.

Alabama Gas Corporation

Management is responsible for establishing and maintaining adequate internal controls over financial reporting. Alabama Gas Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Alabama Gas Corporation’s management, including our Chief Executive Officer and Chief Financial Officer, conducted an assessment of the effectiveness of Alabama Gas Corporation’s internal control over financial reporting as of September 30, 2016. In making this assessment, management used the criteria in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013). Based on that assessment, management concluded that Alabama Gas Corporation’s internal control over financial reporting was effective as of September 30, 2016.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Spire Inc.

St. Louis, Missouri

We have audited the internal control over financial reporting of Spire Inc. (formerly The Laclede Group, Inc.) and subsidiaries (the "Company") as of September 30, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in the Spire section of Management Reports on Internal Control Over Financial Reporting, management excluded from its assessment the internal controls over financial reporting at EnergySouth, Inc., which was acquired on September 12, 2016, and whose net assets, total assets and revenues constitute 5.1 percent, 4.9 percent and 0.2 percent, respectively, of the consolidated financial statement amounts as of and for the year ended September 30, 2016. Accordingly, our audit did not include the internal control over financial reporting at EnergySouth, Inc. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Spire section of Management Reports on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended September 30, 2016of the Company and our report dated November 15, 2016 expressed an unqualified opinion on those consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

St. Louis, Missouri

November 15, 2016

53

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Spire Inc.

St. Louis, Missouri

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Spire Inc. (formerly The Laclede Group, Inc.) and subsidiaries (the "Company") as of September 30, 2016 and 2015, and the related consolidated statements of income, comprehensive income, common shareholders' equity, and cash flows for each of the three years in the period ended September 30, 2016. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Spire Inc. and subsidiaries as of September 30, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2016, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of September 30, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated November 15, 2016 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

St. Louis, Missouri

November 15, 2016

54

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Laclede Gas Company

St. Louis, Missouri

We have audited the accompanying balance sheets and statements of capitalization of Laclede Gas Company (a wholly owned subsidiary of Spire Inc. (formerly The Laclede Group, Inc.)) (the "Company") as of September 30, 2016 and 2015, and the related statements of income, comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended September 30, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Laclede Gas Company as of September 30, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

St. Louis, Missouri

November 15, 2016

55

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Alabama Gas Corporation

Birmingham, Alabama

We have audited the accompanying balance sheets and statements of capitalization of Alabama Gas Corporation (a wholly owned subsidiary of Spire Inc. (formerly The Laclede Group, Inc.)) (the "Company") as of September 30, 2016 and 2015, and the related statements of income, comprehensive income, common shareholder's equity, and cash flows for each of the two years in the period ended September 30, 2016 and the nine months ended September 30, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Alabama Gas Corporation as of September 30, 2016 and 2015, and the results of its operations and its cash flows for each of the two years in the period ended September 30, 2016 and the nine months ended September 30, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Birmingham, Alabama

November 15, 2016

56

SPIRE INC.
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
Years Ended September 30	2016		2015		2014
Operating Revenues:
Gas Utility	$	1,457.2	$	1,891.8	$	1,462.6
Gas Marketing and other	80.1		84.6		164.6
Total Operating Revenues	1,537.3		1,976.4		1,627.2
Operating Expenses:
Gas Utility
Natural and propane gas	492.2		882.4		731.7
Other operation and maintenance expenses	377.5		390.6		287.8
Depreciation and amortization	136.9		129.9		82.4
Taxes, other than income taxes	125.2		142.1		112.0
Total Gas Utility Operating Expenses	1,131.8		1,545.0		1,213.9
Gas Marketing and other	123.2		158.9		246.9
Total Operating Expenses	1,255.0		1,703.9		1,460.8
Operating Income	282.3		272.5		166.4
Other Income and (Income Deductions) – Net	8.6		1.2		(3.3		)
Interest Charges:
Interest on long-term debt	67.6		66.6		39.3
Other interest charges	9.6		8.0		6.9
Total Interest Charges	77.2		74.6		46.2
Income Before Income Taxes	213.7		199.1		116.9
Income Tax Expense	69.5		62.2		32.3
Net Income	$	144.2	$	136.9	$	84.6
Weighted Average Number of Common Shares Outstanding:
Basic	44.1		43.2		35.8
Diluted	44.3		43.3		35.9
Basic Earnings Per Share of Common Stock	$	3.26	$	3.16	$	2.36
Diluted Earnings Per Share of Common Stock	$	3.24	$	3.16	$	2.35

See the accompanying Notes to Financial Statements.

57

SPIRE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
Years Ended September 30	2016			2015			2014
Net Income	$	144.2		$	136.9		$	84.6
Other Comprehensive Income (Loss), Before Tax:
Cash flow hedging derivative instruments:
Net hedging loss arising during the period	(4.0		)	(5.5		)	(4.5		)
Reclassification adjustment for loss included in net income	1.1			4.4			2.5
Net unrealized loss on cash flow hedging derivative instruments	(2.9		)	(1.1		)	(2.0		)
Defined benefit pension and other postretirement benefit plans:
Net actuarial gain arising during the period	—			0.1			—
Amortization of actuarial (gain) loss included in net periodic pension and postretirement benefit cost	(0.3		)	0.4			0.5
Net defined benefit pension and other postretirement benefit plans	(0.3		)	0.5			0.5
Other Comprehensive Loss, Before Tax	(3.2		)	(0.6		)	(1.5		)
Income Tax Benefit Related to Items of Other Comprehensive Loss	(1.0		)	(0.3		)	(0.6		)
Other Comprehensive Loss, Net of Tax	(2.2		)	(0.3		)	(0.9		)
Comprehensive Income	$	142.0		$	136.6		$	83.7

See the accompanying Notes to Financial Statements.

58

SPIRE INC.
CONSOLIDATED BALANCE SHEETS
(In millions)
September 30	2016			2015
ASSETS
Utility Plant	$	4,793.6		$	4,234.5
Less: Accumulated depreciation and amortization	1,506.4			1,307.0
Net Utility Plant	3,287.2			2,927.5
Non-utility property (net of accumulated depreciation and amortization, $8.1 and $7.5 at September 30, 2016 and 2015, respectively)	13.7			13.7
Goodwill	1,164.9			946.0
Other investments	62.1			59.9
Other Property and Investments	1,240.7			1,019.6
Current Assets:
Cash and cash equivalents	5.2			13.8
Accounts receivable:
Utility	127.8			138.1
Other	113.4			86.7
Allowance for doubtful accounts	(20.5		)	(14.2		)
Delayed customer billings	1.6			2.6
Inventories:
Natural gas	174.0			188.6
Propane gas	12.0			12.0
Materials and supplies	16.3			14.8
Natural gas receivable	9.7			17.3
Derivative instrument assets	11.4			4.6
Unamortized purchased gas adjustments	49.7			12.9
Other regulatory assets	44.2			27.6
Prepayments and other	24.8			25.3
Total Current Assets	569.6			530.1
Deferred Charges:
Regulatory assets	838.0			737.6
Other	141.9			75.4
Total Deferred Charges	979.9			813.0
Total Assets	$	6,077.4		$	5,290.2

59

.

SPIRE INC.
CONSOLIDATED BALANCE SHEETS (Continued)
September 30	2016		2015
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity	$	1,768.2	$	1,573.6
Long-term debt	1,833.7		1,771.5
Total Capitalization	3,601.9		3,345.1
Current Liabilities:
Current portion of long-term debt	250.0		80.0
Notes payable	398.7		338.0
Accounts payable	210.9		146.5
Advance customer billings	70.2		44.3
Wages and compensation accrued	39.8		32.7
Dividends payable	23.5		21.1
Customer deposits	34.9		32.1
Interest accrued	14.8		14.3
Unamortized purchased gas adjustments	1.7		28.2
Taxes accrued	55.2		51.7
Other regulatory liabilities	28.9		32.4
Other	32.7		32.5
Total Current Liabilities	1,161.3		853.8
Deferred Credits and Other Liabilities:
Deferred income taxes	607.3		482.1
Pension and postretirement benefit costs	303.7		253.4
Asset retirement obligations	206.4		159.2
Regulatory liabilities	130.7		119.3
Other	66.1		77.3
Total Deferred Credits and Other Liabilities	1,314.2		1,091.3
Commitments and Contingencies (Note 16)
Total Capitalization and Liabilities	$	6,077.4	$	5,290.2

See the accompanying Notes to Financial Statements.

60

SPIRE INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in millions, except per share amounts)
September 30	2016			2015
Common Stock Equity:
Common stock, par value $1 per share:
Authorized – 70,000,000 shares
Outstanding – 45,650,642 shares and 43,335,012 shares, respectively	$	45.6		$	43.3
Paid-in capital	1,175.9			1,038.1
Retained earnings	550.9			494.2
Accumulated other comprehensive loss	(4.2		)	(2.0		)
Total Common Stock Equity	1,768.2			1,573.6
Long-Term Debt - Spire:
Floating Rate Senior Notes, due August 15, 2017	—			250.0
2.55% Senior Notes, due August 15, 2019	125.0			125.0
2.52% Senior Notes, due September 1, 2021	35.0			—
2.0% Series A Remarketable Subordinated Notes, due April 1, 2022	143.8			143.8
3.31% Notes Payable, due December 15, 2022	25.0			25.0
3.13% Senior Notes, due September 1, 2026	130.0			—
4.70% Senior Notes, due August 15, 2044	250.0			250.0
Long-Term Debt - Laclede Gas:
First Mortgage Bonds:
2.0% Series, due August 15, 2018	100.0			100.0
5.5% Series, due May 1, 2019	50.0			50.0
3.0% Series, due March 15, 2023	55.0			55.0
3.4% Series, due August 15, 2023	250.0			250.0
3.4% Series, due March 15, 2028	45.0			45.0
7.0% Series, due June 1, 2029	25.0			25.0
7.9% Series, due September 15, 2030	30.0			30.0
6.0% Series, due May 1, 2034	100.0			100.0
6.15% Series, due June 1, 2036	55.0			55.0
4.625% Series, due August 15, 2043	100.0			100.0
Long-Term Debt - Alagasco:
5.2% Notes, due January 15, 2020	40.0			40.0
3.86% Notes, due December 23, 2021	50.0			50.0
3.21% Notes, due September 15, 2025	35.0			35.0
5.9% Notes, due January 15, 2037	45.0			45.0
4.31% Notes, due December 1, 2045	80.0			—
Long-Term Debt - Other:
3.10%, due December 30, 2018	5.0			—
4.14%, due September 30, 2021	20.0			—
5.00%, due September 30, 2031	42.0			—
Total Principal of Long-Term Debt	1,835.8			1,773.8
Unamortized discounts on long-term debt	(2.1		)	(2.3		)
Total Long-Term Debt	1,833.7			1,771.5
Total Capitalization	$	3,601.9		$	3,345.1

Long-term debt dollar amounts are exclusive of current portion.

See the accompanying Notes to Financial Statements.

61

SPIRE INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
	Common Stock Outstanding			Paid-in Capital			Retained Earnings			AOCI*
(Dollars in millions, except per share amounts)	Shares	Amount											Total
Balance September 30, 2013	32,696,836	$	32.7	$	594.3		$	420.1		$	(0.8	)	$	1,046.3
Net income	—	—		—			84.6			—			84.6
Common stock offering	10,350,000	10.4		446.4			—			—			456.8
Equity units offering	—	—		(19.7		)	—			—			(19.7		)
Dividend reinvestment plan	33,667	—		1.5			—			—			1.5
Stock-based compensation costs	—	—		5.8			—			—			5.8
Equity Incentive Plan	97,902	0.1		1.6			—			—			1.7
Employees’ taxes paid associated with restricted shares withheld upon vesting	—	—		(1.1		)	—			—			(1.1		)
Tax benefit – stock compensation	—	—		0.6			—			—			0.6
Dividends declared:
Common stock ($1.76 per share)	—	—		—			(67.2		)	—			(67.2		)
Other comprehensive loss, net of tax	—	—		—			—			(0.9		)	(0.9		)
Balance September 30, 2014	43,178,405	$	43.2	$	1,029.4		$	437.5		$	(1.7	)	$	1,508.4
Net income	—	—		—			136.9			—			136.9
Dividend reinvestment plan	31,166	—		1.6			—			—			1.6
Stock-based compensation costs	—	—		3.0			—			—			3.0
Equity Incentive Plan	125,441	0.1		5.0			—			—			5.1
Employees’ taxes paid associated with restricted shares withheld upon vesting	—	—		(1.6		)	—			—			(1.6		)
Tax benefit – stock compensation	—	—		0.7			—			—			0.7
Dividends declared:
Common stock ($1.84 per share)	—	—		—			(80.2		)	—			(80.2		)
Other comprehensive loss, net of tax	—	—		—			—			(0.3		)	(0.3		)
Balance September 30, 2015	43,335,012	$	43.3	$	1,038.1		$	494.2		$	(2.0	)	$	1,573.6
Net income	—	—		—			144.2			—			144.2
Common stock offering	2,185,000	2.2		131.0			—			—			133.2
Dividend reinvestment plan	22,878	—		1.4			—			—			1.4
Stock-based compensation costs	—	—		2.2			—			—			2.2
Equity Incentive Plan	107,752	0.1		5.0			—			—			5.1
Employees’ taxes paid associated with restricted shares withheld upon vesting	—	—		(1.8		)	—			—			(1.8		)
Dividends declared:
Common stock ($1.96 per share)	—	—		—			(87.5		)	—			(87.5		)
Other comprehensive loss, net of tax	—	—		—			—			(2.2		)	(2.2		)
Balance September 30, 2016	45,650,642	$	45.6	$	1,175.9		$	550.9		$	(4.2	)	$	1,768.2

*Accumulated other comprehensive income (loss)

See the accompanying Notes to Financial Statements.

62

SPIRE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
Years Ended September 30	2016			2015			2014
Operating Activities:
Net Income	$	144.2		$	136.9		$	84.6
Adjustments to reconcile net income to net cash provided by    operating activities:
Depreciation, amortization and accretion	137.5			130.8			83.3
Deferred income taxes and investment tax credits	68.8			65.5			31.4
Changes in assets and liabilities:
Accounts receivable – net	(12.3		)	(4.8		)	(5.3		)
Unamortized purchased gas adjustments	(64.3		)	46.9			(36.4		)
Deferred purchased gas costs	11.5			(19.8		)	13.9
Accounts payable	30.0			(30.0		)	8.6
Delayed / advance customer billings – net	26.9			20.3			(19.1		)
Taxes accrued	(0.4		)	(17.0		)	(0.8		)
Inventories	16.5			54.8			(15.5		)
Other assets and liabilities	(35.0		)	(67.6		)	(27.5		)
Other	4.9			6.4			5.4
Net cash provided by operating activities	328.3			322.4			122.6
Investing Activities:
Capital expenditures	(293.3		)	(289.8		)	(171.0		)
Acquisition of EnergySouth (net of $2.0 cash acquired)	(317.7		)	—			—
Acquisition of Alagasco (net of $12.1 cash acquired in 2014)	—			(8.2		)	(1,305.2		)
Acquisition of MGE	—			—			23.9
Proceeds from sale of right to acquire New England Gas Company	—			—			11.0
Other	(1.7		)	(0.7		)	3.7
Net cash used in investing activities	(612.7		)	(298.7		)	(1,437.6		)
Financing Activities:
Issuance of long-term debt	245.0			35.0			768.8
Repayment of long-term debt	(80.0		)	(34.8		)	(80.0		)
Issuance of short-term debt - net	60.7			50.8			198.1
Issuance of common stock	137.1			3.1			460.0
Dividends paid	(85.2		)	(79.0		)	(61.9		)
Other	(1.8		)	(1.1		)	(6.9		)
Net cash provided by (used in) financing activities	275.8			(26.0		)	1,278.1
Net Decrease in Cash and Cash Equivalents	(8.6		)	(2.3		)	(36.9		)
Cash and Cash Equivalents at Beginning of Year	13.8			16.1			53.0
Cash and Cash Equivalents at End of Year	$	5.2		$	13.8		$	16.1
Supplemental disclosure of cash (paid) refunded for:
Interest	$	(72.5	)	$	(65.3	)	$	(40.6	)
Income taxes	2.9			1.3			(3.4		)

See the accompanying Notes to Financial Statements.

63

LACLEDE GAS COMPANY
STATEMENTS OF INCOME
(In millions)
Years Ended September 30	2016		2015			2014
Operating Revenues:
Utility	$	1,087.5	$	1,416.6		$	1,448.1
Other	—		—			0.1
Total Operating Revenues	1,087.5		1,416.6			1,448.2
Operating Expenses:
Utility
Natural and propane gas	471.3		786.1			816.9
Other operation and maintenance expenses	244.4		253.6			276.4
Depreciation and amortization	88.6		82.6			78.5
Taxes, other than income taxes	96.3		108.9			110.1
Total Utility Operating Expenses	900.6		1,231.2			1,281.9
Other	—		—			(0.1		)
Total Operating Expenses	900.6		1,231.2			1,281.8
Operating Income	186.9		185.4			166.4
Other Income and (Income Deductions) - Net	1.8		(0.5		)	(3.4		)
Interest Charges:
Interest on long-term debt	32.9		33.1			34.4
Other interest charges	4.5		3.3			3.0
Total Interest Charges	37.4		36.4			37.4
Income Before Income Taxes	151.3		148.5			125.6
Income Tax Expense	45.4		43.2			35.5
Net Income	$	105.9	$	105.3		$	90.1

See the accompanying Notes to Financial Statements.

64

LACLEDE GAS COMPANY
STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
Years Ended September 30	2016			2015			2014
Net Income	$	105.9		$	105.3		$	90.1
Other Comprehensive Income, Before Tax:
Cash flow hedging derivative instruments:
Net hedging (loss) gain arising during the period	—			(1.2		)	0.1
Reclassification adjustment for loss (gain) included in net income	0.5			0.9			(0.2		)
Net unrealized gain (loss) on cash flow hedging derivative instruments	0.5			(0.3		)	(0.1		)
Defined benefit pension and other postretirement benefit plans:
Net actuarial gain arising during the period	—			0.1			—
Amortization of actuarial (gain) loss included in net periodic pension and postretirement benefit cost	(0.3		)	0.4			0.4
Net defined benefit pension and other postretirement benefit plans	(0.3		)	0.5			0.4
Loss on available for sale securities	(0.1		)	—			—
Other Comprehensive Income, Before Tax	0.1			0.2			0.3
Income Tax Expense Related to Items of Other Comprehensive Income	0.2			—			0.1
Other Comprehensive (Loss) Income, Net of Tax	(0.1		)	0.2			0.2
Comprehensive Income	$	105.8		$	105.5		$	90.3

See the accompanying Notes to Financial Statements.

65

LACLEDE GAS COMPANY
BALANCE SHEETS
(In Millions)
September 30	2016			2015
ASSETS
Utility Plant	$	2,718.5		$	2,579.1
Less: Accumulated depreciation and amortization	604.5			590.0
Net Utility Plant	2,114.0			1,989.1
Goodwill	210.2			210.2
Other Property and Investments	57.3			55.3
Other Property and Investments	267.5			265.5
Current Assets:
Cash and cash equivalents	2.1			1.7
Accounts receivable:
Utility	87.9			103.4
Other	11.4			25.2
Allowance for doubtful accounts	(16.1		)	(10.0		)
Delayed customer billings	1.6			2.6
Receivables from associated companies	2.2			2.5
Inventories:
Natural gas	127.3			138.2
Propane gas	12.0			12.0
Materials and supplies	9.2			9.3
Derivative instrument assets	4.9			—
Unamortized purchased gas adjustments	43.1			12.9
Other regulatory assets	23.9			16.2
Prepayments and other	14.5			12.5
Total Current Assets	324.0			326.5
Deferred Charges:
Regulatory assets	589.8			573.6
Other	5.3			12.8
Total Deferred Charges	595.1			586.4
Total Assets	$	3,300.6		$	3,167.5

66

LACLEDE GAS COMPANY
BALANCE SHEETS (continued)
September 30	2016		2015
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity	$	1,068.5	$	1,037.8
Long-term debt	808.3		808.1
Total Capitalization	1,876.8		1,845.9
Current Liabilities:
Notes payable	243.7		233.0
Accounts payable	67.6		61.5
Accounts payable to associated companies	5.4		5.5
Advance customer billings	49.1		25.2
Wages and compensation accrued	29.9		26.8
Dividends payable	14.0		19.9
Customer deposits	13.5		13.0
Interest accrued	7.7		7.6
Taxes accrued	29.1		25.4
Regulatory liabilities	1.3		0.6
Other	9.9		18.5
Total Current Liabilities	471.2		437.0
Deferred Credits and Other Liabilities:
Deferred income taxes	556.9		485.2
Pension and postretirement benefit costs	211.8		207.8
Asset retirement obligations	75.2		72.4
Regulatory liabilities	67.3		70.6
Other	41.4		48.6
Total Deferred Credits and Other Liabilities	952.6		884.6
Commitments and Contingencies (Note 16)
Total Capitalization and Liabilities	$	3,300.6	$	3,167.5

See the accompanying Notes to Financial Statements.

67

LACLEDE GAS COMPANY
STATEMENTS OF CAPITALIZATION
(Dollars in millions, except per share amounts)
September 30	2016			2015
Common Stock Equity:
Common stock, par value $1 per share:
Authorized – 50,000,000 shares
Outstanding – 24,577 shares	0.1			0.1
Paid-in capital	751.9			748.2
Retained earnings	318.3			291.2
Accumulated other comprehensive loss	(1.8		)	(1.7		)
Total Common Stock Equity	1,068.5			1,037.8
Long-Term Debt:
First Mortgage Bonds:
2.0% Series, due August 15, 2018	100.0			100.0
5.5% Series, due May 1, 2019	50.0			50.0
3.0% Series, due March 15, 2023	55.0			55.0
3.4% Series, due August 15, 2023	250.0			250.0
3.4% Series, due March 15, 2028	45.0			45.0
7.0% Series, due June 1, 2029	25.0			25.0
7.9% Series, due September 15, 2030	30.0			30.0
6.0% Series, due May 1, 2034	100.0			100.0
6.15% Series, due June 1, 2036	55.0			55.0
4.625% Series, due August 15, 2043	100.0			100.0
Total Principal of Long-Term Debt	810.0			810.0
Unamortized discounts on long-term debt	(1.7		)	(1.9		)
Total Long-Term Debt	808.3			808.1
Total Capitalization	$	1,876.8		$	1,845.9

See the accompanying Notes to Financial Statements.

68

LACLEDE GAS COMPANY
STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
	Common Stock Outstanding			Paid-in Capital		Retained Earnings			AOCI*
(Dollars in millions, except per share amounts)	Shares	Amount										Total
Balance September 30, 2013	24,549	$	0.1	$	738.1	$	237.8		$	(2.1	)	$	973.9
Net income	—	—		—		90.1			—			90.1
Stock-based compensation costs	—	—		4.2		—			—			4.2
Tax benefit – stock compensation	—	—		0.6		—			—			0.6
Dividends declared on common stock	—	—		—		(62.3		)	—			(62.3		)
Issuance of common stock to Spire	28	—		1.1		—			—			1.1
Other comprehensive income, net of tax	—	—		—		—			0.2			0.2
Balance September 30, 2014	24,577	$	0.1	$	744.0	$	265.6		$	(1.9	)	$	1,007.8
Net income	—	—		—		105.3			—			105.3
Stock-based compensation costs	—	—		3.7		—			—			3.7
Tax benefit – stock compensation	—	—		0.5		—			—			0.5
Dividends declared on common stock	—	—		—		(79.7		)	—			(79.7		)
Other comprehensive income, net of tax	—	—		—		—			0.2			0.2
Balance September 30, 2015	24,577	$	0.1	$	748.2	$	291.2		$	(1.7	)	$	1,037.8
Net income	—	—		—		105.9			—			105.9
Stock-based compensation costs	—	—		3.7		—			—			3.7
Dividends declared on common stock	—	—		—		(78.8		)	—			(78.8		)
Other comprehensive loss, net of tax	—	—		—		—			(0.1		)	(0.1		)
Balance September 30, 2016	24,577	$	0.1	$	751.9	$	318.3		$	(1.8	)	$	1,068.5

*Accumulated other comprehensive income (loss)

See the accompanying Notes to Financial Statements.

69

LACLEDE GAS COMPANY
STATEMENTS OF CASH FLOWS
(In millions)
Years Ended September 30	2016			2015			2014
Operating Activities:
Net Income	$	105.9		$	105.3		$	90.1
Adjustments to reconcile net income to net cash provided by    operating activities:
Depreciation, amortization and accretion	88.6			82.6			78.5
Deferred income taxes and investment tax credits	45.3			45.4			35.6
Changes in assets and liabilities:
Accounts receivable – net	35.7			9.9			(21.5		)
Unamortized purchased gas adjustments	(30.2		)	41.1			(36.4		)
Deferred purchased gas costs	11.5			(19.8		)	13.9
Accounts payable	0.9			(11.4		)	6.8
Delayed / advance customer billings – net	24.9			17.9			(19.1		)
Taxes accrued	4.9			(14.6		)	10.0
Inventories	11.0			51.2			(26.4		)
Other assets and liabilities	(29.6		)	(32.8		)	(3.3		)
Other	2.3			2.8			2.8
Net cash provided by operating activities	271.2			277.6			131.0
Investing Activities:
Capital expenditures	(197.8		)	(198.6		)	(163.0		)
Acquisition of MGE	—			—			23.9
Other	1.1			2.9			4.1
Net cash used in investing activities	(196.7		)	(195.7		)	(135.0		)
Financing Activities:
Repayment of long-term debt	—			—			(80.0		)
Issuance (repayment) of short-term debt - net	10.7			(5.7		)	164.6
Borrowings from Spire	—			18.4			276.1
Repayment of borrowings from Spire	—			(18.4		)	(322.7		)
Dividends paid	(84.8		)	(78.7		)	(57.2		)
Issuance of common stock to Spire	—			—			1.2
Other	—			0.5			1.8
Net cash used in financing activities	(74.1		)	(83.9		)	(16.2		)
Net Increase (Decrease) in Cash and Cash Equivalents	0.4			(2.0		)	(20.2		)
Cash and Cash Equivalents at Beginning of Year	1.7			3.7			23.9
Cash and Cash Equivalents at End of Year	$	2.1		$	1.7		$	3.7
Supplemental disclosure of cash (paid) refunded for:
Interest	$	(35.7	)	$	(31.0	)	$	(36.4	)
Income taxes	2.1			0.7			(0.2		)

See the accompanying Notes to Financial Statements.

70

ALABAMA GAS CORPORATION
STATEMENTS OF INCOME
	Year Ended September 30,		Year Ended September 30,		Nine Months Ended September 30,
(In millions)	2016		2015		2014
Operating Revenues:
Utility	$	368.5	$	479.2	$	417.2
Total Operating Revenues	368.5		479.2		417.2
Operating Expenses:
Utility
Natural and propane gas	67.3		171.5		184.5
Other operation and maintenance expenses	133.5		138.0		107.5
Depreciation and amortization	47.8		47.3		34.4
Taxes, other than income taxes	28.4		33.2		28.6
Total Operating Expenses	277.0		390.0		355.0
Operating Income	91.5		89.2		62.2
Other Income - Net	7.9		2.0		2.2
Interest Charges:
Interest on long-term debt	11.4		11.6		10.1
Other interest charges	2.4		2.3		1.4
Total Interest Charges	13.8		13.9		11.5
Income Before Income Taxes	85.6		77.3		52.9
Income Tax Expense	32.4		29.3		19.9
Net Income	$	53.2	$	48.0	$	33.0

See the accompanying Notes to Financial Statements.

71

ALABAMA GAS CORPORATION
BALANCE SHEETS
(In millions)
September 30	2016			2015
ASSETS
Utility Plant	$	1,729.6		$	1,655.4
Less: Accumulated depreciation and amortization	756.6			717.0
Net Utility Plant	973.0			938.4
Current Assets:
Cash and cash equivalents	—			7.2
Accounts receivable:
Utility	34.0			34.7
Other	7.2			5.2
Allowance for doubtful accounts	(3.3		)	(4.2		)
Inventories:
Natural gas	34.6			40.4
Materials and supplies	5.9			5.4
Unamortized purchased gas adjustments	5.6			—
Other regulatory assets	14.9			11.4
Deferred income tax	—			6.2
Prepayments and other	5.1			4.6
Total Current Assets	104.0			110.9
Deferred Charges:
Regulatory assets	230.7			163.6
Deferred income tax	221.4			248.4
Other	63.2			57.7
Total Deferred Charges	515.3			469.7
Total Assets	$	1,592.3		$	1,519.0

72

ALABAMA GAS CORPORATION
BALANCE SHEETS (continued)
September 30	2016		2015
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity	$	867.3	$	874.6
Long-term debt	250.0		170.0
Total Capitalization	1,117.3		1,044.6
Current Liabilities:
Current portion of long-term debt	—		80.0
Notes payable	82.0		31.0
Accounts payable	34.3		21.8
Accounts payable to associated companies	0.4		0.2
Advance customer billings	21.1		19.1
Wages and compensation accrued	7.8		5.8
Customer deposits	18.2		19.1
Interest accrued	3.3		3.5
Unamortized purchase gas adjustment	—		28.2
Taxes accrued	21.6		26.0
Other regulatory liabilities	22.7		31.8
Other	6.3		5.4
Total Current Liabilities	217.7		271.9
Deferred Credits and Other Liabilities:
Pension and postretirement benefit costs	74.3		45.6
Asset retirement obligations	120.1		86.6
Regulatory liabilities	41.7		48.7
Other	21.2		21.6
Total Deferred Credits and Other Liabilities	257.3		202.5
Commitments and Contingencies (Note 16)
Total Capitalization and Liabilities	$	1,592.3	$	1,519.0

See the accompanying Notes to Financial Statements.

73

ALABAMA GAS CORPORATION
STATEMENTS OF CAPITALIZATION
(Dollars in millions, except per share amounts)
September 30	2016		2015
Common Stock Equity:
Common stock, par value $0.01 per share, and paid-in capital:
Authorized – 3,000,000 shares
Outstanding – 1,972,052 shares	$	451.9	$	480.9
Retained earnings	415.4		393.7
Total Common Stock Equity	867.3		874.6
Long-Term Debt:
5.2% Notes, due January 15, 2020	40.0		40.0
3.86% Notes, due December 23, 2021	50.0		50.0
3.21% Notes, due September 15, 2025	35.0		35.0
5.9% Notes, due January 15, 2037	45.0		45.0
4.31% Notes, due December 1, 2045	80.0		—
Total Long-Term Debt	250.0		170.0
Total Capitalization	$	1,117.3	$	1,044.6

Long-term debt dollar amounts are exclusive of current portion.

See the accompanying Notes to Financial Statements.

74

ALABAMA GAS CORPORATION
STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
	Common Stock Outstanding			Paid-in Capital			Retained Earnings
(Dollars in millions, except per share amounts)	Shares	Amount								Total
Balance December 31, 2013	1,972,052	$	—	$	34.5		$	350.1		$	384.6
Net income	—	—		—			33.0			33.0
Dividends declared on common stock	—	—		—			(37.4		)	(37.4		)
Purchase accounting adjustments	—	—		469.4			—			469.4
Balance September 30, 2014	1,972,052	—		503.9			345.7			849.6
Net income	—	—		—			48.0			48.0
Purchase accounting adjustments	—			4.0			—			4.0
Return of capital to Spire	—	—		(27.0		)	—			(27.0		)
Balance September 30, 2015	1,972,052	—		480.9			393.7			874.6
Net income	—	—		—			53.2			53.2
Dividends declared on common stock	—	—		—			(31.5		)	(31.5		)
Return of capital to Spire	—	—		(29.0		)	—			(29.0		)
Balance September 30, 2016	1,972,052	$	—	$	451.9		$	415.4		$	867.3

See the accompanying Notes to Financial Statements.

75

ALABAMA GAS CORPORATION
STATEMENTS OF CASH FLOWS
	Year Ended September 30,			Year Ended September 30,			Nine Months Ended September 30,
(In millions)	2016			2015			2014
Operating Activities:
Net Income	$	53.2		$	48.0		$	33.0
Adjustments to reconcile net income to net cash provided by    operating activities:
Depreciation, amortization and accretion	47.8			47.3			34.4
Deferred income taxes	33.2			29.2			4.0
Changes in assets and liabilities:
Accounts receivable – net	(11.1		)	(9.1		)	26.4
Unamortized purchased gas adjustments	(33.8		)	5.8			24.8
Accounts payable	9.1			(10.4		)	(11.5		)
Advance customer billings – net	2.0			2.4			(0.3		)
Taxes accrued	(5.2		)	(4.0		)	1.9
Inventories	5.3			7.2			(11.8		)
Other assets and liabilities	(3.2		)	(18.0		)	17.1
Other	0.9			2.0			(3.0		)
Net cash provided by operating activities	98.2			100.4			115.0
Investing Activities:
Capital expenditures	(93.4		)	(85.8		)	(46.2		)
Proceeds from the sale of assets	—			—			0.8
Other	(2.5		)	(1.0		)	—
Net cash used in investing activities	(95.9		)	(86.8		)	(45.4		)
Financing Activities:
Issuance of long-term debt	80.0			35.0			—
Repayment of long-term debt	(80.0		)	(34.8		)	—
Issuance (repayments) of short-term debt - net	51.0			15.0			(34.0		)
Return of capital to Spire	(29.0		)	(27.0		)	—
Dividends paid	(31.5		)	—			(37.4		)
Other	—			(0.2		)	4.4
Net cash used in financing activities	(9.5		)	(12.0		)	(67.0		)
Net (Decrease) Increase in Cash and Cash Equivalents	(7.2		)	1.6			2.6
Cash and Cash Equivalents at Beginning of Period	7.2			5.6			3.0
Cash and Cash Equivalents at End of Period	$	—		$	7.2		$	5.6
Supplemental disclosure of cash (paid) refunded for:
Interest	$	(12.4	)	$	(12.3	)	$	(9.6	)
Income taxes	0.8			—			(20.4		)

See the accompanying Notes to Financial Statements.

76

SPIRE INC., LACLEDE GAS COMPANY, AND ALABAMA GAS CORPORATION

NOTES TO FINANCIAL STATEMENTS

(Dollars in millions, except per share and per gallon amounts)

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION –These notes are an integral part of the accompanying audited financial statements of Spire Inc. (Spire or the Company), as well as Laclede Gas Company (Laclede Gas or the Missouri Utilities) and Alabama Gas Corporation (Alagasco). Laclede Gas, which includes the operations of Missouri Gas Energy (MGE), and Alagasco are wholly owned subsidiaries of the Company. Laclede Gas, Alagasco and the subsidiaries of EnergySouth, Inc. (EnergySouth) are collectively referred to as the Utilities. The subsidiaries of EnergySouth are Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas and Oil Company (Willmut Gas). The accompanying audited financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

The consolidated financial position, results of operations, and cash flows of Spire are primarily derived from the financial position, results of operations, and cash flows of the Utilities. In compliance with GAAP, transactions between Laclede Gas and Alagasco and their affiliates, as well as intercompany balances on their balance sheets, have not been eliminated from their separate financial statements. The Company’s September 12, 2016 acquisition of EnergySouth and the August 31, 2014 acquisition of Alagasco are included in the results of operations since their acquisition dates and impact the comparability of the financial statement periods presented for the Company. For a further discussion of the acquisitions, see Note 2, Acquisitions. The Utilities are regulated natural gas distribution utilities. Due to the seasonal nature of the Utilities, the earnings of Spire, Laclede Gas and Alagasco are typically concentrated during the heating season of November through April each fiscal year.

Effective September 2, 2014, Alagasco amended its bylaws to change Alagasco’s fiscal year from beginning January 1 and ending on December 31, to beginning October 1 and ending September 30. As a result, the financial statements covering the nine-month period from January 1, 2014 through September 30, 2014 (the “transition period”) were included in Alagasco’s transition report on Form 10-K/T for such period and are presented in the financial statements and notes herein.

NATURE OF OPERATIONS – Spire Inc. (NYSE: SR), headquartered in St. Louis, Missouri, is a public utility holding company. The Company has two reportable segments: Gas Utility and Gas Marketing. The Gas Utility segment consists of the regulated natural gas distribution operations of the Company and is the core business segment of Spire in terms of revenue and earnings generation. The Gas Utility segment is comprised of the operations of the Missouri Utilities, serving St. Louis and eastern Missouri, Kansas City and western Missouri (through MGE), Alagasco serving central and northern Alabama, and the subsidiaries of EnergySouth, serving southern Alabama and south-central Mississippi. Spire’s primary non-utility business, Laclede Energy Resources, Inc. (LER), included in the Gas Marketing segment, provides non-regulated natural gas services. The activities of other subsidiaries are described in Note 14, Information by Operating Segment, and are reported as Other. Laclede Gas and Alagasco each have a single reportable segment.

USE OF ESTIMATES – The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

SYSTEM OF ACCOUNTS – The accounts of the Utilities are maintained in accordance with the Uniform System of Accounts prescribed by the applicable state public service commissions, which systems substantially conform to that prescribed by the Federal Energy Regulatory Commission (FERC).

UTILITY PLANT, DEPRECIATION AND AMORTIZATION – Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overheads, and an allowance for funds used during construction. The costs of units of property retired, replaced, or renewed are removed from utility plant and are charged to accumulated depreciation. Maintenance and repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expenses.

77

For Laclede Gas, utility plant is depreciated on a straight-line basis at rates based on estimated service lives of the various classes of property. In fiscal years 2016, 2015 and 2014, annual depreciation and amortization expense averaged 3.0% of the original cost of depreciable and amortizable property.

Laclede Gas’ capital expenditures were $197.8, $198.6 and $163.0 for fiscal years 2016, 2015, and 2014, respectively. Additionally, Laclede Gas had recorded accruals for capital expenditures totaling $14.8 at September 30, 2016, $9.6 at September 30, 2015, and $3.0 at September 30, 2014.

For Alagasco, depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of utility property at rates approved by the Alabama Public Service Commission (APSC). On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1%. As required by the APSC, Alagasco performed another depreciation study in 2015. The composite depreciation rate from this study was also approximately 3.1%. Alagasco anticipates refunding approximately $9.3 of refundable negative salvage costs through lower tariff rates over the next twelve months.

Related to the lower depreciation rates, an estimated $18.7 of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a three year period through 2019. 

Alagasco’s capital expenditures were $93.4, $85.8 and $46.2 for fiscal years 2016, 2015, and 2014, respectively. Additionally, Alagasco recorded accruals for capital expenditures totaling $6.8 at September 30, 2016, $3.1 at September 30, 2015 and $5.0 at September 30, 2014.

Accrued capital expenditures are excluded from the capital expenditures included in the statements of cash flows of the Company, Laclede Gas and Alagasco.

ASSET RETIREMENT OBLIGATIONS – Spire, Laclede Gas, and Alagasco record legal obligations associated with the retirement of long-lived assets in the period in which the obligations are incurred, if sufficient information exists to reasonably estimate the fair value of the obligations. Obligations are recorded as both a cost of the related long-lived asset and as a corresponding liability. Subsequently, the asset retirement costs are depreciated over the life of the asset and the asset retirement obligations are accreted to the expected settlement amounts. The Company, Laclede Gas and Alagasco record asset retirement obligations associated with certain safety requirements to purge and seal gas distribution mains upon retirement, the plugging and abandonment of storage wells and other storage facilities, specific service line obligations, and certain removal and disposal obligations related to components of Laclede Gas’, Alagasco’s and Mobile Gas’ distribution systems and general plant. Asset retirement obligations recorded by Spire’s other subsidiaries are not material. As authorized by the Missouri Public Service Commission (MoPSC) and APSC, Laclede Gas, Alagasco and Mobile Gas accrue future asset removal costs associated with their property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities or assets. When those utilities retire depreciable utility plant and equipment, they charge the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities or assets. The difference between removal costs recognized in depreciation rates and the accretion expense and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes. Accordingly, these differences are deferred as regulatory liabilities or assets. In the rate setting process, the regulatory liability or asset is excluded from the rate base upon which those utilities have the opportunity to earn their allowed rates of return. The costs associated with asset retirement obligations of Laclede Gas, Alagasco and Mobile Gas are either currently being recovered in rates or are probable of recovery in future rates.

78

The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30, as reported in the balance sheets.

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Asset retirement obligations, beginning of year	$	159.2		$	99.2		$	72.4		$	71.2		$	86.6		$	27.7
Liabilities incurred during the period	4.1			2.3			1.2			0.6			2.9			1.7
Liabilities settled during the period	(9.5		)	(2.0		)	(1.9		)	(1.9		)	(6.8		)	(0.1		)
Accretion	13.2			4.5			3.5			3.4			9.7			1.1
Revisions in estimated cash flows	27.5			55.2			—			(0.9		)	27.7			56.2
Addition of EnergySouth asset retirement obligations	11.9			—			—			—			—			—
Asset retirement obligations, end of year	$	206.4		$	159.2		$	75.2		$	72.4		$	120.1		$	86.6

REGULATED OPERATIONS – The Utilities account for their regulated operations in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.” This Topic sets forth the application of GAAP for those companies whose rates are established by or are subject to approval by an independent third-party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. In addition, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities). Management believes that the current regulatory environment supports the continued use of these regulatory accounting principles and that all regulatory assets and regulatory liabilities are recoverable or refundable through the regulatory process. See additional discussion on regulated operations in Note 15, Regulatory Matters.

As discussed below for Laclede Gas and Alagasco, the Purchased Gas Adjustment (PGA) clauses and Gas Supply Adjustment (GSA) riders allow the Utilities to pass through to customers the cost of purchased gas supplies. Regulatory assets and liabilities related to the PGA clauses and the GSA rider are both labeled Unamortized Purchased Gas Adjustments herein.

Laclede Gas

As authorized by the MoPSC, the PGA clause allows Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. To better match customer billings with market natural gas prices, Laclede Gas is allowed to file to modify, on a periodic basis, the level of gas costs in its PGA. Certain provisions of the PGA clause are included below:

• Laclede Gas has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. The MoPSC clarified that costs, cost reductions, and carrying costs associated with the Utility’s use of natural gas derivative instruments are gas costs recoverable through the PGA mechanism.

• The tariffs allow Laclede Gas flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months.

• Laclede Gas is authorized to apply carrying costs to all over- or under-recoveries of gas costs, including costs and cost reductions associated with the use of derivative instruments, including cash payments for margin deposits. Laclede Gas’ eastern Missouri service territory is also authorized to recover gas inventory carrying costs through its PGA rates to recover costs it incurs to finance its investment in gas supplies that are purchased during the storage injection season for sale during the heating season.

• The MoPSC approved a plan applicable to Laclede Gas’ gas supply commodity costs under which it retains a portion of cost savings associated with the acquisition of natural gas below an established benchmark level. This gas supply cost management program allows Laclede Gas to retain 10% of cost savings, up to a maximum of $3.0 annually. Laclede Gas did not record any income under the plan during the three fiscal years reported. Income recorded under the plan, if any, is included in Gas Utility Operating Revenues on the Consolidated Statements of Income and under Operating Revenues on Laclede Gas’ Statements of Income.

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Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA clause are reflected as a deferred charge or credit at the end of the fiscal year. These costs include costs and cost reductions associated with the use of derivative instruments and gas inventory carrying costs, amounts due to or from customers related to operation of the gas supply cost management program, refunds received from the Company’s suppliers in connection with gas supply, transportation, and storage services, and carrying costs on such over- or under-recoveries. At that time, the balance is classified as a current asset or current liability and recovered from, or credited to, customers over an annual period commencing in November. The balance in the current account is amortized as amounts are reflected in customer billings.

The PGA clause also provides for the treatment of income from off-system sales and capacity release revenues. Pre-tax income from off-system sales and capacity release revenues is shared with customers, with an estimated amount assumed in PGA rates. The difference between the actual amount allocated to customers for each fiscal year and the estimated amount assumed in PGA rates is recovered from, or credited to, customers over an annual period commencing in the subsequent November. The customer share of such income is determined in accordance with the following tables, shown for each service territory for which the PGA clauses were approved by the MoPSC.

	Customer Share	Company Share
Eastern Missouri
First $2.0*	100%	—%
Next $2.0	80%	20%
Next $2.0	75%	25%
Amounts exceeding $6.0	70%	30%
* Customer share reverts to 85% and company share reverts to 15% in 2017.
Western Missouri
First $1.2	85%	15%
Next $1.2	80%	20%
Next $1.2	75%	25%
Amounts exceeding $3.6	70%	30%

Alagasco

Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA rider, which is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather-related conditions that may affect customer usage are not included in the temperature adjustment.

NATURAL GAS AND PROPANE GAS – For Laclede Gas’ eastern Missouri utility, inventory of natural gas in storage is priced on a last in, first out (LIFO) basis and inventory of propane gas in storage is priced on a first in, first out (FIFO) basis. For the rest of the Gas Utility segment, inventory of natural gas in storage is priced on the weighted average cost basis. The replacement cost of Laclede Gas’ natural gas for current use in eastern Missouri at September 30, 2016 and September 30, 2015 was less than the LIFO cost by $11.4 and $20.4, respectively. The carrying value of Laclede Gas’ inventory is not adjusted to the lower of cost or market prices because, pursuant to the Missouri Utilities’ PGA clauses, actual gas costs are recovered in customer rates. Natural gas and propane gas storage inventory in Spire’s other operating segments is recorded at the lower of average cost or market.

BUSINESS COMBINATIONS – The EnergySouth and Alagasco acquisitions are accounted for by Spire using business combination accounting. Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value. For additional information on the acquisition of EnergySouth and Alagasco, refer to Note 2, Acquisitions.

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GOODWILL – Goodwill is measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Spire and Laclede Gas evaluate goodwill for impairment as of July 1st of each year, or more frequently if events and circumstances indicate that goodwill might be impaired. At July 1, 2016, 2015 and 2014, Spire and Laclede Gas each applied a quantitative goodwill evaluation model to their reporting units and concluded goodwill was not impaired because the fair value exceeded the carrying amount. The changes in the carrying amount of goodwill by reportable segment were as follows:

	Gas Utility			Gas Marketing		Other		Total
Balance as of September 30, 2013	$	247.1		$	—	$	—	$	247.1
Adjustments to finalize the 2013 acquisition of MGE	(36.9		)	—		—		(36.9		)
Acquisition of Alagasco	—			—		727.6		727.6
Balance as of September 30, 2014	210.2			—		727.6		937.8
Adjustments to finalize the acquisition of Alagasco	—			—		8.2		8.2
Balance as of September 30, 2015	210.2			—		735.8		946.0
Acquisition of EnergySouth	—			—		218.9		218.9
Balance as of September 30, 2016	$	210.2		$	—	$	954.7	$	1,164.9

IMPAIRMENT OF LONG-LIVED ASSETS – Long-lived assets classified as held and used are evaluated for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, the Company recognizes an impairment charge equal to the amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which the Company determines an asset meets held-for-sale criteria, an impairment charge is recorded to the extent the book value exceeds its fair value less cost to sell.

REVENUE RECOGNITION – The Utilities read meters and bill customers on monthly cycles. The Missouri Utilities record their gas utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues for Laclede Gas at September 30, 2016 and 2015 were $26.1 and $27.6, respectively.

Alagasco records natural gas distribution revenues in accordance with the tariff established by the APSC. The amount of accrued unbilled revenues, which are not recorded as revenues until billed, for Alagasco at September 30, 2016 and 2015 were $5.9 and $6.4, respectively. All related costs and margins are also deferred.

The subsidiaries of EnergySouth record natural gas revenues in accordance with tariffs established by the APSC and MSPSC. Unbilled revenues are accrued and related costs and margins are also deferred.

Spire’s other subsidiaries, including LER, record revenues when earned, either when the product is delivered or when services are performed.

In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. Certain of its derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815, “Derivatives and Hedging.” Those contracts are accounted for as executory contracts and recorded on an accrual basis. Revenues and expenses from such contracts are recorded using a gross presentation. Contracts not designated as normal purchases or normal sales are recorded as derivatives with changes in fair value recognized in earnings in the periods prior to physical delivery. For additional information on derivative instruments, refer to Note 10, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions are classified as trading activities for financial reporting purposes. Under GAAP, revenues and expenses associated with trading activities are presented on a net basis in Gas Marketing operating revenues (or expenses, if negative) in the Consolidated Statements of Income. This net presentation has no effect on operating income or net income.

INCOME TAXES – Spire and its subsidiaries account for income taxes under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and the respective tax basis and for tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to

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taxable income in the years in which those temporary differences are expected to be recovered or settled. The effects on deferred tax assets and liabilities of a change in enacted tax rates is recognized in income or loss for a non-regulated company, and in a regulatory asset or regulatory liability for a regulated company. A valuation allowance is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized.

The Company accounts for uncertain tax positions in accordance with authoritative guidance. The authoritative guidance addresses the determination of whether tax benefits claimed, or expected to be claimed, on a tax return should be recorded in the financial statements. Spire may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the position will be sustained upon examination by the taxing authority, based on the technical merits of the position. Tax-related interest and penalties, if any, are classified as a liability on the balance sheets.

CASH AND CASH EQUIVALENTS – All highly liquid debt instruments purchased with original maturities of three months or less are considered to be cash equivalents. Such instruments are carried at cost, which approximates market value. Outstanding checks on the Company’s and Utilities’ bank accounts in excess of funds on deposit create book overdrafts (which are funded at the time checks are presented for payment) and are classified as Other in the Current Liabilities section of the balance sheets. Changes in book overdrafts are reflected as Operating Activities in the statements of cash flows.

NATURAL GAS RECEIVABLE – LER enters into natural gas transactions with natural gas pipeline companies known as park and loan arrangements. Under the terms of the arrangements, LER purchases natural gas from a third party and delivers that natural gas to the pipeline company for the right to receive the same quantity of natural gas from the pipeline company at the same location in a future period. These arrangements are accounted for as non-monetary transactions under GAAP and are recorded at the carrying amount. As such, natural gas receivables are reflected on the Consolidated Balance Sheets at cost, which includes related pipeline fees associated with the transactions. In the period that the natural gas is returned to LER, concurrent with the sale of the natural gas to a third party, the related natural gas receivable is expensed in the Consolidated Statements of Income. In conjunction with these transactions, LER usually enters into New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE) natural gas futures, options, and swap contracts or fixed price sales agreements to protect against market changes in future sales prices.

EARNINGS PER COMMON SHARE – GAAP requires dual presentation of basic and diluted earnings per share (EPS). EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareholders. Certain of the Company’s stock-based compensation awards pay non-forfeitable dividends to the participants during the vesting period and, as such, are deemed participating securities. Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding that are increased for additional shares that would be outstanding if potentially dilutive non-participating securities were converted to common shares, pursuant to the treasury stock method. Shares attributable to equity units, non-participating stock options and time-vested restricted stock/units are excluded from the calculation of diluted earnings per share if the effect would be antidilutive. Shares attributable to non-participating performance-contingent restricted stock awards are only included in the calculation of diluted earnings per share to the extent the underlying performance and/or market conditions are satisfied (a) prior to the end of the reporting period or (b) would be satisfied if the end of the reporting period were the end of the related contingency period and the result would be dilutive. The Company’s EPS computations are presented in Note 4, Earnings Per Common Share.

GROSS RECEIPTS AND SALES TAXES – Gross receipts taxes associated with the Company’s natural gas utility services are imposed on the Company, Laclede Gas, and Alagasco and billed to its customers. The revenue and expense amounts are recorded gross in the “Operating Revenues” and “Taxes, other than income taxes” lines, respectively, in the statements of income.

The following table presents gross receipts taxes recorded:

	2016		2015		2014
Spire	$	75.5	$	97.3	$	77.5
Laclede Gas	57.4		74.5		76.3
Alagasco	17.9		22.6		20.6

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Sales taxes imposed on applicable Alagasco and Laclede Gas sales are billed to customers. These amounts are not recorded in the statements of income but are recorded as tax collections payable and included in the Other line of the Current Liabilities section of the balance sheets.

TRANSACTIONS WITH AFFILIATES –Transactions between affiliates of the Company have been eliminated from the consolidated financial statements of Spire. Other than borrowings from Spire reflected in Alagasco’s Balance Sheets and Statements of Cash Flows and normal intercompany shared services transactions, there were no transactions between Alagasco and affiliates. Laclede Gas had the following transactions with affiliates:

	2016		2015		2014
Purchases of natural gas from LER	$	46.3	$	74.1	$	89.1
Sales of natural gas to LER	1.9		4.0		5.1
Services received from Laclede Insurance Risk Services, Inc.	1.8		1.0		0.6

ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS – Trade accounts receivable are recorded at the amounts due from customers, including unbilled amounts. Estimates of the collectability of trade accounts receivable are based on historical trends, age of receivables, economic conditions, credit risk of specific customers, and other factors. Accounts receivable are written off against the allowance for doubtful accounts when they are deemed to be uncollectible. Spire’s provision for uncollectible accounts includes the amortization of previously deferred uncollectible expenses for Laclede Gas and Alagasco, as approved by the MoPSC and the APSC.

FINANCE RECEIVABLES – Alagasco finances third party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2016 and September 30, 2015, the Company’s finance receivable totaled approximately $11.8 and $11.2, respectively. Financing is available only to qualified customers who meet creditworthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third party collection agency. Alagasco had finance receivables past due 90 days or more of $0.4 at September 30, 2016 and September 30, 2015. Alagasco recorded an allowance for credit losses at September 30, 2016 and September 30, 2015 of $0.4.

GROUP MEDICAL AND WORKERS’ COMPENSATION RESERVES – The Company self-insures its group medical and workers’ compensation costs and carries stop-loss coverage in relation to medical claims and workers’ compensation claims. Reserves for amounts incurred but not reported are established based on historical cost levels and lags between occurrences and reporting.

FAIR VALUE MEASUREMENTS – Certain assets and liabilities are recognized or disclosed at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.

The levels of the hierarchy are described below:

• Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities.

• Level 2 – Pricing inputs other than quoted prices included within Level 1, which are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data.

• Level 3 – Pricing that is based upon inputs that are generally unobservable that are based on the best information available and reflect management’s assumptions about how market participants would price the asset or liability.

Assessment of the significance of a particular input to the fair value measurements may require judgment and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. Additional information about fair value measurements is provided in Note 8, Fair Value of Financial Instruments, Note 9, Fair Value Measurements, and Note 13, Pension Plans and Other Postretirement Benefits.

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STOCK-BASED COMPENSATION – The Company measures stock-based compensation awards at fair value at the date of grant and recognizes the compensation cost of the awards over the requisite service period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. Refer to Note 3, Stock-Based Compensation, for further discussion of the accounting for the Company’s stock-based compensation plans.

REVISIONS TO PRIOR FINANCIAL STATEMENTS - Certain amounts in the prior period have been adjusted to conform with the current period presentation for Spire and Laclede Gas. The adjustment was related to the presentation of categories of deferred tax assets in Note 12, Income Taxes.

NEW ACCOUNTING PRONOUNCEMENTS – In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers. The core principle of the standard is when an entity transfers goods or services to customers it will recognize revenue in an amount that reflects the consideration the entity expects to be entitled to for those goods or services. ASU No. 2014-09 also requires disclosures that will enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which made the guidance in ASU No. 2014-09 effective for fiscal years beginning after December 15, 2017 and interim periods within those years, but companies may choose to adopt it one year earlier. In 2016, the FASB issued related ASU Nos. 2016-08, 2016-10, 2016-11 and 2016-12, which further modified the standards for accounting for revenue. The Company, Laclede Gas and Alagasco are currently assessing the available transition methods and the potential impacts of the updates, which must be adopted by the first quarter of fiscal year 2019.

In April 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. Currently, debt issuance costs are recorded as a deferred charge (asset), while debt discount and debt premium costs are recorded as a liability adjustment. This amendment will require debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU No. 2015-15 clarified that ASU No. 2015-03 does not address the presentation of debt issuance costs related to line-of-credit arrangements, and the Company intends to continue to report such costs as deferred charges. The new guidance is effective for the Company, Laclede Gas and Alagasco beginning in the first quarter of fiscal 2017. The application of this standard will be retrospective, wherein each balance sheet presented will be adjusted to reflect the impacts of applying the new guidance. If this ASU had been adopted as of September 30, 2016, the amounts reclassified from other deferred charges to reduce long-term debt at September 30, 2016 and 2015, respectively, would have been $13.2 and $13.0 for Spire, $4.2 and $4.8 for Laclede Gas, and $2.6 and $2.4 for Alagasco.

In November 2015, the FASB issued ASU No. 2015-17, Income Taxes: Balance Sheet classification of Deferred Taxes, to require that deferred tax liabilities and assets be classified entirely as noncurrent. This was part of the FASB’s simplification initiative intended to reduce cost and complexity in financial reporting while improving or maintaining the usefulness of the information reported to investors. The Company, Laclede Gas and Alagasco adopted this ASU in the fourth quarter of fiscal 2016. Prior periods were not retrospectively adjusted. The adoption of this accounting standard was not material to the financial statements.

In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall: Recognition and Measurement of Financial Assets and Financial Liabilities, which provides revised guidance concerning certain matters involving the recognition, measurement, and disclosure of financial instruments. It is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Company, Laclede Gas and Alagasco are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of fiscal year 2019.

In February 2016, the FASB issued ASU No. 2016-02, Leases. The new standard requires lessees to recognize a right-of-use asset and lease liability for almost all lease contracts based on the present value of lease payments. There is an exemption for short-term leases. The ASU provides new guidelines for identifying and classifying a lease, and classification affects the pattern and income statement line item for the related expense. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company, Laclede Gas and Alagasco are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of fiscal year 2020.

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The standard is intended to simplify several areas of accounting for share-based compensation arrangements, including the income tax impact, classification on the statement of cash flows and forfeitures. The ASU is effective for fiscal years beginning after December 15, 2016, including interim

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periods within those fiscal years. The Company, Laclede Gas and Alagasco are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of fiscal year 2018.

On June 16, 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments. The standard introduces new guidance for the accounting for credit losses on instruments within its scope, including trade receivables. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, but may be adopted up to two years earlier. The Company, Laclede Gas and Alagasco are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of fiscal year 2021.

2.     ACQUISITIONS

Spire’s recent acquisitions are described below. The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed at the acquisition dates. Measurement period adjustments were immaterial.

	Alagasco			EnergySouth
Recognized amounts of identifiable assets acquired and liabilities assumed:
Utility plant	$	892.7		$	199.5
Cash	12.1			2.0
Other current assets	99.4			17.5
Deferred tax assets	282.0			—
Other assets	143.4			79.8
Long-term debt	(249.8		)	(67.0		)
Current portion of long-term debt	(15.0		)	—
Other current liabilities	(173.4		)	(42.7		)
Deferred tax liabilities	—			(35.5		)
Other liabilities	(130.4		)	(52.8		)
Total identifiable net assets	861.0			100.8
Goodwill	735.8			218.9
Deferred tax elimination (Spire)	(271.3		)	—
Consideration (cash)	$	1,325.5		$	319.7

Acquisition of Alagasco

Spire completed the acquisition of 100% of the common stock of Alagasco from Energen effective on August 31, 2014. Total cash consideration paid at closing, net of cash acquired and debt assumed was $1,305.2. Subsequently, the Company and Energen agreed to a final reconciliation of net assets, and $8.2 was paid by the Company to Energen on January 6, 2015, effectively increasing the total net consideration to $1,313.4.

The goodwill of $735.8 arising from this acquisition, $717.6 of which is expected to be deductible for tax purposes, is attributable to Alagasco’s assembled workforce and the expected cost efficiencies and strategic benefits of the transaction. The acquisition was supportive of the strategic focus on growing the Company’s regulated footprint and created geographic and regulatory diversity. The Company determined that the Alagasco acquisition met the scope exceptions for pushdown accounting; therefore, the goodwill was recorded on the Spire parent company balance sheet rather than the Alagasco subsidiary balance sheet and included in disclosures of segment assets under Other rather than the Gas Utility segment.

The Company and Energen made an election under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended, to treat the Alagasco acquisition as a deemed purchase and sale of assets for tax purposes. As a result of the election, goodwill was generated for tax purposes at Alagasco. For book purposes, as noted above, goodwill was recorded on the Spire parent entity and not pushed down to Alagasco. Consequently, a deferred tax asset (DTA) was recorded at Alagasco related to the excess of tax deductible goodwill over book goodwill for the stand-alone entity. That initial goodwill DTA is eliminated (along with the investment in subsidiary and Alagasco’s equity) in the Spire consolidated balance sheet because, at that consolidated level, there is no excess of tax deductible goodwill over book goodwill. As the tax goodwill is amortized and deducted for tax purposes, the DTA at Alagasco is reduced, and for Spire, a deferred tax liability (DTL) is created. For both Alagasco and consolidated Spire, the changes to the goodwill DTA/DTL are reported as a component of deferred tax expense in the income statement. Because the

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deferred tax expense impact will be offset by an opposite current tax expense impact, there will be no significant impact on the effective tax rate of the Company.

Acquisition of EnergySouth

Effective September 12, 2016, Spire completed the acquisition of 100% of the common stock of EnergySouth, the parent company of Mobile Gas and Willmut Gas, serving natural gas utility customers in Alabama and Mississippi. This acquisition is supportive of the strategic focus on growing Spire’s gas utility business and creating geographic and regulatory diversity. Total cash consideration paid at closing, net of cash acquired and debt assumed was $317.7. The goodwill of $218.9 arising from this acquisition, which is not deductible for tax purposes, is attributable to the assembled workforce and the expected cost efficiencies and strategic benefits of the transaction. The Company did not elect pushdown accounting, so the goodwill was recorded on the Spire parent company balance sheet rather than the EnergySouth subsidiary balance sheet and is included in disclosures of segment assets under Other. Because the acquisition occurred near the end of the fiscal year and certain assessments are still in progress, the assignment of goodwill to reporting units has not yet been completed. Similarly, the recorded values of some of the assets acquired and liabilities assumed, such as those related to income taxes and contingencies, are provisional pending completion of analyses of those items.

Actual and Pro Forma Results

The results of operations of each of the acquisitions are included in the Spire statements of income from the date of acquisition, as shown in the following table.

	Alagasco							EnergySouth
	2016		2015		2014			2016
Total Operating Revenues	$	368.5	$	479.2	$	19.7		$	3.3
Net Income (Loss)	53.2		48.0		(2.9		)	(0.2		)
Earnings (Loss) Per Share	$	1.20	$	1.11	$	(0.08	)	$	—

The following unaudited pro forma financial information presents Spire’s combined results of operations as though the EnergySouth acquisition had occurred as of the beginning of fiscal year 2015 and the Alagasco acquisition had occurred as of the beginning of fiscal year 2013. The unaudited pro forma financial information is not necessarily indicative of either future results of operations or results that would have been achieved if the acquisitions had occurred as of those earlier dates. It does not reflect the costs of any integration activities. It includes estimates and assumptions which management believes are reasonable.

	2016		2015		2014
Total Operating Revenues	$	1,632.4	$	2,081.6	$	2,187.1
Net Income	153.9		143.6		133.5
Basic Earnings Per Share	$	3.48	$	3.32	$	3.11
Diluted Earnings Per Share	3.46		3.31		3.10

3.     STOCK-BASED COMPENSATION

Spire’s 2015 incentive plan, The Laclede Group 2015 Equity Incentive Plan (the 2015 Plan), was approved at the annual meeting of shareholders of Spire on January 29, 2015. The purpose of the 2015 Plan is to encourage directors, officers, and employees of the Company and its subsidiaries to contribute to the Company’s success and align their interests with that of shareholders. To accomplish this purpose, the Compensation Committee (Committee) of the Board of Directors may grant awards under the 2015 Plan that may be earned by achieving performance objectives and/or other criteria as determined by the Committee. Under the terms of the 2015 Plan, officers and employees of the Company and its subsidiaries, as determined by the Committee, are eligible to be selected for awards. The 2015 Plan provides for restricted stock, restricted stock units, qualified and non-qualified stock options, stock appreciation rights, and performance shares payable in stock, cash, or a combination of both. The 2015 Plan generally provides a minimum vesting period of at least three years for each type of award, with pro rata vesting permitted during the minimum three-year vesting period. The maximum number of shares reserved for issuance under the 2015 Plan is 1,000,000. The 2015 Plan replaced The Laclede Group 2006 Equity Incentive Plan (the 2006 Plan), which in turn replaced The Laclede Group, Inc. 2002 Equity Incentive Plan (the 2002 Plan).

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Shares reserved under the 2006 Plan and the 2002 Plan, other than those needed for currently outstanding awards, were canceled upon shareholder approval of the 2015 Plan.

The Company issues new shares to satisfy employee restricted stock awards and stock option exercises.

Restricted Stock Awards

During fiscal year 2016, the Company granted 199,140 performance-contingent restricted share units to executive officers and key employees at a weighted average grant date fair value of $45.95 per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. The share units have a performance period ending September 30, 2018. While the participants have no interim voting rights on these share units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying share units do not vest.

The number of share units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP and is discussed further below.

The weighted average grant date fair value of performance-contingent restricted shares and share units granted during fiscal years 2015 and 2014 was $36.69 and $37.21 per share, respectively.

Fiscal year 2016 activity of restricted stock and restricted stock units subject to performance and/or market conditions is presented below:

	Shares/ Units		Weighted Average Grant Date Fair Value Per Share
Nonvested at September 30, 2015	397,270		$	36.28
Granted (maximum shares that can be earned)	199,140		$	45.95
Vested	(62,593	)	$	35.29
Forfeited	(23,234	)	$	30.96
Nonvested at September 30, 2016	510,583		$	40.37

During fiscal year 2016, the Company granted 35,210 shares of time-vested restricted stock to executive officers and key employees at a weighted average grant date fair value of $59.40 per share. These shares were awarded between December 2015 and September 2016 and vest between December 2018 and September 2019 based on terms of the agreements. In the interim, participants receive full voting rights and dividends, which are not subject to forfeiture. The weighted average grant date fair value of time-vested restricted stock and restricted stock units awarded to employees during fiscal year 2015 and 2014 was $50.90 and $45.66 per share, respectively.

During fiscal year 2016, the Company granted 13,520 shares of time-vested restricted stock to non-employee directors at a weighted average grant date fair value of $63.93 per share. The weighted average grant date fair value of restricted stock awarded to non-employee directors during fiscal years 2015 and 2014 was $54.66 and $46.02 per share, respectively.

Time-vested restricted stock and stock unit activity for fiscal year 2016 is presented below:

	Shares/ Units		Weighted Average Grant Date Fair Value Per Share
Nonvested at September 30, 2015	129,304		$	44.89
Granted	48,730		$	60.65
Vested	(44,645	)	$	47.30
Forfeited	(610	)	$	53.12
Nonvested at September 30, 2016	132,779		$	49.83

During fiscal year 2016, 107,238 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on October 1, 2012, December 3, 2012, February 1, 2013, June 3, 2013, and August 1, 2013 vested. The Company withheld 30,712 of the vested shares at a weighted average price of $57.29 per share pursuant to

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elections by employees to satisfy tax withholding obligations. During fiscal year 2015, 128,135 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on December 1, 2011, May 1, 2012, December 2, 2013 and January 1, 2014 vested. The Company withheld 31,688 of the vested shares at a weighted average price of $50.65 per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year 2014, 88,533 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on December 1, 2010, September 1, 2011, October 1, 2012, January 30, 2014 and February 21, 2014 vested. The Company withheld 23,776 of these vested shares at a weighted average price of $45.96 per share pursuant to elections by employees to satisfy tax withholding obligations.

The total fair value of restricted stock (performance-contingent and time-vested) vested during fiscal years 2016, 2015, and 2014 was $6.3, $6.4, and $4.1, respectively, and the related tax benefit was $2.4, $2.4 and $1.6, respectively. None of the tax benefits have been realized.

Stock Option Awards

No stock options were granted during fiscal years 2016, 2015, and 2014. Stock option activity for fiscal year 2016 is presented below:

	Stock Options		Weighted Average Exercise Price Per Share
Outstanding at September 30, 2015	28,500		$	33.65
Exercised	(27,750	)	$	33.66
Forfeited	(750	)	$	33.45
Outstanding at September 30, 2016	—		$	—

During fiscal year 2016, cash received from the exercise of stock options was $0.7 and the related intrinsic value was $0.7. During fiscal year 2015, cash received from the exercise of stock options was $1.5 and the related intrinsic value was $0.9. During fiscal year 2014, cash received from the exercise of stock options was $1.7 and the related intrinsic value was $0.9. Related tax benefits were not material in any of those years.

The closing price of the Company’s common stock was $63.74 per share at September 30, 2016.

Equity Compensation Costs

Compensation cost for performance-contingent restricted stock and stock unit awards is based upon the probable outcome of the performance conditions. For shares or units that do not vest or that are not expected to vest due to the outcome of the performance conditions (excluding market conditions), no compensation cost is recognized and any previously recognized compensation cost is reversed.

The fair value of awards of performance-contingent and time-vested restricted stock and restricted stock units, not subject to the TSR provision, are estimated using the closing price of the Company’s stock on the date of the grant. For those awards that do not pay dividends during the vesting period, the estimate of fair value is reduced by the present value of the dividends expected to be paid on the Company’s common stock during the performance period, discounted using an appropriate US Treasury yield. For shares subject to the TSR provision, the estimated impact of this market condition is reflected in the grant date fair value per share of the awards. Accordingly, compensation cost is not reversed to reflect any actual reductions in the awards that may result from the TSR provision. However, if the Company’s TSR during the performance period ranks below the level specified in the award agreements, relative to a comparator group of companies, and the Committee elects not to reduce the award (or reduce by a lesser amount), this election would be accounted for as a modification of the original award and additional compensation cost would be recognized at that time. The grant date fair value of the awards subject to the TSR provision awarded during fiscal years 2016, 2015, and 2014 was valued by a Monte Carlo simulation model that assessed the probabilities of various TSR outcomes. The significant assumptions used in the Monte Carlo simulations are as follows:

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	2016	2015	2014
Risk free interest rate	1.14%	0.83%	0.53%
Expected dividend yield of stock	—	—	—
Expected volatility of stock	15.0%	14.0%	18.0%
Vesting period	2.8 years	2.8 years	2.8 years

The risk free interest rate was based on the yield on US Treasury securities matching the vesting period. A zero percent dividend yield was used, which is mathematically equivalent to the assumption that dividends are reinvested as they are paid. The expected volatility is based on the historical volatility of the Company’s stock. Volatility assumptions were also made for each of the companies included in the comparator group. The vesting period is equal to the performance period set forth in the terms of the award.

The amounts of compensation cost recognized for share-based compensation arrangements are presented below:

	2016			2015			2014
Total equity compensation cost	$	6.7		$	6.7		$	5.8
Compensation cost capitalized	(2.2		)	(1.8		)	(1.8		)
Compensation cost recognized in net income	$	4.5		$	4.9		$	4.0
Income tax benefit recognized in net income	(1.7		)	(1.9		)	(1.5		)
Compensation cost recognized in net income, net of income tax	$	2.8		$	3.0		$	2.5

As of September 30, 2016, there was $9.2 of total unrecognized compensation cost related to non-vested share-based compensation arrangements. That cost is expected to be recognized over a weighted average period of 1.8 years.

4.     EARNINGS PER COMMON SHARE

	2016		2015		2014
Basic EPS:
Net Income	$	144.2	$	136.9	$	84.6
Less: Income allocated to participating securities	0.5		0.5		0.3
Net Income Available to Common Shareholders	$	143.7	$	136.4	$	84.3
Weighted Average Shares Outstanding (millions)	44.1		43.2		35.8
Earnings Per Share of Common Stock	$	3.26	$	3.16	$	2.36
Diluted EPS:
Net Income	$	144.2	$	136.9	$	84.6
Less: Income allocated to participating securities	0.5		0.5		0.3
Net Income Available to Common Shareholders	$	143.7	$	136.4	$	84.3
Weighted Average Shares Outstanding (millions)	44.1		43.2		35.8
Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units (millions)	0.2		0.1		0.1
Weighted Average Diluted Shares (millions)	44.3		43.3		35.9
Earnings Per Share of Common Stock	$	3.24	$	3.16	$	2.35
Outstanding Shares (in millions) Excluded from the Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to performance and/or market conditions	0.3		0.3		0.3

Spire’s 2014 2.0% Series Equity Units issued in June 2014 are potentially dilutive securities, but were excluded from the calculation of diluted EPS for the years ended September 30, 2016, 2015 and 2014. The potential shares were not included in the outstanding shares excluded from the calculation of Diluted EPS in the table above. See Note 5 for more information.

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5.     STOCKHOLDERS’ EQUITY

Equity Units

In June 2014, Spire issued 2.875 million equity units, initially consisting of Corporate Units, for an aggregate stated amount of approximately $143.8. Each Corporate Unit has a stated amount of fifty dollars and consists of (i) a stock purchase contract obligating the holder to purchase shares of Spire’s common stock, par value $1.00 per share, and (ii) a 1/20, or 5%, undivided beneficial ownership interest in one thousand dollars principal amount of Spire’s 2014 Series A 2.00% Remarketable Junior Subordinated Notes due 2022 (RSNs). The stock purchase contracts obligate the holders to purchase shares of common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price to be paid under the stock purchase contracts is fifty dollars per Corporate Unit and the number of shares to be purchased will be determined as follows:

If the applicable market value per share of Spire common stock is:	Number of shares to be purchased per purchase contract is:
Equal to or greater than $57.8125	0.8649
Less than $57.8125, but greater than $46.25	$50 ÷ applicable market value
Less than or equal to $46.25	1.0811

The RSNs are pledged as collateral to secure the purchase of Spire’s common stock under the related stock purchase contracts.

The Company makes quarterly interest payments on the RSNs and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. The Company may defer payments on the stock purchase contracts and the RSNs for one or more consecutive periods but generally not beyond the purchase contract settlement date. If payments are deferred, interest on the RSNs and contract adjustment payments will compound on each respective payment date in which the payment was deferred. Also, during the deferral period, the Company may not make any cash distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Additionally, the Company may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the RSNs during the deferral period. The Company has recorded the present value of the stock purchase contract payments as a liability offset by a charge to additional paid-in capital in equity. Interest payments on the RSNs are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS, the Company applies the treasury stock method to the Corporate Units. These securities did not have an effect on diluted EPS for the years ended September 30, 2016 and 2015.

Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Spire will issue between approximately 2.5 million and 3.1 million shares of its common stock in April 2017. A total of approximately 4.2 million shares of common stock have been reserved for issuance in connection with the stock purchase contracts. The stock purchase contracts obligate the holders to purchase shares of common stock at a future settlement date (April 1, 2017, or if such day is not a business day, the following business day) prior to the relevant RSN maturity date.

Selected information about the Company’s equity units is presented below:

Issuance Date	Units Issued (Millions)	Total Net Proceeds	Total Long-term Debt	RSN Annual Interest Rate	Stock Purchase Contract Annual Rate	Stock Purchase Contract Liability
6/11/2014	2.875	$139.4	$143.8	2.00%	4.75%	$19.7

Other Stock Information

Spire

On June 20, 2014, Spire filed a registration statement on Form S-3 for the issuance and sale of up to 168,698 shares of its common stock under its Dividend Reinvestment and Stock Purchase Program. There were 106,535 and 101,439 shares at September 30, 2016 and November 11, 2016, respectively, remaining available for issuance under this Form S-3.

On May 17, 2016, Spire completed a public offering of 2,185,000 shares of its common stock, generating $133.2 of proceeds net of issuance costs. On September 23, 2016, Spire and Laclede Gas filed with the SEC a joint shelf

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registration statement on Form S-3 for issuance of various types of debt and equity securities, which registration statement will expire September 22, 2019. The amount, timing, and type of additional financing to be issued under this shelf registration statement will depend on cash requirements and market conditions.

At September 30, 2016 and 2015, Spire had authorized 5,000,000 shares of preferred stock, but none were issued and outstanding.

Laclede Gas

Laclede Gas periodically sells shares of its stock to Spire at prices per share equal to book value on the last day of the quarter preceding each sale. There was no sale of shares to Spire during fiscal years 2016 or 2015. Laclede Gas sold 28 shares to Spire for $1.1 during fiscal year 2014. Exemption from registration for all of the sales was claimed under section 4(a)(2) of the Securities Act of 1933, as amended.

Substantially all of Laclede Gas plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on Laclede Gas’ ability to pay cash dividends on its common stock or to make loans to its parent company. These mortgage restrictions are applicable regardless of whether the stock is publicly held or held solely by Laclede Gas’ parent company. Under the most restrictive of these provisions, no cash dividend may be declared or paid if, after the dividend, the aggregate net amount spent for all dividends after September 30, 1953 would exceed a maximum amount determined by a formula set out in the mortgage. Under that formula, the maximum amount is the sum of $8.0 plus earnings applicable to common stock (adjusted for stock repurchases and issuances) for the period from September 30, 1953 to the last day of the quarter before the declaration or payment date for the dividends. As of September 30, 2016 and 2015, the amount under the mortgage’s formula that was available to pay dividends was $916.8 and $891.7, respectively. Thus, all of Laclede Gas’ retained earnings were free from such dividend restrictions as of those dates.

On September 23, 2016, Spire and Laclede Gas filed with the SEC a joint shelf registration statement on Form S-3 for issuance of various types of debt and equity securities, which registration statement will expire September 22, 2019. The amount, timing, and type of additional financing to be issued under this shelf registration statement will depend on cash requirements and market conditions, as well as future MoPSC authorizations.

Laclede Gas has authority from the MoPSC to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in capital, and enter into capital lease agreements, all for a total of up to $300.0. Laclede Gas has issued no securities under this authorization.

At September 30, 2016 and 2015, Laclede Gas had authorized 1,480,000 shares of preferred stock, but none were issued and outstanding.

Alagasco

At September 30, 2016 and 2015, Alagasco has authorized 120,000 shares of preferred stock, but none were issued and outstanding.

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Other Comprehensive Income

The components of accumulated other comprehensive income (loss), net of income taxes, recognized in the balance sheets at September 30 were as follows:

	Net Unrealized Gains (Losses) on Cash Flow Hedges			Defined Benefit Pension and Other Postretirement Benefit Plans			Net Unrealized Losses on Available for Sale Securities			Total
Spire
Balance at September 30, 2014	$	0.2		$	(1.9	)	$	—		$	(1.7	)
Other comprehensive (loss) income	(0.6		)	0.4			(0.1		)	(0.3		)
Balance at September 30, 2015	(0.4		)	(1.5		)	(0.1		)	(2.0		)
Other comprehensive (loss) income	(1.9		)	(0.3		)	—			(2.2		)
Balance at September 30, 2016	$	(2.3	)	$	(1.8	)	$	(0.1	)	$	(4.2	)
Laclede Gas
Balance at September 30, 2014	$	—		$	(1.9	)	$	—		$	(1.9	)
Other comprehensive (loss) income	(0.2		)	0.4			—			0.2
Balance at September 30, 2015	(0.2		)	(1.5		)	—			(1.7		)
Other comprehensive income (loss)	0.3			(0.3		)	(0.1		)	(0.1		)
Balance at September 30, 2016	$	0.1		$	(1.8	)	$	(0.1	)	$	(1.8	)

Income tax expense (benefit) recorded for items of other comprehensive income (loss) reported in the statements of comprehensive income is calculated by applying statutory federal, state, and local income tax rates applicable to ordinary income. The tax rates applied to individual items of other comprehensive income are similar within each reporting period. For the periods presented, Alagasco had no accumulated other comprehensive income (loss) balances.

6. LONG-TERM DEBT

Composition of long-term debt for Spire, Laclede Gas and Alagasco are shown in each registrant’s statements of capitalization as part of the financial statements. Maturities of long-term debt for Spire, Laclede Gas and Alagasco for the five fiscal years subsequent to September 30, 2016 are as follows:

	Spire		Laclede Gas		Alagasco
2017	$	250.0	$	—	$	—
2018	100.0		100.0		—
2019	180.0		50.0		—
2020	40.0		—		40.0
2021	55.0		—		—

Spire’s, Laclede Gas’ and Alagasco’s short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of September 30, 2016, there were no events of default under these covenants.

The Company’s, Laclede Gas’, and Alagasco’s access to capital markets, including the commercial paper market, and their respective financing costs, may depend on the credit rating of the entity that is accessing the capital markets. The credit ratings of the Company, Laclede Gas and Alagasco remain at investment grade, but are subject to review and change by the rating agencies.

It is management’s view that the Company, Laclede Gas and Alagasco have adequate access to capital markets and will have sufficient capital resources, both internal and external, to meet anticipated capital requirements, which primarily include capital expenditures, interest payments on long-term debt, scheduled maturities of long-term debt, short-term seasonal needs, and dividends.

Spire

Spire entered into a master note purchase agreement on June 20, 2016, with certain institutional purchasers pursuant to which Spire issued a total of $165.0 unsecured notes in the private placement market. These notes were

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issued on September 9, 2016 to fund a portion of the purchase price for the EnergySouth acquisition and consisted of $35 million in aggregate principal amount of its unsecured Series 2016 Senior Notes, Tranche A, due September 1, 2021 (Tranche A Notes) and $130 million in aggregate principal amount of its unsecured Series 2016 Senior Notes, Tranche B, due September 1, 2026 (Tranche B Notes). Tranche A Notes and Tranche B Notes bear interest at a rate per annum of 2.52% and 3.13%, respectively.

At September 30, 2016, including the current portion but excluding unamortized discounts and net hedging gains, Spire had long-term debt totaling $2,085.8, of which $810.0 was issued by Laclede Gas, $250.0 was issued by Alagasco, and $67.0 was issued by other subsidiaries. With the exception of $250.0 floating rate senior notes issued by Spire, all long-term debt bears fixed rates and is subject to changes in fair value as market interest rates change. However, increases and decreases in fair value would impact earnings and cash flows only if the Company were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to the Utilities’ regulated operations, losses or gains on early redemption of long-term debt typically would be deferred as regulatory assets or liabilities and amortized over a future period.

Of the Company’s $1,942.0 senior long-term debt (including the current portion) , $25.0 have no call options, $937.0 have make-whole call options, $250.0 is callable currently, and $730.0 are callable at par between one to six months prior to maturity. The remainder of the Company’s long-term debt is $143.8 of 2% Remarketable Junior Subordinated Notes due in 2022. None of the debt has put options.

Spire has a shelf registration statement on Form S-3 on file with the SEC for the issuance and sale of up to 168,698 shares of common stock under its Dividend Reinvestment and Direct Stock Purchase Plan. There were 106,535 and 101,439 at September 30, 2016 and November 11, 2016, respectively, remaining available for issuance under this Form S-3. Spire also has a shelf registration statement on Form S-3 on file with the SEC for the issuance of equity and debt securities.

The Company’s capitalization at September 30, 2016 consisted of 49.1% of Spire common stock equity and 50.9% long-term debt, compared to 47.0% of Spire common stock equity and 53.0% of long-term debt at September 30, 2015. The decline in the proportion of long-term debt is due primarily to the reclassification of $250.0 of Spire’s long-term debt to “current.”

Laclede Gas

At September 30, 2016, Laclede Gas had fixed-rate long-term debt, including the current portion, totaling $810.0. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. Of Laclede Gas’ $810.0 in long-term debt, $25.0 have no call options, $435.0 have make-whole call options and $350.0 are callable at par three to six months prior to maturity. None of the debt has any put options.

Laclede Gas has authority from the MoPSC to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in-capital, and enter into capital lease agreements, all for a total of up to $300.0 for financings placed any time before September 30, 2018. On March 31, 2016, Laclede Gas filed an appeal with Missouri’s Western District Court of Appeals challenging the level of authority. On July 20, 2016, Laclede Gas filed its initial brief in the appeal. Oral arguments are scheduled for November 17, 2016. During the year ended September 30, 2016, Laclede Gas issued no securities under this authorization, so that as of November 11, 2016, $300.0 remains available to be issued. On September 23, 2016, Laclede Gas filed a shelf registration on Form S-3 with the SEC for issuance of first mortgage bonds, unsecured debt, and preferred stock, which expires on September 22, 2019. The amount, timing, and type of additional financing to be issued under this shelf registration will depend on cash requirements and market conditions, as well as future MoPSC authorizations. This authorization is more fully described in Note 5, Stockholders’ Equity.

Laclede Gas’ capitalization at September 30, 2016 consisted of 56.9% of Laclede Gas common stock equity and 43.1% long-term debt compared to 56.2% of Laclede Gas common stock equity and 43.8% of long-term debt at September 30, 2015.

Substantially all of Laclede Gas’ plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on Laclede Gas’ ability to pay cash dividends on its common stock, which are described more fully in Note 5, Stockholders’ Equity.

Alagasco

Because Alagasco has no standing authority to issue long-term debt, it must petition the APSC for each planned issuance. On November 3, 2014, Alagasco received authorization and approval from the APSC to borrow $35.0 for the purpose of redeeming, without penalty, $34.8 in existing long-term, callable debt financed at 5.7%. Pursuant to a call notice issued on December 15, 2014, Alagasco redeemed $34.8 of debt effective January 15, 2015. On

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February 3, 2015, Alagasco received authorization and approval from the APSC to borrow $80.0 for the purpose of refinancing the scheduled maturity on December 1, 2015 of $80.0 of existing debt. Pursuant to these authorizations, Alagasco committed to issue $115.0 unsecured notes in the private placement market: $35.0 at a rate of 3.21% for 10 years issued on September 15, 2015, and $80.0 at a rate of 4.31% for 30 years issued on December 1, 2015. The Notes are senior unsecured obligations of Alagasco and rank equal in right to payment with all other senior unsecured indebtedness. Alagasco used the proceeds from the sale of the Notes to refinance existing indebtedness and for general corporate purposes.

At September 30, 2016, Alagasco had fixed-rate long-term debt totaling $250.0. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. All of Alagasco’s $250.0 long-term debt has make-whole call options.

Alagasco’s capitalization at September 30, 2016 consisted of 77.6% of Alagasco common stock equity and 22.4% long-term debt compared to 83.7% of Alagasco common stock equity and 16.3% of long-term debt at September 30, 2015.

7.    NOTES PAYABLE AND CREDIT AGREEMENTS

Short-term cash requirements outside of the Utilities have generally been funded by Spire or met with internally generated funds. AtSeptember 30, 2016, Spire had a $150.0 syndicated line of credit from nine banks maturing on September 3, 2019, with the largest portion provided by a single bank being 15.6%. The line of credit has a covenant limiting the total debt of the consolidated Spire to no more than 70% of the Company’s total capitalization. As defined in the line of credit, this ratio was 58.5% on September 30, 2016. Spire’s line may be used to provide for the funding needs of various subsidiaries. The maturity date of the loan agreement is September 3, 2019.

The Utilities’ short-term borrowing requirements typically peak during the colder months while the Company’s needs are less seasonal. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. At September 30, 2016, Laclede Gas had a syndicated line of credit of $450.0 in place from ten banks. The largest portion provided by a single bank is 15.6%. Laclede Gas’ line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. As defined in the line of credit, on September 30, 2016 total debt was 49.7% of total capitalization. Laclede Gas’ commercial paper program is backed by the line of credit. The maturity date of the line of credit is September 3, 2019.

On September 2, 2014, Alagasco entered into a new $150.0 syndicated line of credit with twelve banks and extinguished the line that was in place prior to its acquisition by Spire. The largest portion provided by a single bank is 10%. The line of credit, which matures on September 2, 2019, has a covenant limiting total debt to no more than 70% of Alagasco’s total capitalization. As defined in the line of credit, this ratio stood at 27.8% on September 30, 2016.

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Spire

Information about Spire’s short-term borrowings (excluding intercompany borrowings) during the twelve months ended September 30, and as of September 30, is presented below for 2016 and 2015:

	Laclede Gas Commercial Paper Borrowings	Spire Bank Line Borrowings*	Alagasco Bank Line Borrowings	Total Short-Term Borrowings
Year Ended September 30, 2016
Weighted average borrowings outstanding	$201.0	$42.7	$30.2	$273.9
Weighted average interest rate	0.7%	1.6%	1.4%	0.9%
Range of borrowings outstanding	$43.0 - $307.2	$0.0 - $82.0	$0.0 - $82.0	$73.1 - $427.2
As of September 30, 2016
Borrowings outstanding at end of period	$243.7	$73.0	$82.0	$398.7
Weighted average interest rate	0.8%	1.8%	1.5%	1.1%
Year Ended September 30, 2015
Weighted average borrowings outstanding	$212.7	$65.6	$22.3	$300.6
Weighted average interest rate	0.4%	1.4%	1.1%	0.7%
Range of borrowings outstanding	$ 102.1 - $341.0	$32.5 - $80.0	$0.0 - $69.5	$180.1 - $488.5
As of September 30, 2015
Borrowings outstanding at end of period	$233.0	$74.0	$31.0	$338.0
Weighted average interest rate	0.5%	1.5%	1.2%	0.8%

* Spire Inc., excluding its wholly owned subsidiaries.

Based on average short-term borrowings for the twelve months ended September 30, 2016, an increase in the average interest rate of 100 basis points would decrease Spire’s pre-tax earnings and cash flows by approximately $2.7 on an annual basis, portions of which may be offset through the application of PGA or GSA carrying costs.

Laclede Gas

Information about Laclede Gas’ short-term borrowings during the twelve months ended September 30, and as of September 30, is presented below for 2016 and 2015:

	Commercial Paper Borrowings	Borrowings from Spire	Total Short-Term Borrowings
Year Ended September 30, 2016
Weighted average borrowings outstanding	$201.0	$14.7	$215.7
Weighted average interest rate	0.7%	0.8%	0.7%
Range of borrowings outstanding	$43.0 - $307.2	$0.0 - $114.2	$127.8 - $ 307.2
As of September 30, 2016
Borrowings outstanding at end of period	$243.7	$—	$243.7
Weighted average interest rate	0.8%	—%	0.8%
Year Ended September 30, 2015
Weighted average borrowings outstanding	$212.7	$0.3	$213.0
Weighted average interest rate	0.4%	0.5%	0.4%
Range of borrowings outstanding	$102.1 - $341.0	$0.0 - $10.4	$104.2 - $ 341.0
As of September 30, 2015
Borrowings outstanding at end of period	$233.0	$—	$233.0
Weighted average interest rate	0.5%	—%	0.5%

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Based on average short-term borrowings for the twelve months ended September 30, 2016, an increase in the average interest rate of 100 basis points would decrease Laclede Gas’ pre-tax earnings and cash flows by approximately $2.2 on an annual basis, portions of which may be offset through the application of PGA carrying costs.

Alagasco

Information about Alagasco’s short-term borrowings during the twelve months ended September 30, and as of September 30, is presented below for 2016 and 2015:

	Bank Line Borrowings	Borrowings from Spire	Total Short-Term Borrowings
Year Ended September 30, 2016
Weighted average borrowings outstanding	$30.2	$12.4	$42.6
Weighted average interest rate	1.4%	1.4%	1.4%
Range of borrowings outstanding	$0.0 - $82	$0.0 - $61.9	$19.0 - $82.0
As of September 30, 2016
Borrowings outstanding at end of period	$82.0	$—	$82.0
Weighted average interest rate	1.5%	—%	1.5%
Year Ended September 30, 2015
Weighted average borrowings outstanding	$22.3	$—	$22.3
Weighted average interest rate	1.1%	—%	1.1%
Range of borrowings outstanding	$0.0 - $69.5	0	$0.0- $69.5
As of September 30, 2015
Borrowings outstanding at end of period	$31.0	$—	$31.0
Weighted average interest rate	1.2%	—%	1.2%

Based on average short-term borrowings for the twelve months ended September 30, 2016, an increase in the average interest rate of 100 basis points would decrease Alagasco’s pre-tax earnings and cash flows by approximately $0.4 on an annual basis, portions of which may be offset through the application of GSA carrying costs.

8. FAIR VALUE OF FINANCIAL INSTRUMENTS

Spire

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis for the Company are as follows:

					Classification of Estimated Fair Value
	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of September 30, 2016
Cash and cash equivalents	$	5.2	$	5.2	$	5.2	$	—	$	—
Short-term debt	398.7		398.7		—		398.7		—
Long-term debt, including current portion	2,083.7		2,257.1		—		2,257.1		—
As of September 30, 2015
Cash and cash equivalents	$	13.8	$	13.8	$	13.8	$	—	$	—
Short-term debt	338.0		338.0		—		338.0		—
Long-term debt, including current portion	1,851.5		1,944.2		—		1,944.2		—

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Laclede Gas

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis for Laclede Gas are as follows:

					Classification of Estimated Fair Value
	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of September 30, 2016
Cash and cash equivalents	$	2.1	$	2.1	$	2.1	$	—	$	—
Short-term debt	243.7		243.7		—		243.7		—
Long-term debt	808.3		900.4		—		900.4		—
As of September 30, 2015
Cash and cash equivalents	$	1.7	$	1.7	$	1.7	$	—	$	—
Short-term debt	233.0		233.0		—		233.0		—
Long-term debt	808.1		880.2		—		880.2		—

Alagasco

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis for Alagasco are as follows:

					Classification of Estimated Fair Value
	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of September 30, 2016
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—
Short-term debt	82.0		82.0		—		82.0		—
Long-term debt	250.0		275.5		—		275.5		—
As of September 30, 2015
Cash and cash equivalents	$	7.2	$	7.2	$	7.2	$	—	$	—
Short-term debt	31.0		31.0		—		31.0		—
Long-term debt, including current portion	250.0		263.2		—		263.2		—

The carrying amounts for cash and cash equivalents and short-term debt approximate fair value due to the short maturity of these instruments. The fair values of long-term debt are estimated based on market prices for similar issues. Refer to Note 9, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis.

9.    FAIR VALUE MEASUREMENTS

Spire

The information presented below categorizes the assets and liabilities in the balance sheets that are accounted for at fair value on a recurring basis in periods subsequent to initial recognition.

The mutual funds included in Level 1 are valued based on exchange-quoted market prices of individual securities. The mutual funds included in Level 2 are valued based on the closing net asset value per unit.

Derivative instruments included in Level 1 are valued using quoted market prices on the NYMEX. Derivative instruments classified as Level 2 include physical commodity derivatives that are valued using Over-the-Counter Bulletin Board (OTCBB), broker, or dealer quotation services whose prices are derived principally from, or are corroborated by, observable market inputs. Also included in Level 2 are certain derivative instruments that have

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values that are similar to, and correlate with, quoted prices for exchange-traded instruments in active markets. Derivative instruments included in Level 3 are valued using generally unobservable inputs that are based upon the best information available and reflect management’s assumptions about how market participants would price the asset or liability. There were no material Level 3 balances as of September 30, 2016 or 2015. The Company’s and the Utilities’ policy is to recognize transfers between the levels of the fair value hierarchy, if any, as of the beginning of the interim reporting period in which circumstances change or events occur to cause the transfer.

The mutual funds are included in the “Other investments” line of the balance sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the balance sheets when a legally enforceable netting agreement exist between the Company or Laclede Gas and the counterparty to the derivative contract. For additional information on derivative instruments, see Note 10, Derivative Instruments and Hedging Activities.

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	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of September 30, 2016
ASSETS
Gas Utility
US stock/bond mutual funds	$	16.8	$	4.1	$	—	$	—		$	20.9
NYMEX/ICE natural gas contracts	5.3		—		—		(0.4		)	4.9
Gasoline and heating oil contracts	0.4		—		—		(0.3		)	0.1
Subtotal	22.5		4.1		—		(0.7		)	25.9
Gas Marketing
NYMEX/ICE natural gas contracts	0.4		3.4		—		(3.4		)	0.4
Natural gas commodity contracts	—		8.7		0.2		(0.9		)	8.0
Total	$	22.9	$	16.2	$	0.2	$	(5.0	)	$	34.3
LIABILITIES
Gas Utility
NYMEX/ICE natural gas contracts	$	1.6	$	—	$	—	$	(1.6	)	$	—
OTCBB natural gas contracts	—		0.2		—		—			0.2
Subtotal	1.6		0.2		—		(1.6		)	0.2
Gas Marketing
NYMEX/ICE natural gas contracts	3.5		1.6		—		(5.1		)	—
Natural gas commodity contracts	—		2.6		—		(0.9		)	1.7
Other
Interest rate swaps	—		3.0		—		—			3.0
Total	$	5.1	$	7.4	$	—	$	(7.6	)	$	4.9
As of September 30, 2015
ASSETS
Gas Utility
US stock/bond mutual funds	$	15.5	$	4.0	$	—	$	—		$	19.5
NYMEX/ICE natural gas contracts	1.3		—		—		(1.3		)	—
Subtotal	16.8		4.0		—		(1.3		)	19.5
Gas Marketing
NYMEX natural gas contracts	6.3		4.3		—		(6.6		)	4.0
Natural gas commodity contracts	—		1.5		0.2		(0.5		)	1.2
Total	$	23.1	$	9.8	$	0.2	$	(8.4	)	$	24.7
LIABILITIES
Gas Utility
NYMEX/ICE natural gas contracts	$	16.4	$	—	$	—	$	(16.4	)	$	—
OTCBB natural gas contracts	—		5.9		—		—			5.9
NYMEX gasoline and heating oil contracts	0.3		—		—		(0.3		)	—
Subtotal	16.7		5.9		—		(16.7		)	5.9
Gas Marketing
NYMEX/ICE natural gas contracts	1.2		3.9		—		(5.1		)	—
Natural gas commodity contracts	—		2.2		—		(0.5		)	1.7
Total	$	17.9	$	12.0	$	—	$	(22.3	)	$	7.6

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Laclede Gas

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of September 30, 2016
ASSETS
US stock/bond mutual funds	$	16.8	$	4.1	$	—	$	—		$	20.9
NYMEX/ICE natural gas contracts	5.3		—		—		(0.4		)	4.9
Gasoline and heating oil contracts	0.3		—		—		(0.3		)	—
Total	$	22.4	$	4.1	$	—	$	(0.7	)	$	25.8
LIABILITIES
NYMEX/ICE natural gas contracts	$	1.6	$	—	$	—	$	(1.6	)	$	—
OTCBB natural gas contracts	—		0.2		—		—			0.2
Total	$	1.6	$	0.2	$	—	$	(1.6	)	$	0.2
As of September 30, 2015
ASSETS
US stock/bond mutual funds	$	15.5	$	4.0	$	—	$	—		$	19.5
NYMEX/ICE natural gas contracts	1.3		—		—		(1.3		)	—
Total	$	16.8	$	4.0	$	—	$	(1.3	)	$	19.5
LIABILITIES
NYMEX/ICE natural gas contracts	$	16.4	$	—	$	—	$	(16.4	)	$	—
OTCBB natural gas contracts	—		5.9		—		—			5.9
NYMEX gasoline and heating oil contracts	0.3		—		—		(0.3		)	—
Total	$	16.7	$	5.9	$	—	$	(16.7	)	$	5.9

Alagasco

During the fiscal second quarter of 2016 Alagasco commenced a gasoline derivative program to stabilize the cost of fuel used in operations. As of September 30, 2016, the fair value of related gasoline contracts was not significant.

10. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Spire

Laclede Gas has a risk management policy to utilize various derivatives, including futures contracts, exchange-traded options, swaps and over-the-counter instruments for the explicit purpose of managing price risk associated with purchasing and delivering natural gas on a regular basis to customers in accordance with its tariffs. The objective of this policy is to limit Laclede Gas’ exposure to natural gas price volatility and to manage, hedge and mitigate substantial price risk. Further discussion of this policy can be found in the Laclede Gas section.

From time to time Laclede Gas and Alagasco purchase NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of their business. Further information on these derivatives can be found in the Laclede Gas and Alagasco sections, respectively.

In the course of its business, Spire’s gas marketing subsidiary, LER, which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At September 30, 2016, the fair values of 122.7 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 110.8 million MMBtu will settle during fiscal year 2017, and 11.4 million MMBtu, 0.2 million MMBtu, and 0.3 million MMBtu will settle

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during 2018, 2019, and 2020, respectively. These contracts have not been designated as hedges; therefore, changes in the fair value of these contracts are reported in earnings each period.

Furthermore, LER manages the price risk associated with its fixed-priced commitments by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of NYMEX or ICE futures, swap, and option contracts to lock in margins.

At September 30, 2016, LER’s unmatched fixed-price positions were not material to Spire’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.

On April 14, 2014, as amended on July 8, 2014, Spire entered into certain interest rate swap agreements, with a notional amount $375.0, to effectively lock in interest rates on a portion of the long-term debt it anticipated issuing to finance its acquisition of Alagasco. These derivative instruments were designated as cash flow hedges of forecasted transactions. These forward starting swaps involved the payment of a fixed interest rate and the receipt of a floating interest rate (the London Interbank Offered Rate, also known as LIBOR) over the terms specified in the contracts. On August 6, 2014, the interest rate swap agreements were terminated and the settlement resulted in a $19.0 loss by Spire, which assigned the loss as a regulatory asset since the interest rate swaps were entered into to hedge the interest payments on the $625.0 of long-term debt issued on August 19, 2014 by Spire.

During the second quarter of fiscal year 2015, Alagasco entered into certain interest rate swap transactions to protect itself against adverse movement in interest rates in anticipation of its issuance of $115.0 of long-term debt. Alagasco received prior approval from the APSC to enter into these hedges. The notional amount of interest rate swaps outstanding was $80.5 with stated maturities ranging from 2025 to 2045 and fixed interest rates ranging between 2.18% and 2.85%. In April 2015, Alagasco entered into an additional hedge with a notional amount of $24.0 and terms within the same range. These derivative instruments were designated as cash flow hedges of forecasted transactions. These forward starting swaps involved the payment of a fixed interest rate and the receipt of LIBOR over the terms specified in the contracts. On May 21, 2015, the interest rate swap agreements were terminated and the settlement resulted in a $2.7 gain which was recorded as a regulatory liability. Of the total issuance of long-term debt, $35.0 was issued on September 15, 2015 and the remaining $80.0 was issued on December 1, 2015.

During the second quarter of fiscal 2016, Spire entered into five-year interest rate swap transactions with a fixed interest rate of 1.776% and a notional amount of $105.0 to protect itself against adverse movement in interest rates in anticipation of the issuance of long-term debt in 2017. During the third quarter of 2016, the Company entered into seven-year swap transactions with an average fixed interest rate of 1.501% and a notional amount of $120.0 to hedge against additional debt expected to be issued in 2017 or early 2018. As a result, a $1.0 mark-to-market gain and $3.0 mark-to-market losses were recognized for the three and twelve months ended September 30, 2016, respectively.

On May 5, 2016, Spire entered into certain interest rate swap agreements, with a notional amount of $85.0, to effectively lock in interest rates on a portion of the long-term debt it anticipated issuing to finance its acquisition of EnergySouth. These derivative instruments were designated as cash flow hedges of forecasted transactions. On June 3, 2016, the interest rate swap agreements were terminated and the settlement resulted in a $0.4 payment recorded in accumulated other comprehensive loss to be amortized over the life of the related debt issuances.

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The Company’s and Laclede Gas’ exchange-traded/cleared derivative instruments consist primarily of NYMEX, OTCBB, and ICE positions. The NYMEX and OTCBB is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX/ICE and OTCBB natural gas futures and swap positions at September 30, 2016 were as follows:

	Gas Utility			Gas Marketing
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
NYMEX/ICE Open short futures positions
Fiscal 2017	—	$	—	12.20	$	2.86
Fiscal 2018	—	—		1.27	2.95
NYMEX/ICE Open long futures/swap positions
Fiscal 2017	18.43	2.95		4.62	3.12
Fiscal 2018	0.33	2.83		0.45	3.02
Fiscal 2019	—	—		0.04	2.89
ICE Open long basis swap positions
Fiscal 2017	—	—		16.62	0.34
Fiscal 2018	—	—		2.01	0.43
Fiscal 2019	—	—		0.08	0.40
ICE Open short basis swap positions
Fiscal 2017	—	—		11.88	0.19
Fiscal 2018	—	—		0.93	0.27
Fiscal 2019	—	—		2.27	0.13
OTC Open long futures/swap positions
Fiscal 2017	0.32	3.64		—	—

At September 30, 2016, Laclede Gas also had 19.8 million MMBtu of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies while LER had none.

Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the balance sheets of the Company at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in other comprehensive income or loss (OCI). Accumulated other comprehensive income or loss (AOCI) is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at September 30, 2016, it is expected that an immaterial amount of unrealized gains will be reclassified into the Consolidated Statements of Income of the Company during the next twelve months. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the Consolidated Statements of Cash Flows.

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Effect of Derivative Instruments on the Consolidated Statements of Income and Consolidated Statements of Comprehensive Income
	Location of Gain (Loss)
	Recorded in Income	2016			2015			2014
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
Gas Marketing natural gas contracts		$	(0.6	)	$	(4.3	)	$	(4.6	)
Gas Utility gasoline and heating oil contracts		—			(1.2		)	0.1
Interest Rate Swaps		(3.4		)	—			—
Total		$	(4.0	)	$	(5.5	)	$	(4.5	)
Effective portion of gain (loss) reclassified from AOCI to income:
Natural gas contracts	Gas Marketing Operating Revenues	$	4.3		$	1.7		$	4.2
	Gas Marketing Operating Expenses	(4.9		)	(5.2		)	(1.5		)
Subtotal		(0.6		)	(3.5		)	2.7
Gasoline and heating oil contracts	Gas Utility Other Operating Expenses	(0.5		)	(0.9		)	(0.2		)
Total		$	(1.1	)	$	(4.4	)	$	2.5
Ineffective portion of gain (loss) on derivatives recognized in income:
Natural gas contracts	Gas Marketing Operating Revenues	$	0.1		$	—		$	(0.1	)
	Gas Marketing Operating Expenses	0.1			(0.5		)	0.1
Subtotal		0.2			(0.5		)	—
Gasoline and heating oil contracts	Gas Utility Other Operating Expenses	0.1			0.1			(0.2		)
Total		$	0.3		$	(0.4	)	$	(0.2	)
Derivatives Not Designated as Hedging Instruments*
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	12.3		$	(1.3	)	$	(8.7	)
NYMEX / ICE natural gas contracts	Gas Marketing Operating Revenues	(1.7		)	(9.6		)	3.0
Gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	—			(0.2		)	—
Total		$	10.6		$	(11.1	)	$	(5.7	)

* Gains and losses on Laclede Gas’ natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Missouri Utilities’ PGA clauses and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the statements of income. Such amounts are recognized in the statements of income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA clause and reflected in customer billings.

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Fair Value of Derivative Instruments in the Consolidated Balance Sheet
	Asset Derivatives*			Liability Derivatives*
September 30, 2016	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Gas Utility:
Gasoline and heating oil contracts	Derivative Instrument Assets	$	0.3	Derivative Instrument Assets	$	—
Gas Marketing:
Natural gas contracts	Derivative Instrument Assets	2.5		Derivative Instrument Assets	0.8
	Deferred Charges – Other	0.4		Deferred Charges – Other	0.1
Other: Interest swaps	Derivative Instrument Assets	—		Derivative Instrument Assets	3.0
Subtotal		3.2			3.9
Derivatives not designated as hedging instruments
Gas Utility:
Natural gas contracts	Accounts Receivable – Other	5.4		Accounts Receivable – Other	1.6
	Derivative Instrument Assets	—		Derivative Instrument Assets	0.2
Gas Marketing:
NYMEX / ICE natural gas contracts	Derivative Instrument Assets	0.8		Derivative Instrument Assets	4.1
	Deferred Charges – Other	—		Deferred Charges – Other	0.1
Natural gas commodity	Derivative Instrument Assets	6.5		Derivative Instrument Assets	0.2
	Other Deferred Charges	2.1		Other Deferred Charges	0.3
	Current Liabilities – Other	0.2		Current Liabilities – Other	2.0
	Deferred Credits – Other	0.2		Deferred Credits – Other	0.1
Subtotal		15.2			8.6
Total derivatives		$	18.4		$	12.5
September 30, 2015
Derivatives designated as hedging instruments
Gas Utility:
Gasoline and heating oil contracts	Accounts Receivable – Other	$	—	Accounts Receivable – Other	$	0.3
Gas Marketing:
Natural gas contracts	Derivative Instrument Assets	4.1		Derivative Instrument Assets	3.2
	Deferred Charges – Other	1.1		Deferred Charges – Other	0.5
Subtotal		5.2			4.0
Derivatives not designated as hedging instruments
Gas Utility:
Natural gas contracts	Accounts Receivable – Other	1.2		Accounts Receivable – Other	16.4
	Derivative Instrument Assets	—		Derivative Instrument Assets	5.7
	Deferred Charges – Other	—		Deferred Charges – Other	0.2
Gas Marketing:
NYMEX / ICE natural gas contracts	Derivative Instrument Assets	4.7		Derivative Instrument Assets	0.6
	Deferred Charges – Other	0.7		Deferred Charges – Other	0.7
Natural gas commodity	Derivative Instrument Assets	1.4		Derivative Instrument Assets	0.1
	Current Liabilities – Other	0.2		Current Liabilities – Other	1.4
	Deferred Credits – Other	0.1		Deferred Credits – Other	0.7
Subtotal		8.3			25.8
Total derivatives		$	13.5		$	29.8

* The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the balance sheets. As such, the gross balances presented in the table above are not indicative of the Company’s net economic exposure. Refer to Note 9, Fair Value Measurements, for information on the valuation of derivative instruments.

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Following is a reconciliation of the amounts in the tables above to the amounts presented in the Consolidated Balance Sheets:

	2016			2015
Fair value of asset derivatives presented above	$	18.4		$	13.5
Fair value of cash margin receivables offset with derivatives	2.5			13.9
Netting of assets and liabilities with the same counterparty	(7.6		)	(22.2		)
Total	$	13.3		$	5.2
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	$	11.4		$	4.6
Deferred Charges – Other	1.9			0.6
Total	$	13.3		$	5.2
Fair value of liability derivatives presented above	$	12.5		$	29.8
Netting of assets and liabilities with the same counterparty	(7.6		)	(22.2		)
Total	$	4.9		$	7.6
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Current Liabilities – Other	$	4.8		$	6.8
Deferred Credits – Other	0.1			0.8
Total	$	4.9		$	7.6

Additionally, at September 30, 2016 and 2015, the Company had $2.9 and $5.9, respectively, in cash margin receivables not offset with derivatives, which are presented in Accounts Receivable – Other.

Laclede Gas

Laclede Gas has a risk management policy to utilize various derivatives, including futures contracts, exchange-traded options, swaps and over-the-counter instruments for the explicit purpose of managing price risk associated with purchasing and delivering natural gas on a regular basis to customers in accordance with its tariffs. The objective of this policy is to limit Laclede Gas’ exposure to natural gas price volatility and to manage, hedge and mitigate substantial price risk. This policy strictly prohibits speculation and permits Laclede Gas to hedge current physical natural gas purchase commitments or forecasted or anticipated future peak (maximum) physical need for natural gas delivered. Costs and cost reductions, including carrying costs, associated with Laclede Gas’ use of natural gas derivative instruments are allowed to be passed on to Laclede Gas customers through the operation of its PGA clause, through which the MoPSC allows Laclede Gas to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, Laclede Gas does not expect any adverse earnings impact as a result of the use of these derivative instruments.

Laclede Gas does not designate these instruments as hedging instruments for financial reporting purposes because gains or losses associated with the use of these derivative instruments are deferred and recorded as regulatory assets or regulatory liabilities pursuant to ASC Topic 980, “Regulated Operations,” and, as a result, have no direct impact on the statements of income.

The timing of the operation of the PGA clause may cause interim variations in short-term cash flows, because Laclede Gas is subject to cash margin requirements associated with changes in the values of these instruments. Nevertheless, carrying costs associated with such requirements are recovered through the PGA clause.

From time to time, Laclede Gas purchases NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At September 30, 2016, Laclede Gas held 1.8 million gallons of gasoline futures contracts at an average price of $1.37 per gallon. Most of these contracts, the longest of which extends to December 2016, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815, “Derivatives and Hedging.” The gains or losses on these derivative instruments are not subject to Laclede Gas’ PGA clause.

Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the balance sheets at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in OCI. AOCI is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged

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item impacts. Based on market prices at September 30, 2016, it is expected that an immaterial amount of pre-tax gains will be reclassified into the statements of income during fiscal year 2016. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the statements of cash flows.

Laclede Gas’ derivative instruments consist primarily of NYMEX and OTCBB positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX and OTCBB natural gas futures positions at September 30, 2016 were as follows:

	MMBtu (millions)	Avg. Price Per MMBtu
NYMEX/ICE Open long futures/swap positions
Fiscal 2017	18.43	$	2.95
Fiscal 2018	0.33	2.83
OTC Open long futures/swap positions
Fiscal 2017	0.32	$	3.64

At September 30, 2016, Laclede Gas also had 19.8 million MMBtu of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies.

Effect of Derivative Instruments on the Statements of Income and Statements of Comprehensive Income
	Location of Gain (Loss)
	Recorded in Income	2016			2015			2014
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
Gasoline and heating oil contracts		$	—		$	(1.2	)	$	0.1
Effective portion of gain (loss) reclassified from AOCI to income:
Gasoline and heating oil contracts	Gas Utility Other Operating Expenses	$	(0.5	)	$	(0.9	)	$	(0.2	)
Ineffective portion of gain (loss) on derivatives recognized in income:
Gasoline and heating oil contracts	Gas Utility Other Operating Expenses	$	0.1		$	0.1		$	(0.2	)
Derivatives Not Designated as Hedging Instruments*
Gain (loss) recognized in income on derivatives:
Gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	$	—		$	(0.2	)	$	—

* Gains and losses on Laclede Gas’ natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Laclede Gas’ PGA clauses and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the Statements of Income. Such amounts are recognized in the Statements of Income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA clause and reflected in customer billings.

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Fair Value of Derivative Instruments in the Balance Sheet at September 30, 2016
	Asset Derivatives*				Liability Derivatives*
	Balance Sheet Location	Fair Value			Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Gasoline and heating oil contracts	Derivative Instrument Assets	$	0.3		Derivative Instrument Assets	$	—
Subtotal		0.3				—
Derivatives not designated as hedging instruments
Natural gas contracts	Accounts Receivable – Other	5.4			Accounts Receivable – Other	1.6
OTCBB natural gas contracts	Derivative Instrument Assets	—			Derivative Instrument Assets	0.2
Subtotal		5.4				1.8
Total derivatives		$	5.7			$	1.8
Fair Value of Derivative Instruments in the Balance Sheet at September 30, 2015
	Asset Derivatives				Liability Derivatives*
	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Gasoline and heating oil contracts	Accounts Receivable – Other	$	—		Accounts Receivable – Other	$	0.3
Subtotal		—				0.3
Derivatives not designated as hedging instruments
Natural gas contracts	Accounts Receivable – Other	1.2			Accounts Receivable – Other	16.4
	Derivative Instrument Assets	—			Derivative Instrument Assets	5.7
	Deferred Charges - Other	—			Deferred Charges - Other	0.2
Subtotal		1.2				22.3
Total derivatives		$	1.2			$	22.6

* The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the Balance Sheets. As such, the gross balances presented in the table above are not indicative of Laclede Gas’ net economic exposure. Refer to Note 9, Fair Value Measurements, for information on the valuation of derivative instruments.

Following is a reconciliation of the amounts in the tables above to the amounts presented in Laclede Gas’ Balance Sheets:

	2016			2015
Fair value of asset derivatives presented above	$	5.7		$	1.2
Fair value of cash margin receivables offset with derivatives	0.8			15.5
Netting of assets and liabilities with the same counterparty	(1.6		)	(16.7		)
Total	$	4.9		$	—
Derivative Instrument Assets, per Balance Sheets:
Derivative instrument assets	$	4.9		$	—
Total	$	4.9		$	—
Fair value of liability derivatives presented above	$	1.8		$	22.6
Netting of assets and liabilities with the same counterparty	(1.6		)	(16.7		)
Total	$	0.2		$	5.9
Derivative Instrument Liabilities, per Balance Sheets:
Current Liabilities – Other	$	0.2		$	5.7
Deferred Credits – Other	—			0.2
Total	$	0.2		$	5.9

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Additionally, at September 30, 2016 and 2015, Laclede Gas had $0.5 and $5.9, respectively, in cash margin receivables not offset with derivatives, which are presented in Accounts Receivable – Other.

Alagasco

In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the GSA rider in accordance with Alagasco’s APSC approved tariff.

During the second quarter of fiscal year 2015, Alagasco entered into certain interest rate swap transactions to protect itself against adverse movement in interest rates in anticipation of its issuance of $115.0 of long-term debt. Alagasco received prior approval from the APSC to enter into these hedges. The notional amount of interest rate swaps outstanding was $80.5 with stated maturities ranging from 2025 to 2045 and fixed interest rates ranging between 2.18% and 2.85%. In April 2015, Alagasco entered into an additional hedge with a notional amount of $24.0 and terms within the same range. These derivative instruments were designated as cash flow hedges of forecasted transactions. These forward starting swaps involved the payment of a fixed interest rate and the receipt of LIBOR over the terms specified in the contracts. On May 21, 2015, the interest rate swap agreements were terminated and the settlement resulted in a $2.7 gain which was recorded as a regulatory liability. Of the total issuance of long-term debt, $35.0 was issued on September 15, 2015 and the remaining $80.0 was issued on December 1, 2015.

During the fiscal second quarter of 2016, Alagasco commenced a gasoline derivative program to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At September 30, 2016, Alagasco held 0.6 million gallons of gasoline futures contracts at an average price of $1.53 per gallon. Most of these contracts, the longest of which extends to December 2017, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815, “Derivatives and Hedging.” The gains or losses on these derivative instruments are not subject to Alagasco’s GSA clause. As of September 30, 2016, the fair value of related gasoline contracts was not significant.

11.    CONCENTRATIONS OF CREDIT RISK

Other than in LER (the Gas Marketing segment), Spire has no significant concentration of credit risk.

A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to $15.8 at September 30, 2016 ($12.4 reflecting netting arrangements). LER’s accounts receivable attributable to utility companies and their marketing affiliates comprised $52.8 of total accounts receivable at September 30, 2016 ($50.5 reflecting netting arrangements).

LER also has concentrations of credit risk with certain individually significant counterparties and with pipeline companies associated with its natural gas receivable amount. At September 30, 2016, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure) totaled $31.2 ($27.2 reflecting netting arrangements). These five counterparties are either investment-grade rated or owned by investment-grade rated companies.

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12. INCOME TAXES

Spire

The Company’s provision for income taxes charged during the fiscal years ended September 30, 2016, 2015, and 2014 are as follows:

	2016			2015			2014
Federal
Current	$	0.1		$	(3.3	)	$	0.3
Deferred	62.0			58.8			30.6
Investment tax credits	(0.2		)	(0.2		)	(0.2		)
State and local
Current	0.6			—			0.6
Deferred	7.0			6.9			1.0
Total income tax expense	$	69.5		$	62.2		$	32.3

The Company’s effective income tax rate varied from the federal statutory income tax rate for each year due to the following:

	2016		2015		2014
Federal income tax statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal income tax benefits	2.8		3.0		1.8
Certain expenses capitalized on books and deducted on tax return	(3.4	)	(3.7	)	(4.9	)
Taxes related to prior years	(0.2	)	(0.6	)	(0.7	)
Other items – net *	(1.7	)	(2.5	)	(3.6	)
Effective income tax rate	32.5	%	31.2	%	27.6	%

* Other consists primarily of property adjustments.

The Company’s significant items comprising the net deferred tax liability recorded in the Consolidated Balance Sheets as of September 30 are as follows:

	2016		2015
Deferred tax assets:
Reserves not currently deductible	$	21.3	$	14.8
Pension and other postretirement benefits	68.3		62.5
Operating losses	102.3		47.3
Other	—		1.5
Deferred tax assets	191.9		126.1
Less: valuation allowance	0.9		—
Total deferred tax assets	191.0		126.1
Deferred tax liabilities:
Relating to property	623.1		472.1
Regulatory pension and other postretirement benefits	106.8		110.6
Deferred gas costs	20.0		8.1
Other	48.4		11.6
Total deferred tax liabilities	798.3		602.4
Net deferred tax liability	607.3		476.3
Net deferred tax asset – current	—		5.8
Net deferred tax liability – noncurrent	$	607.3	$	482.1

In assessing whether deferred tax assets are realizable, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all significant available positive and negative evidence, including the existence of losses in recent years, the timing of deferred tax liability reversals, projected future taxable income, taxable income in carryback years, and tax planning strategies to

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assess the need for a valuation allowance. Based upon this evidence, management believes it is more likely than not the Company will realize the benefits of these deferred tax assets.

The Company has federal and state loss carryforwards of approximately $297.0 at September 30, 2016. The Company also has contribution carryforwards of approximately $12.2 at September 30, 2016. The loss carryforwards begin to expire in the fiscal year ending 2030 for certain state purposes and 2035 for federal and other states purposes. The contribution carryforwards begin to expire in fiscal year 2017. The Company has established a valuation allowance of $0.9 during the fiscal year as a portion of the charitable contribution carryforward will not be realized prior to its expiration. The Company also has various tax credit carryforwards of approximately $3.5 that begin to expire in 2017.

The Company recognizes the tax benefit from a tax position only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The Company records potential interest and penalties related to its uncertain tax positions as interest expense and other income deductions, respectively. Unrecognized tax benefits, accrued interest payable, and accrued penalties payable are reported as a reduction of a deferred tax asset for an operating loss carryforward.

The following table presents a reconciliation of the beginning and ending balances of the Company’s unrecognized tax benefits:

	2016			2015			2014
Unrecognized tax benefits, beginning of year	$	7.1		$	4.6		$	2.4
Increases related to tax positions taken in current year	3.4			2.9			2.6
Reductions due to lapse of applicable statute of limitations	(0.5		)	(0.4		)	(0.4		)
Unrecognized tax benefits, end of year	$	10.0		$	7.1		$	4.6

The amount of unrecognized tax benefits which, if recognized, would affect the Company’s effective tax rate were $3.3 and $3.1 as of September 30, 2016 and 2015, respectively. It is reasonably possible that events will occur in the next 12 months that could increase or decrease the amount of the Company’s unrecognized tax benefits. The Company does not expect that any such change will be significant to the Consolidated Balance Sheets.

As of September 30, 2016 and 2015, interest accrued associated with the Company’s uncertain tax positions was de minimis, and no penalties were accrued as of September 30, 2016.

The Company is subject to US federal income tax as well as income tax in various state and local jurisdictions. The Company is no longer subject to examination for fiscal years prior to 2013.

Regarding the Company’s recent EnergySouth acquisition, tax returns for the calendar years 2013 through 2015 remain open and subject to examination by the Internal Revenue Service and state taxing jurisdictions. These returns cover periods during which EnergySouth was owned by Sempra Global. The impact of any adjustments made to these returns by the relevant taxing authorities would be addressed by the indemnification provisions of the stock purchase agreement with Sempra Global.

Laclede Gas

Laclede Gas’ provision for income taxes charged during the fiscal years ended September 30, 2016, 2015, and 2014 are as follows:

	2016			2015			2014
Federal
Current	$	—		$	(2.1	)	$	(0.1	)
Deferred	37.5			40.9			34.3
Investment tax credits	(0.2		)	(0.2		)	(0.2		)
State and local
Current	0.1			(0.1		)	—
Deferred	8.0			4.7			1.5
Total income tax expense	$	45.4		$	43.2		$	35.5

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Laclede Gas’ effective income tax rate varied from the federal statutory income tax rate for each year due to the following:

	2016		2015		2014
Federal income tax statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal income tax benefits	2.8		2.8		1.8
Certain expenses capitalized on books and deducted on tax return	(4.8	)	(4.9	)	(4.5	)
Taxes related to prior years	(0.2	)	(0.8	)	(0.7	)
Other items – net *	(2.8	)	(3.0	)	(3.3	)
Effective income tax rate	30.0	%	29.1	%	28.3	%

* Other consists primarily of property adjustments.

Laclede Gas’ significant items comprising the net deferred tax liability reported in the Balance Sheets as of September 30 are as follows:

	2016		2015
Deferred tax assets:
Reserves not currently deductible	$	14.9	$	15.4
Pension and other postretirement benefits	56.9		62.5
Operating losses	29.9		3.7
Other	—		1.5
Deferred tax assets	101.7		83.1
Less: valuation allowance	0.9		—
Total deferred tax assets	100.8		83.1
Deferred tax liabilities:
Relating to utility property	497.0		425.0
Regulatory pension and other postretirement benefits	106.8		120.2
Deferred gas costs	20.0		8.2
Other	33.9		14.5
Total deferred tax liabilities	657.7		567.9
Net deferred tax liability	556.9		484.8
Net deferred tax asset – current	—		0.4
Net deferred tax liability – noncurrent	$	556.9	$	485.2

Spire files a consolidated federal return and various state income tax returns and allocates income taxes to Laclede Gas and its other subsidiaries as if each entity were a separate taxpayer.

In assessing whether deferred tax assets are realizable, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all significant available positive and negative evidence, including the existence of losses in recent years, the timing of deferred tax liability reversals, projected future taxable income, taxable income in carryback years, and tax planning strategies to assess the need for a valuation allowance. Based upon this evidence, management believes it is more likely than not that Laclede Gas will realize the benefits of these deferred tax assets.

Laclede Gas has state and federal loss carryforwards of approximately $105.0, at September 30, 2016, based on a separate company basis. For federal tax purposes, these loss carryforwards may be utilized against income from another member of the consolidated group. Laclede Gas also has contribution carryforwards of approximately $12.0 at September 30, 2016. The loss carryforwards begin to expire in the fiscal year ending 2035 for federal and state purposes. The contribution carryforwards begin to expire in fiscal year ending 2017. Laclede Gas has established a valuation allowance of $0.9 during the fiscal year as a portion of the charitable contribution carryforward will not be realized prior to its expiration. Laclede Gas also has approximately $2.0 of various tax credit carryforwards with expiration dates which begin to expire in 2017.

Laclede Gas recognizes the tax benefit from a tax position only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. Laclede Gas records potential interest and penalties related to its uncertain tax positions as interest expense and other income deductions, respectively. Unrecognized tax benefits, accrued interest payable, and accrued penalties payable are reported as a reduction of a deferred tax asset for an operating loss carryforward.

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The following table presents a reconciliation of the beginning and ending balances of Laclede Gas unrecognized tax benefits:

	2016			2015			2014
Unrecognized tax benefits, beginning of year	$	6.9		$	4.2		$	2.0
Increases related to tax positions taken in current year	3.3			2.9			2.5
Reductions due to lapse of applicable statute of limitations	(0.5		)	(0.2		)	(0.3		)
Unrecognized tax benefits, end of year	$	9.7		$	6.9		$	4.2

The amount of unrecognized tax benefits, which, if recognized, would affect Laclede Gas’ effective tax rate were $3.1 and $2.9 as of September 30, 2016 and 2015, respectively. It is reasonably possible that events will occur in the next 12 months that could increase or decrease the amount of Laclede Gas’ unrecognized tax benefits. Laclede Gas does not expect that any such change will be significant to Laclede Gas’ Balance Sheets.

As of September 30, 2016 and 2015, interest accrued associated with Laclede Gas’ uncertain tax positions was de minimis, and no penalties were accrued.

Laclede Gas is subject to US federal income tax as well as income tax in various state and local jurisdictions, and is no longer subject to examination for fiscal years prior to 2013.

Alagasco

Alagasco’s provision for income taxes charged during the fiscal years ended September 30, 2016 and 2015, and the nine months ended September 30, 2014, are as follows:

	Year Ended September 30,			Year Ended September 30,		Nine Months Ended September 30,
	2016			2015		2014
Federal
Current	$	(0.8	)	$	—	$	14.1
Deferred	29.4			25.9		3.5
State and local
Current	—			0.1		1.8
Deferred	3.8			3.3		0.5
Total income tax expense	$	32.4		$	29.3	$	19.9

Alagasco’s effective income tax rate varied from the federal statutory income tax rate for each year due to the following:

	Year Ended September 30,		Year Ended September 30,		Nine Months Ended September 30,
	2016		2015		2014
Federal income tax statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal income tax benefits	2.8		2.8		2.8
Other items – net	0.1		0.1		(0.2	)
Effective income tax rate	37.9	%	37.9	%	37.6	%

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Alagasco’s significant items comprising the net deferred tax asset reported in the Balance Sheets as of September 30 are as follows:

	2016		2015
Deferred tax assets:
Reserves not currently deductible	$	6.3	$	7.0
Pension and other postretirement benefits	11.4		9.6
Goodwill	233.4		251.5
Operating losses	60.2		32.4
Other	—		1.4
Total deferred tax assets	311.3		301.9
Deferred tax liabilities:
Relating to utility property	87.6		45.1
Other	2.3		2.2
Total deferred tax liabilities	89.9		47.3
Net deferred tax asset	221.4		254.6
Net deferred tax asset – current	—		6.2
Net deferred tax asset – noncurrent	$	221.4	$	248.4

Spire files a consolidated federal return and various state income tax returns and allocates income taxes to Alagasco and its other subsidiaries as if each entity were a separate taxpayer.

In assessing whether deferred tax assets are realizable, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all significant available positive and negative evidence, including the existence of losses in recent years, the timing of deferred tax liability reversals, projected future taxable income, taxable income in carryback years, and tax planning strategies to assess the need for a valuation allowance. Based upon this evidence, management believes it is more likely than not that Alagasco will realize the benefits of these deferred tax assets.

On a separate company basis, Alagasco has state and federal loss carryforwards of approximately $159.0, at September 30, 2016 generated since the acquisition. The loss carryforwards begin to expire in the fiscal year ending 2030 for state purposes and 2035 for federal purposes. For federal tax purposes, these loss carryforwards may be utilized against income from another member of the consolidated group.

Alagasco recognizes the tax benefit from a tax position only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. Alagasco records potential interest and penalties related to its uncertain tax positions as interest expense and other income deductions, respectively. Alagasco has reported no unrecognized tax benefits since the acquisition by Spire in August 2014.

The following table presents a reconciliation of the beginning and ending balances of Alagasco’s unrecognized tax benefits:

	Year Ended September 30,		Year Ended September 30,		Nine Months Ended September 30,
	2016		2015		2014
Unrecognized tax benefits, beginning of period	$	—	$	—	$	0.3
Reduction for transfer of balance to Energen	—		—		(0.3		)
Unrecognized tax benefits, end of period	$	—	$	—	$	—

Alagasco is subject to US federal income tax as well as income tax in various state and local jurisdictions. Alagasco’s tax returns for the periods after 2012 remain open and subject to examination by the Internal Revenue Service and state taxing jurisdictions. The returns covering 2013 and 2014 include periods during which Alagasco was owned by Energen. The impact of any adjustments made to those returns by the relevant taxing authorities would be addressed by the indemnification provisions of the stock purchase agreement with Energen.

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13.     PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

The Spire information in this note reflects all plans of the Company, including information for plans of EnergySouth since September 12, 2016 and Alagasco since August 31, 2014. The net pension and postretirement obligations were re-measured at those acquisition dates as well as at the fiscal year end.

Pension Plans

The pension plans of Spire consist of plans for employees at the Missouri Utilities, plans covering the employees of Alagasco, and plans covering employees for EnergySouth.

The Missouri Utilities have non-contributory, defined benefit, trusteed forms of pension plans covering the majority of their employees. Plan assets consist primarily of corporate and US government obligations and a growth segment consisting of exposure to equity markets, commodities, real estate and inflation-indexed securities, achieved through derivative instruments and investments in diversified mutual funds.

Alagasco has non-contributory, defined benefit, trusteed forms of pension plans covering the majority of its employees. Qualified plan assets are comprised of United States equities consisting of mutual and commingled funds with varying strategies, global equities consisting of mutual funds, alternative investments of limited partnerships and commingled and mutual funds, and fixed income investments.

The net periodic pension costs include the following components:

	Spire									Laclede Gas									Alagasco
	2016			2015			2014			2016			2015			2014			2016			2015			2014*
Service cost – benefits earned during the period	$	15.3		$	17.3		$	10.2		$	10.0		$	11.5		$	9.7		$	5.3		$	5.8		$	5.1
Interest cost on projected benefit obligation	28.0			29.5			24.5			21.7			23.3			24.0			6.3			6.2			4.1
Expected return on plan assets	(34.9		)	(37.4		)	(27.2		)	(26.7		)	(29.2		)	(26.5		)	(8.2		)	(8.2		)	(5.2		)
Amortization of other comprehensive income	—			—			0.4			—			—			—			—			—			—
Amortization of prior service cost	0.4			0.5			0.5			0.4			0.5			0.5			—			—			0.1
Amortization of actuarial loss	8.0			7.5			7.1			7.9			7.5			7.1			0.1			—			2.2
Loss on lump-sum settlements	3.3			19.6			1.5			—			18.0			1.5			3.3			1.6			10.1
Special termination benefits	1.6			—			—			1.6			—			—			—			—			—
Subtotal	21.7			37.0			17.0			14.9			31.6			16.3			6.8			5.4			16.4
Regulatory adjustment	17.8			(2.1		)	10.4			11.7			(5.2		)	10.4			6.1			3.1			0.4
Net pension cost	$	39.5		$	34.9		$	27.4		$	26.6		$	26.4		$	26.7		$	12.9		$	8.5		$	16.8
													* Nine months ended September 30

Other changes in plan assets and pension benefit obligations recognized in other comprehensive income or loss (OCI) include the following:

	Spire									Laclede Gas									Alagasco
	2016			2015			2014			2016			2015			2014			2016			2015			2014*
Current year actuarial loss	$	46.8		$	48.3		$	15.7		$	21.6		$	26.0		$	14.2		$	25.2		$	22.3		$	1.5
Amortization of actuarial loss	(8.0		)	(7.5		)	(7.1		)	(7.9		)	(7.5		)	(7.1		)	(0.1		)	—			—
Acceleration of loss recognized due to settlement	(3.3		)	(19.6		)	(1.5		)	—			(18.0		)	(1.5		)	(3.3		)	(1.6		)	—
Amortization of current year service cost	5.0			—			—			5.0			—			—			—			—			—
Amortization of prior service cost	(0.4		)	(0.5		)	(0.5		)	(0.4		)	(0.5		)	(0.5		)	—			—			—
Subtotal	40.1			20.7			6.6			18.3			—			5.1			21.8			20.7			1.5
Regulatory adjustment	(39.8		)	(21.2		)	(6.1		)	(18.0		)	(0.5		)	(4.7		)	(21.8		)	(20.7		)	(1.5		)
Total recognized in OCI	$	0.3		$	(0.5	)	$	0.5		$	0.3		$	(0.5	)	$	0.4		$	—		$	—		$	—
													* Nine months ended September 30

Spire pension obligations are driven by separate plan and regulatory provisions governing Laclede Gas, Alagasco and EnergySouth pension plans.

Pursuant to the provisions of the Missouri Utilities’ and Alagasco’s pension plans, pension obligations may be satisfied by lump-sum cash payments. Lump-sum payments are recognized as settlements (which can result in gains or losses) only if the total of such payments exceeds 100% of the sum of service and interest costs in a specific

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year. Special termination benefits, when offered, are also recognized as settlements which can result in gains or losses. Two Alagasco plans and one Laclede plan met the criteria for settlement recognition in the fiscal year ended September 30, 2016, requiring re-measurement of the obligation under those plans using updated census data and assumptions for discount rate and mortality. Lump-sum payments recognized as settlements during fiscal year 2016, 2015, and 2014 were $16.6 (attributable to Alagasco), $71.1, and $22.1, respectively.

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains or losses not yet includible in pension cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas’ eastern Missouri qualified pension plan is based on an annual allowance of $15.5 effective January 1, 2011. The recovery in rates for MGE’s qualified pension plan is based on an annual allowance of $10 effective February 20, 2010. The difference between these amounts and pension expense as calculated pursuant to the above and that otherwise would be included in the statements of income and statements of comprehensive income is deferred as a regulatory asset or regulatory liability.

The following table shows the reconciliation of the beginning and ending balances of the pension benefit obligation at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Benefit obligation, beginning of year	$	652.3		$	692.4		$	497.6		$	543.6		$	154.7		$	148.8
Service cost	15.3			17.3			10.0			11.5			5.3			5.8
Interest cost	28.0			29.5			21.7			23.3			6.3			6.2
Actuarial loss (gain)	85.8			(12.8		)	59.2			(20.7		)	26.6			7.9
Plan amendments	5.1			—			5.1			—			—			—
EnergySouth acquisition	60.4			—			—			—			—			—
Settlement loss	1.1			16.5			—			14.5			1.1			2.0
Special termination benefits	1.6			—			1.6			—			—			—
Settlement benefits paid	(16.6		)	(71.1		)	—			(58.2		)	(16.6		)	(12.9		)
Regular benefits paid	(38.3		)	(19.5		)	(35.2		)	(16.4		)	(3.1		)	(3.1		)
Benefit obligation, end of year	$	794.7		$	652.3		$	560.0		$	497.6		$	174.3		$	154.7
Accumulated benefit obligation, end of year	724.5			$	591.4		517.7			$	456.9		149.8			$	134.5

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Fair value of plan assets, beginning of year	$	448.9		$	506.6		$	339.9		$	387.4		$	109.0		$	119.2
Actual return on plan assets	75.1			(7.2		)	64.4			(3.0		)	10.7			(4.2		)
Employer contributions	26.6			40.1			26.6			30.1			—			10.0
EnergySouth acquisition	44.8			—			—			—			—			—
Settlement benefits paid	(16.6		)	(71.1		)	—			(58.2		)	(16.6		)	(12.9		)
Regular benefits paid	(38.3		)	(19.5		)	(35.2		)	(16.4		)	(3.1		)	(3.1		)
Fair value of plan assets, end of year	$	540.5		$	448.9		$	395.7		$	339.9		$	100.0		$	109.0
Funded status of plans, end of year	$	(254.2	)	$	(203.4	)	$	(164.3	)	$	(157.7	)	$	(74.3	)	$	(45.7	)

The following table sets forth the amounts recognized in the balance sheets at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Current liabilities	$	(0.6	)	$	(0.5	)	$	(0.6	)	$	(0.5	)	$	—		$	—
Noncurrent liabilities	(253.6		)	(202.9		)	(163.7		)	(157.2		)	(74.3		)	(45.7		)
Total	$	(254.2	)	$	(203.4	)	$	(164.3	)	$	(157.7	)	$	(74.3	)	$	(45.7	)

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Pre-tax amounts recognized in accumulated other comprehensive loss not yet recognized as components of net periodic pension cost consist of:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Net actuarial loss	$	179.4		$	143.9		$	135.5		$	121.9		$	43.9		$	22.0
Prior service costs	8.2			3.5			8.2			3.5			—			—
Subtotal	187.6			147.4			143.7			125.4			43.9			22.0
Adjustments for amounts included in regulatory assets	(184.8		)	(144.9		)	(140.9		)	(122.9		)	(43.9		)	(22.0		)
Total	$	2.8		$	2.5		$	2.8		$	2.5		$	—		$	—

At September 30, 2016, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive loss into net periodic pension cost during fiscal year 2017:

	Spire			Laclede Gas			Alagasco
Amortization of net actuarial loss	$	13.5		$	11.6		$	1.9
Amortization of prior service cost	1.0			1.0			—
Subtotal	14.5			12.6			1.9
Regulatory adjustment	(14.2		)	(12.3		)	(1.9		)
Total	$	0.3		$	0.3		$	—

The assumptions used to calculate net periodic pension costs for Laclede Gas are as follows:

	2016	2015	2014
Weighted average discount rate - Laclede Gas division plans	4.40%	4.30%	4.70%
Weighted average discount rate - MGE division plans	4.50%	4.45%	5.00%
Weighted average rate of future compensation increase *	3.00%	3.00%	3.00%
Expected long-term rate of return on plan assets *	7.75%	7.75%	7.75%

* Assumptions for weighted average rate of future compensation increase and expected long-term rate of return on plan assets are the same for both Laclede Gas and MGE plans.

The assumptions used to calculate net periodic pension costs for Alagasco are as follows:

	2016	2015	2014*
Weighted average discount rate	4.25% /4.30%	4.15% /4.25%	4.00% / 4.05%
Weighted average rate of future compensation increase	3.00%	2.92%	2.92%
Expected long-term rate of return on plan assets	7.50%	7.00% / 7.25%	7.00% / 7.25%

* Nine-month transition period ended September 30

The weighted average discount rate is based on long-term, high quality bond indices at the measurement date. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns. The overall expected rate of return for the portfolio was developed based on the target allocation for each class.

The assumptions used to calculate the benefit obligations are as follows:

	2016	2015
Weighted average discount rate - Laclede Gas division	3.50%	4.40%
Weighted average discount rate - MGE division	3.50%	4.50%
Weighted average discount rate - Alagasco	3.45%/3.50%	4.25%/4.30%
Weighted average rate of future compensation increase - Laclede Gas, Alagasco and MGE	3.00%	3.00%

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Following are the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for plans that have a projected benefit obligation and an accumulated benefit obligation in excess of plan assets:

	Spire				Laclede Gas				Alagasco
	2016		2015		2016		2015		2016		2015
Projected benefit obligation	$	794.8	$	652.3	$	560.0	$	497.6	$	174.3	$	154.7
Accumulated benefit obligation	724.5		591.4		517.7		456.9		149.8		134.5
Fair value of plan assets	540.5		448.9		395.7		339.9		100.0		109.0

Following are the targeted and actual plan assets by category as of September 30 of each year for Laclede Gas and Alagasco:

Laclede Gas	2016 Target		2016 Actual		2015 Target		2015 Actual
Equity markets	56.2	%	56.9	%	52.0	%	48.4	%
Debt securities	43.8	%	43.1	%	48.0	%	50.1	%
Other*	—	%	—	%	—	%	1.5	%
Total	100.0	%	100.0	%	100.0	%	100.0	%

* Other investments in 2016 and 2015 consisted of cash equivalents.

Alagasco	2016 Target		2016 Actual		2015 Target		2015 Actual
Equity markets	60.0	%	59.2	%	60.0	%	52.9	%
Debt securities	29.0	%	28.8	%	29.0	%	27.9	%
Other*	11.0	%	12.0	%	11.0	%	19.2	%
Total	100.0	%	100.0	%	100.0	%	100.0	%

* Other investments in 2016 included cash, real estate, commodities, natural resources and TIPS. In 2015, this included cash and cash equivalents, hedge funds, real estate, and all asset funds, which can invest in equities or fixed income.

Laclede Gas’ investment policies are designed to maximize, to the extent possible, the funded status of the plan over time, and minimize volatility of funding and costs. The policy seeks to maximize investment returns consistent with these objectives and Laclede Gas’ tolerance for risk. The duration of plan liabilities and the impact of potential changes in asset values on the funded status are fundamental considerations in the selection of plan assets. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with the policy. The policy seeks to avoid significant concentrations of risk by investing in a diversified portfolio of assets. Investments in corporate, US government and agencies, and, to a lesser extent, international debt securities seek to provide duration matching with plan liabilities, and typically have investment grade ratings and reflect allocations across various entities and industries. There are also exposures to additional asset types in the target portfolio: commodities, real estate and inflation-indexed securities. During 2015, the target portfolio was rebalanced to include a higher weighting for the growth (equity) component and a lower weighting to the liability-driven (debt) component. The investment policy permits the use of derivative instruments, which may be used to achieve the desired market exposure of an index, adjust portfolio duration, or rebalance the total portfolio to the target asset allocation. The Growth Strategy utilizes a combination of derivative instruments and debt securities to achieve diversified exposure to equity and other markets while generating returns from the fixed-income investments and providing further duration matching with the liabilities. Performance and compliance with the guidelines is regularly monitored. The policy calls for increased allocations to debt securities as the funded status improves.

Alagasco employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions. Alagasco has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by Alagasco to manage separate pools of assets. Funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment managers are performing satisfactorily. Alagasco seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class.

117

Accordingly, plan assets for the pension plans do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

Following are expected pension benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter, for Spire, Laclede Gas, and Alagasco:

	2017		2018		2019		2020		2021		2022- 2026
Spire	$	61.3	$	56.2	$	57.1	$	56.6	$	56.8	$	286.3
Laclede Gas	48.2		43.3		43.5		42.2		40.4		196.6
Alagasco	10.9		10.6		11.2		11.9		13.7		74.5

The funding policy of Laclede Gas and Alagasco is to contribute an amount not less than the minimum required by government funding standards, nor more than the maximum deductible amount for federal income tax purposes. Laclede Gas contributions to the pension plans in fiscal year 2017 are anticipated to be $29.0 into the qualified trusts, and $0.6 into the non-qualified plans. Alagasco has no required contributions to the qualified pension plans during 2017. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. During fiscal 2017, Alagasco may make additional discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions.

Postretirement Benefits

The Utilities provide certain life insurance benefits at retirement. Laclede Gas plans provide for medical insurance after early retirement until age 65. For retirements prior to January 1, 2015, the MGE plans provided medical insurance after retirement until death. For retirements after January 1, 2015, the MGE plans provide medical insurance after early retirement until age 65. Under the Alagasco plans, medical insurance is currently available upon retirement until death for certain retirees depending on the type of employee and the date the employee was originally hired.

Net periodic postretirement benefit costs consist of the following components:

	Spire									Laclede Gas									Alagasco
	2016			2015			2014			2016			2015			2014			2016			2015			2014*
Service cost – benefits earned during the period	$	10.9		$	12.8		$	11.3		$	10.6		$	12.3		$	11.2		$	0.3		$	0.5		$	0.4
Interest cost on accumulated postretirement benefit obligation	10.2			11.2			8.9			8.1			8.6			8.7			2.1			2.6			1.9
Expected return on plan assets	(13.5		)	(13.2		)	(7.3		)	(8.5		)	(8.1		)	(6.8		)	(5.0		)	(5.1		)	(3.6		)
Amortization of prior other comprehensive loss	—			—			(0.2		)	—			—			—			—			—			—
Amortization of prior service cost	0.3			0.8			—			0.3			0.8			—			—			—			—
Amortization of actuarial loss (gain)	3.6			5.1			6.0			3.8			5.1			6.0			(0.2		)	—			(1.0		)
Special termination benefits	2.6			—			—			2.6			—			—			—			—			—
Subtotal	14.1			16.7			18.7			16.9			18.7			19.1			(2.8		)	(2.0		)	(2.3		)
Regulatory adjustment	(6.6		)	(11.0		)	(9.6		)	(4.8		)	(9.2		)	(9.6		)	(1.8		)	(1.8		)	(0.2		)
Net postretirement benefit cost	$	7.5		$	5.7		$	9.1		$	12.1		$	9.5		$	9.5		$	(4.6	)	$	(3.8	)	$	(2.5	)
													* Nine months ended September 30

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Other changes in plan assets and postretirement benefit obligations recognized in OCI include the following:

	Spire									Laclede Gas									Alagasco
	2016			2015			2014			2016			2015			2014			2016			2015			2014*
Current year actuarial loss (gain)	$	0.8		$	(8.5	)	$	(3.1	)	$	1.4		$	(2.4	)	$	(4.2	)	$	(0.6	)	$	(6.1	)	$	1.1
Amortization of actuarial (loss) gain	(3.6		)	(5.1		)	(6.0		)	(3.8		)	(5.1		)	(6.0		)	0.2			—			—
Amortization of prior service (cost) credit	(0.3		)	(0.8		)	2.5			(0.3		)	(0.8		)	2.5			—			—			—
Current year prior service credit	(1.8		)	(4.9		)	—			—			(4.9		)	—			(1.8		)	—			—
Subtotal	(4.9		)	(19.3		)	(6.6		)	(2.7		)	(13.2		)	(7.7		)	(2.2		)	(6.1		)	1.1
Regulatory adjustment	4.9			19.3			6.6			2.7			13.2			7.7			2.2			6.1			(1.1		)
Total recognized in OCI	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
													* Nine months ended September 30

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains and losses not yet includible in postretirement benefit cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the accumulated postretirement benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas’ postretirement benefit plans is based on an annual allowance of $9.5 effective January 1, 2011. The difference between these amounts and postretirement benefit cost based on the above and that otherwise would be included in the statements of income and statements of comprehensive income is deferred as a regulatory asset or regulatory liability.

The following table sets forth the reconciliation of the beginning and ending balances of the postretirement benefit obligation at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Benefit obligation, beginning of year	$	239.2		$	258.5		$	191.9		$	197.9		$	47.3		$	60.6
Service cost	10.9			12.8			10.6			12.3			0.3			0.5
Interest cost	10.2			11.2			8.1			8.6			2.1			2.6
Actuarial loss (gain)	7.1			(23.7		)	6.7			(10.9		)	0.4			(12.8		)
Plan amendments	(1.8		)	(4.9		)	—			(4.9		)	(1.8		)	—
EnergySouth acquisition	5.9			—			—			—			—			—
Special termination benefits	2.6			—			2.6			—			—			—
Retiree drug subsidy program	0.2			0.4			—			—			0.2			0.4
Gross benefits paid	(15.1		)	(15.1		)	(12.0		)	(11.1		)	(3.1		)	(4.0		)
Benefit obligation, end of year	$	259.2		$	239.2		$	207.9		$	191.9		$	45.4		$	47.3

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Fair value of plan assets at beginning of year	$	223.3		$	222.5		$	143.6		$	137.2		$	79.7		$	85.3
Actual return on plan assets	19.9			(2.0		)	13.8			(0.4		)	6.2			(1.6		)
Employer contributions	14.3			17.9			14.3			17.9			—			—
EnergySouth acquisition	4.0			—			—			—			—			—
Gross benefits paid	(15.1		)	(15.1		)	(12.0		)	(11.1		)	(3.1		)	(4.0		)
Fair value of plan assets, end of year	$	246.4		$	223.3		$	159.7		$	143.6		$	82.8		$	79.7
Funded status of plans, end of year	$	(12.8	)	$	(15.9	)	$	(48.2	)	$	(48.3	)	$	37.4		$	32.4

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The following table sets forth the amounts recognized in the balance sheets at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016		2015
Current assets	$	0.3		$	—		$	0.3		$	—		$	—	$	—
Noncurrent assets	37.4			35.5			—			3.1			37.4		32.4
Current liabilities	(0.4		)	(0.3		)	(0.4		)	(0.3		)	—		—
Noncurrent liabilities	(50.1		)	(51.1		)	(48.1		)	(51.1		)	—		—
Total	$	(12.8	)	$	(15.9	)	$	(48.2	)	$	(48.3	)	$	37.4	$	32.4

Pre-tax amounts recognized in accumulated other comprehensive loss not yet recognized as components of net periodic postretirement benefit cost consist of:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Net actuarial loss	$	38.0		$	40.8		$	43.4		$	45.8		$	(5.4	)	$	(5.0	)
Prior service credit	(5.2		)	(3.1		)	(3.4		)	(3.1		)	(1.8		)	—
Subtotal	32.8			37.7			40.0			42.7			(7.2		)	(5.0		)
Adjustments for amounts included in regulatory assets	(32.8		)	(37.7		)	(40.0		)	(42.7		)	7.2			5.0
Total	$	—		$	—		$	—		$	—		$	—		$	—

At September 30, 2016, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive loss into net periodic postretirement benefit cost during fiscal year 2017:

	Spire			Laclede Gas			Alagasco
Amortization of net actuarial loss (gain)	$	2.4		$	2.5		$	(0.1	)
Amortization of prior service cost	0.1			0.3			(0.2		)
Subtotal	2.5			2.8			(0.3		)
Regulatory adjustment	(2.5		)	(2.8		)	0.3
Total	$	—		$	—		$	—

The assumptions used to calculate net periodic postretirement benefit costs for Laclede Gas are as follows:

	2016		2015		2014
Weighted average discount rate Laclede Gas division plans	4.00	%	4.15	%	4.60	%
Weighted average discount rate MGE division plans	4.30	%	4.40	%	4.95	%
Weighted average rate of future compensation increase - Laclede Gas plans	3.00	%	3.00	%	3.00	%
Expected long-term rate of return on plan assets - Laclede Gas division plans	6.00% / 7.75%		6.25% / 7.75%		6.25% / 7.75%
Expected long-term rate of return on plan assets - MGE division plans	4.75	%	5.00	%	3.75% / 5.75%

The assumptions used to calculate net periodic postretirement benefit costs for Alagasco are as follows:

	2016		2015		2014
Weighted average discount rate	4.50	%	4.40	%	4.25	%
Weighted average rate of future compensation increase	n/a		n/a		2.92	%
Expected long-term rate of return on plan assets	4.50% / 7.25%		4.75% / 7.50%		4.75% / 7.25%

The weighted average discount rate is based on long-term, high quality bond indices at the measurement date. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns. The overall expected rate of return for the portfolio was developed based on the target allocation for each class.

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The assumptions used to calculate the accumulated postretirement benefit obligations for Laclede Gas are as follows:

	2016		2015
Weighted average discount rate - Laclede Gas division plans	3.15	%	4.00	%
Weighted average discount rate - MGE division plans	3.45	%	4.30	%
Weighted average rate of future compensation increase	3.00	%	3.00	%

The assumptions used to calculate the accumulated postretirement benefit obligations for Alagasco are as follows:

	2016		2015
Weighted average discount rate	3.60	%	4.50	%
Weighted average rate of future compensation increase	n/a		n/a

The assumed medical cost trend rates at September 30 are as follows:

	2016		2015
Medical cost trend assumed for next year - Laclede Gas	7.50	%	7.00	%
Medical cost trend assumed for next year - Alagasco	7.50	%	7.00	%
Rate to which the medical cost trend rate is assumed to decline (the ultimate medical cost trend rate)	5.00	%	5.00	%
Year the rate reaches the ultimate trend	2023		2020

The following table presents the effects of an assumed 1% change in the assumed medical cost trend rate:

	Spire					Laclede Gas					Alagasco
	1% Increase		1% Decrease			1% Increase		1% Decrease			1% Increase		1% Decrease
Net periodic postretirement benefit cost	$	1.5	$	(1.4	)	$	1.5	$	(1.4	)	$	—	$	—
Accumulated postretirement benefit obligation	11.0		(10.2		)	9.0		(8.4		)	1.3		(1.2		)

Following are the targeted and actual plan assets by category as of September 30 of each year for Laclede Gas and Alagasco:

Laclede Gas	Target		2016 Actual		2015 Actual
Equity securities	60.0	%	59.1	%	59.6	%
Debt securities	40.0	%	39.4	%	39.7	%
Other (cash and cash equivalents)	—	%	1.5	%	0.7	%
Total	100.0	%	100.0	%	100.0	%

Alagasco	Target		2016 Actual		2015 Actual
Equity securities	60.0	%	60.5	%	59.7	%
Debt securities	40.0	%	39.5	%	40.3	%
Total	100.0	%	100.0	%	100.0	%

Missouri state law provides for the recovery in rates of costs accrued pursuant to GAAP provided that such costs are funded through an independent, external funding mechanism. Laclede Gas established Voluntary Employees’ Beneficiary Association and Rabbi Trusts as its external funding mechanisms. Laclede Gas’ investment policy seeks to maximize investment returns consistent with Laclede Gas’ tolerance for risk. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with policy. Performance and compliance with the guidelines is regularly monitored. Laclede Gas’ current investment policy targets an asset allocation of 60% to equity securities and 40% to debt securities, excluding cash held in short-term debt securities for the purpose of making benefit payments. Laclede Gas currently invests in a mutual fund which is rebalanced on an ongoing basis to the target allocation. The mutual fund is diversified across US stock and bond markets.

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Alagasco established Voluntary Employees’ Beneficiary Association accounts as its external funding mechanisms for post-retirement benefit costs. Alagasco’s investment policy seeks to maximize investment returns consistent with its tolerance for risk. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with policy. Performance and compliance with the guidelines is regularly monitored. Alagasco’s current investment policy targets an asset allocation of 60% to equity securities and 40% to debt securities. Alagasco currently invests in several mutual funds which are rebalanced periodically to the target allocation. The mutual funds are diversified across US and international stock markets and the US bond market.

Following are expected postretirement benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter for Spire, Laclede Gas, and Alagasco:

	2017		2018		2019		2020		2021		2022- 2026
Spire	$	15.4	$	16.7	$	17.9	$	19.1	$	20.1	$	108.6
Laclede Gas	12.3		13.7		14.8		15.8		16.8		92.5
Alagasco	2.9		2.8		2.8		2.9		2.9		14.1

Laclede Gas’ funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. Contributions to the postretirement plans in fiscal year 2017 are anticipated to be $10.3 to the qualified trusts and $0.4 paid directly to participants from Laclede Gas funds.

Alagasco’s funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. In fiscal 2017, it is not anticipated that contributions will be made to the postretirement plans.

Other Plans

Laclede Gas and Alagasco sponsor 401(k) plans that cover substantially all employees. The plans allow employees to contribute a portion of their base pay in accordance with specific guidelines. Laclede Gas provides a match of such contributions within specific limits. The cost of the defined contribution plans of Laclede Gas amounted to $8.2, $8.0, and $6.7 for fiscal years 2016, 2015, and 2014, respectively. Alagasco also provides a match of employee contributions within specific limits. The cost of the defined contribution plans of Alagasco amounted to $2.3, $3.0, and $4.7 for fiscal years 2016 and 2015, and the nine months ended September 30, 2014, respectively.

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Fair Value Measurements of Pension and Other Postretirement Plan Assets

Spire

The table below categorizes the fair value measurements of the Spire pension plan assets:

	Quoted Prices in Active Markets (Level 1)			Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	51.2		$	—	$	—	$	51.2
Stock/bond mutual fund	99.3			26.7		0.1		126.1
Debt Securities
US bond mutual funds	23.0			126.0		—		149.0
US government	42.1			3.0		—		45.1
US corporate	137.4			—		—		137.4
US municipal	6.3			—		—		6.3
International	25.3			—		—		25.3
Derivatives and margin (payable)	(1.0		)	1.1		—		0.1
Total	$	383.6		$	156.8	$	0.1	$	540.5
As of September 30, 2015
Cash and cash equivalents	$	43.4		$	0.2	$	—	$	43.6
Stock/bond mutual fund	46.4			74.6		9.6		130.6
Debt Securities
US bond mutual funds	—			9.3		—		9.3
US government	58.7			—		—		58.7
US corporate	123.7			42.9		—		166.6
US municipal	—			5.9		—		5.9
International	—			31.3		—		31.3
Derivative instruments	—			2.9		—		2.9
Total	$	272.2		$	167.1	$	9.6	$	448.9

The table below categorizes the fair value measurements of Spire’s postretirement plan assets:

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	4.8	$	—	$	—	$	4.8
US stock/bond mutual fund	157.9		68.5		—		226.4
International fund	0.9		14.3		—		15.2
Total	$	163.6	$	82.8	$	—	$	246.4
As of September 30, 2015
Cash and cash equivalents	$	1.6	$	—	$	—	$	1.6
US stock/bond mutual fund	115.5		92.8		—		208.3
International fund	—		13.4		—		13.4
Total	$	117.1	$	106.2	$	—	$	223.3

Cash and cash equivalents include money market mutual funds valued based on quoted market prices. Fair values of derivative instruments are calculated by investment managers who use valuation models that incorporate observable market inputs. Debt securities are valued based on broker/dealer quotations or by using observable market inputs. The stock and bond mutual funds are valued at the quoted market price of the identical securities.

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Laclede Gas

The table below categorizes the fair value measurements of Laclede Gas’ pension plan assets:

	Quoted Prices in Active Markets (Level 1)			Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	46.5		$	—	$	—	$	46.5
Stock/bond mutual fund	—			14.8		0.1		14.9
Debt Securities
US bond mutual funds	—			120.2		—		120.2
US government	42.1			3.0		—		45.1
US corporate	137.4			—		—		137.4
US municipal	6.3			—		—		6.3
International	25.2			—		—		25.2
Derivatives and margin (payable)	(1.0		)	1.1		—		0.1
Total	$	256.5		$	139.1	$	0.1	$	395.7
As of September 30, 2015
Cash and cash equivalents	$	31.8		$	—	$	—	$	31.8
Stock/bond mutual funds	—			67.6		0.1		67.7
Debt Securities
US government	37.7			—		—		37.7
US corporate	123.7			42.9		—		166.6
US municipal	—			5.9		—		5.9
International	—			27.3		—		27.3
Derivative instruments	—			2.9		—		2.9
Total	$	193.2		$	146.6	$	0.1	$	339.9

The table below categorizes the fair value measurements of Laclede Gas’ postretirement plan assets:

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	4.6	$	—	$	—	$	4.6
US stock/bond mutual funds	155.1		—		—		155.1
Total	$	159.7	$	—	$	—	$	159.7
As of September 30, 2015
Cash and cash equivalents	$	1.6	$	—	$	—	$	1.6
US stock/bond mutual funds	115.5		26.5		—		142.0
Total	$	117.1	$	26.5	$	—	$	143.6

Cash and cash equivalents include money market mutual funds valued based on quoted market prices. Fair values of derivative instruments are calculated by investment managers who use valuation models that incorporate observable market inputs. Debt securities are valued based on broker/dealer quotations or by using observable market inputs. The stock and bond mutual funds are valued at the quoted market price of the identical securities.

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Alagasco

The table below categorizes the fair value measurements of Alagasco’s pension plan assets:

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	0.4	$	—	$	—	$	0.4
Stock/bond mutual funds	59.0		11.9		—		70.9
Debt Securities
US bond mutual funds	23.0		5.7		—		28.7
Total	$	82.4	$	17.6	$	—	$	100.0
As of September 30, 2015
Cash and cash equivalents	$	11.6	$	0.2	$	—	$	11.8
Stock/bond mutual fund	46.4		7.0		9.5		62.9
Debt Securities
US bond mutual funds	—		9.3		—		9.3
US government	—		21.0		—		21.0
International	—		4.0		—		4.0
Derivative instruments (b)	—		—		—		—
Total	$	58.0	$	41.5	$	9.5	$	109.0

The table below categorizes the fair value measurements of Alagasco’s postretirement plan assets:

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
US stock/bond mutual fund	$	—	$	68.5	$	—	$	68.5
International fund	—		14.3		—		14.3
Total	$	—	$	82.8	$	—	$	82.8
As of September 30, 2015
US stock/bond mutual fund	—		66.3		—		66.3
International fund	—		13.4		—		13.4
Total	$	—	$	79.7	$	—	$	79.7

Cash and cash equivalents include money market mutual funds valued based on quoted market prices. Fair values of derivative instruments are calculated by investment managers who use valuation models that incorporate observable market inputs. Debt securities are valued based on broker/dealer quotations or by using observable market inputs. The stock and bond mutual funds are valued at the quoted market price of the identical securities.

14.    INFORMATION BY OPERATING SEGMENT

Spire

The Company has two reportable segments: Gas Utility and Gas Marketing. The Gas Utility segment is the aggregation of the regulated operations of the Utilities. The Gas Marketing segment includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas and related activities, and LER Storage Services, Inc., which utilizes natural gas storage contracts for providing natural gas sales. Other includes:

• unallocated corporate items, including certain debt and associated interest costs,

• Laclede Pipeline Company, a subsidiary of Spire which operates a propane pipeline under Federal Energy Regulatory Commission (FERC) jurisdiction,

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• Spire STL Pipeline, a subsidiary of Spire planning construction of a 70-mile FERC-regulated pipeline to deliver natural gas into eastern Missouri, and

• Spire’s subsidiaries that are engaged in compression of natural gas and risk management, among other activities. All subsidiaries are wholly owned.

Accounting policies are described in Note 1, Summary of Significant Accounting Policies. Intersegment transactions include sales of natural gas from LER to Laclede Gas, sales of natural gas from Laclede Gas to LER, risk management services provided by Laclede Insurance Risk Services, Inc. to Laclede Gas, propane transportation services provided by Laclede Pipeline Company to Laclede Gas, and propane storage services provided by Laclede Gas to Laclede Pipeline Company.

Management evaluates the performance of the operating segments based on the computation of net economic earnings. Net economic earnings exclude from reported net income the after-tax impacts of net unrealized gains and losses and other timing differences associated with energy-related transactions. Net economic earnings also exclude the after-tax impacts related to acquisition, divestiture, and restructuring activities.

	Gas Utility		Gas Marketing			Other				Eliminations			Consolidated
2016
Revenues from external customers	$	1,457.2	$	78.5		$	1.6			$	—		$	1,537.3
Intersegment revenues	2.2		—			3.2				(5.4		)	—
Total Operating Revenues	1,459.4		78.5			4.8				(5.4		)	1,537.3
Operating Expenses
Gas Utility
Natural and propane gas	539.7		—			—				(47.5		)	492.2
Other operation and maintenance	379.3		—			—				(1.8		)	377.5
Depreciation and amortization	136.9		—			—				—			136.9
Taxes, other than income taxes	125.2		—			—				—			125.2
Total Gas Utility Operating Expenses	1,181.1		—			—				(49.3		)	1,131.8
Gas Marketing and Other	—		66.7		(a)	12.6			(b)	43.9			123.2
Total Operating Expenses	1,181.1		66.7			12.6				(5.4		)	1,255.0
Operating Income (Loss)	278.3		11.8			(7.8		)		—			282.3
Net Economic Earnings (Loss)	160.3		6.4			(17.6		)		—			149.1
Capital Expenditures	291.7		—			1.6				—			293.3

	Gas Utility		Gas Marketing			Other				Eliminations			Consolidated
2015
Revenues from external customers	$	1,891.8	$	82.9		$	1.7			$	—		$	1,976.4
Intersegment revenues	4.0		70.5			2.0				(76.5		)	—
Total Operating Revenues	1,895.8		153.4			3.7				(76.5		)	1,976.4
Operating Expenses
Gas Utility
Natural and propane gas	957.6		—			—				(75.2		)	882.4
Other operation and maintenance	391.6		—			—				(1.0		)	390.6
Depreciation and amortization	129.9		—			—				—			129.9
Taxes, other than income taxes	142.1		—			—				—			142.1
Total Gas Utility Operating Expenses	1,621.2		—			—				(76.2		)	1,545.0
Gas Marketing and Other	—		146.6		(a)	12.6			(b)	(0.3		)	158.9
Total Operating Expenses	1,621.2		146.6			12.6				(76.5		)	1,703.9
Operating Income (Loss)	274.6		6.8			(8.9		)		—			272.5
Net Economic Earnings (Loss)	150.4		4.2			(16.3		)		—			138.3
Capital Expenditures	284.4		—			5.4				—			289.8

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	Gas Utility		Gas Marketing			Other				Eliminations			Consolidated
2014
Revenues from external customers	$	1,462.6	$	162.6		$	2.0			$	—		$	1,627.2
Intersegment revenues	5.2		84.0			1.8				(91.0		)	—
Total Operating Revenues	1,467.8		246.6			3.8				(91.0		)	1,627.2
Operating Expenses
Gas Utility
Natural and propane gas	821.8		—			—				(90.1		)	731.7
Other operation and maintenance	288.7		—			—				(0.9		)	287.8
Depreciation and amortization	82.4		—			—				—			82.4
Taxes, other than income taxes	112.0		—			—				—			112.0
Total Gas Utility Operating Expenses	1,304.9		—			—				(91.0		)	1,213.9
Gas Marketing and Other	—		226.4		(a)	20.5			(b)	—			246.9
Total Operating Expenses	1,304.9		226.4			20.5				(91.0		)	1,460.8
Operating Income (Loss)	162.9		20.2			(16.7		)		—			166.4
Net Economic Earnings (Loss)	92.8		10.2			(2.9		)		—			100.1
Capital Expenditures	168.6		—			2.4				—			171.0

(a) Depreciation and amortization for Gas Marketing are included in Gas Marketing Expenses on the Consolidated Statements of Income ($0.1 for 2016, $0.3 for 2015, and $0.4 for 2014).

(b) Depreciation, amortization, and accretion for Other are included in the Other Operating Expenses on the Consolidated Statements of Income ($0.5 for 2016, $0.6 for 2015, and $0.5 for 2014).

Total Assets at End of Year	2016			2015			2014
Gas Utility	$	5,191.9		$	4,686.2		$	4,520.0
Gas Marketing	205.0			160.6			156.7
Other	1,842.4			1,560.2			1,575.7
Eliminations	(1,161.9		)	(1,116.8		)	(1,178.4		)
Total Assets	$	6,077.4		$	5,290.2		$	5,074.0

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings	2016			2015			2014
Net Income (GAAP)	$	144.2		$	136.9		$	84.6
Unrealized gain on energy-related derivatives	(0.1		)	(2.8		)	(1.6		)
Lower of cost or market inventory adjustments	0.2			0.4			(1.1		)
Realized (gain) loss on economic hedges prior      to the sale of the physical commodity	(1.6		)	2.4			(0.4		)
Acquisition, divestiture and restructuring activities	9.2			9.8			29.5
Gain on sale of property	—			(7.6		)	—
Income tax effect of adjustments	(2.8		)	(0.8		)	(10.9		)
Net Economic Earnings	$	149.1		$	138.3		$	100.1

15. REGULATORY MATTERS

The Utilities account for regulated operations in accordance with ASC Topic 980, “Regulated Operations.” This Topic sets forth the application of GAAP for those companies whose rates are established by or are subject to approval by an independent third-party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated

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company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).

The following regulatory assets and regulatory liabilities were reflected in the Balance Sheets as of September 30, 2016 and 2015. Unamortized Purchased Gas Adjustments are also included below, which are reported separately in the current assets and liabilities sections of each balance sheet.

	Spire				Laclede Gas				Alagasco
	2016		2015		2016		2015		2016		2015
Regulatory Assets:
Current:
Pension and postretirement benefit costs	$	27.0	$	22.0	$	20.2	$	15.5	$	6.8	$	6.5
Unamortized purchased gas adjustments	49.7		12.9		43.1		12.9		5.6		—
Other	17.2		5.6		3.7		0.7		8.1		4.9
Total Current Regulatory Assets	93.9		40.5		67.0		29.1		20.5		11.4
Noncurrent:
Future income taxes due from customers	151.3		134.5		151.3		134.5		—		—
Pension and postretirement benefit costs	487.9		448.7		375.7		368.0		98.9		80.7
Cost of removal	130.6		78.9		—		—		130.6		78.9
Purchased gas costs	12.6		24.1		12.6		24.1		—		—
Energy efficiency	25.5		22.3		25.5		22.3		—		—
Other	30.1		29.1		24.7		24.7		1.2		4.0
Total Noncurrent Regulatory Assets	838.0		737.6		589.8		573.6		230.7		163.6
Total Regulatory Assets	$	931.9	$	778.1	$	656.8	$	602.7	$	251.2	$	175.0
Regulatory Liabilities:
Current:
RSE adjustment	$	7.5	$	12.2	$	—	$	—	$	5.0	$	12.2
Unbilled service margin	5.9		6.4		—		—		5.9		6.4
Refundable negative salvage	9.3		10.8		—		—		9.3		10.8
Unamortized purchased gas adjustments	1.7		28.2		—		—		—		28.2
Other	6.2		3.0		1.3		0.6		2.5		2.4
Total Current Regulatory Liabilities	30.6		60.6		1.3		0.6		22.7		60.0
Noncurrent:
Postretirement liabilities	28.9		28.9		—		—		28.9		28.9
Refundable negative salvage	9.4		16.2		—		—		9.4		16.2
Accrued cost of removal	74.8		58.7		55.1		58.7		—		—
Other	17.6		15.5		12.2		11.9		3.4		3.6
Total Noncurrent Regulatory Liabilities	130.7		119.3		67.3		70.6		41.7		48.7
Total Regulatory Liabilities	$	161.3	$	179.9	$	68.6	$	71.2	$	64.4	$	108.7

Regulatory assets are expected to be recovered in rates charged to customers.

A portion of the Company’s regulatory assets are not earning a return and are shown in the schedule below:

	Spire				Laclede Gas
	2016		2015		2016		2015
Future income taxes due from customers	$	151.3	$	134.5	$	151.3	$	134.5
Pension and postretirement benefit costs	240.6		223.7		240.6		223.7
Compensated absences	—		—		—		—
Other	12.9		14.2		12.9		14.2
Total Regulatory Assets Not Earning a Return	$	404.8	$	372.4	$	404.8	$	372.4

All of Alagasco’s regulatory assets currently earn a return.

These regulatory assets are expected to be recovered from customers in future rates. Excluding deferred income taxes and purchased gas adjustment items, as of September 30, 2016 and 2015, approximately $404.8 and $372.4, respectively, of regulatory assets were not earning a rate of return. The Company expects these items to be

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recovered over a period not to exceed 15 years consistent with precedent set by the MoPSC. The portion of the regulatory asset related to pensions and other postemployment benefits that relates to unfunded differences between the projected benefit obligation and plan assets also does not earn a rate of return.

Laclede Gas

On November 12, 2015, the MoPSC approved an incremental Infrastructure System Replacement Surcharge (ISRS) amount of $4.4 for Laclede Gas’ eastern Missouri service territory and $1.9 for MGE, effective December 1, 2015, bringing total annualized ISRS revenue to $19.6 for Laclede Gas’ eastern Missouri service territory and $6.7 for MGE’s service territory. On January 15, 2016, the Missouri Office of the Public Counsel (OPC) filed an appeal to Missouri’s Western District Court of Appeals of the MoPSC’s decision permitting Laclede Gas to update its ISRS applications during the pendency of the case. On September 27, 2016, the Western District affirmed the report and order of the MoPSC.

On May 19, 2016, the MoPSC approved an incremental ISRS amount of $5.4 for Laclede Gas’ eastern Missouri service territory and $3.6 for MGE, effective May 31, 2016, bringing total annualized ISRS revenue to $25.0 for Laclede Gas’ eastern Missouri service territory and $10.3 for MGE’s service territory. On June 30, 2016, the OPC again filed an appeal to Missouri’s Western District Court of Appeals of the MoPSC’s decision permitting Laclede Gas to update its ISRS applications during the pendency of the case. Laclede Gas believes the MoPSC’s decision was lawful and reasonable, and believes the updating process will again be upheld by the Western District and intends to vigorously oppose the appeal.

On September 30, 2016 Laclede Gas filed to increase its ISRS revenues by $5.0 for Laclede Gas’ eastern Missouri service territory and $3.4 for MGE, related to ISRS investments from March 2016 through October 2016. The MoPSC suspended the tariff until January 28, 2017 and directed the MoPSC Staff (Staff) to file a recommendation no later than November 29, 2016.

Laclede Gas previously had authority from the MoPSC to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in capital, and enter into capital lease agreements, all for a total of up to $518.0. This authority was scheduled to expire June 30, 2015. On April 15, 2015, Laclede Gas applied to the MoPSC for a new financing authorization in the amount of $550.0, and on June 24, 2015, the MoPSC granted an extension of the current authorization until the pending application was resolved. On February 10, 2016, the MoPSC issued an order, by a 3-2 vote, authorizing Laclede financing authority for $300.0 for financings placed any time before September 30, 2018. Laclede Gas filed an application for rehearing, which was denied on March 9, 2016. On March 31, 2016, Laclede Gas filed an appeal with the Western District Court of Appeals concerning this matter. On July 20, 2016, Laclede Gas filed its initial brief before the Court. The MoPSC filed its reply brief on September 19, 2016. Laclede Gas filed its final brief on October 4, 2016. Oral arguments are scheduled for November 17, 2016. Laclede Gas issued no securities under this authorization since the decision and $300.0 remained available for issuance as of November 11, 2016.

Alagasco

Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s current RSE order has a term extending beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control, the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco’s allowed range of return on average common equity is 10.5% to 10.95% with an adjusting point of 10.8%. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4% of prior-year revenues. There was no RSE reduction for the January 31, 2016 quarterly point of test. Related to the April 30, 2016 quarterly point of test, Alagasco recorded a $5.8 RSE reduction to operating revenues, which the APSC directed, by order dated June 20, 2016, be applied to the Gas Supply Adjustment (GSA) balance. The RSE reduction for the July 31, 2016 quarterly point of test was $4.8. As of September 30, 2016, Alagasco recorded a $2.7 RSE reduction to operating revenues to bring the expected rate of return on average common equity at the end of the year to within the allowed range of return. The quarterly point of test reductions from rate year 2016 went into effect October 1, 2016 for $4.8 and will go into effect December 1, 2016 for $2.7. On October 26, 2016, as part of their annual update for RSE, Alagasco filed a $1.3 reduction for rate year 2017, which is subject to review by APSC Staff and becomes effective December 1, 2016 unless otherwise ordered by the APSC.

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The inflation-based Cost Control Mechanism (CCM), established by the APSC, allows for annual increases to operations and maintenance (O&M) expense. The CCM range is Alagasco’s 2007 actual rate year O&M expense (Base Year) inflation-adjusted using the June Consumer Price Index For All Urban Consumers each rate year plus or minus 1.75% (Index Range). If rate year O&M expense falls within the Index Range, no adjustment is required. If rate year O&M expense exceeds the Index Range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent that rate year O&M is less than the Index Range, Alagasco benefits by one-half of the difference through future rate adjustments. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. A CCM benefit to the company for such cost saving of $7.8 related to 2016 will be reflected in rates effective December 1, 2016. The CCM benefit was $4.7 for 2015.

16.    COMMITMENTS AND CONTINGENCIES

Commitments

The Company and the Utilities have entered into contracts with various counterparties, expiring on dates through2031, for the storage, transportation, and supply of natural gas. Minimum payments required by the Company under the contracts in place at September 30, 2016 are estimated at $1,647.8. Minimum payments required for Laclede Gas and Alagasco under the contracts are estimated at $1,227.6 and $352.7, respectively. Additional contracts are generally entered into prior to or during the heating season of November through April. The Missouri Utilities recover their costs from customers in accordance with their PGA clause and Alagasco recovers its cost through its GSA rider.

Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $352.7 through August 2020. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 93 Bcf through August 2020.

Laclede Pipeline Company (Pipeline), a wholly owned subsidiary of Spire, is providing liquid propane transportation service to Laclede Gas pursuant to an approved FERC tariff and a contractual arrangement between Pipeline and Laclede Gas. In accordance with the terms of that agreement, Laclede Gas is obligated to pay Pipeline approximately $1.0 annually, at current rates. The agreement renews at the end of each contract year, unless terminated by either party upon provision of at least six months’ notice.

Leases and Guarantees

Aggregate rental expense and annual minimum rental commitments under all leases having an initial or remaining non-cancelable term of more than one year are shown below:

	Aggregate Rental Expense						Minimum Rental Commitments
	2016		2015		2014		2017		2018		2019		2020		2021		Later		Total
Spire	$	11.9	$	14.1	$	6.7	$	10.5	$	7.5	$	7.3	$	6.2	$	6.0	$	53.4	$	90.9
Laclede Gas	4.3		7.6		6.3		2.5		0.9		0.9		0.3		0.1		—		4.7
Alagasco	3.7		4.0		2.0		3.9		2.5		2.5		2.1		2.1		4.9		18.0

The lease agreement covering the primary office space of Spire and its Missouri Utilities extends through February 2035. Laclede Gas has entered into various operating lease agreements for the rental of vehicles and power operated equipment. The lease agreement covering the primary office space of Alagasco extends through February 2018. Alagasco has an operating lease for additional office space that extends to January 31, 2024. Alagasco has subleased all of this office space to Energen pursuant to a sublease that expires on December 31, 2019 with an option to extend through January 31, 2024. Amounts in the table above have not been reduced for sublease rentals. For Alagasco and Spire, sublease rentals were $2.1, $2.1, and $0.2 for fiscal years 2016, 2015, and 2014, and minimum future rentals to be received in fiscal years 2017, 2018, 2019, and 2020 are $2.1, $2.1, $2.1, and $0.5, respectively. Laclede Gas, Alagasco and LER have other relatively minor rental arrangements that provide for minimum rental payments.

A consolidated subsidiary is a general partner in an unconsolidated partnership that invests in real estate partnerships. The subsidiary and third parties are jointly and severally liable for the payment of mortgage loans in the aggregate outstanding amount of approximately $1.4 incurred in connection with various real estate ventures. Spire has no reason to believe that the other principal liable parties will not be able to meet their proportionate

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share of these obligations. Spire further believes that the asset values of the real estate properties are sufficient to support these mortgage loans.

Contingencies

The Company and Utilities account for environmental liabilities and other contingencies in accordance with accounting standards under the loss contingency guidance of ASC Topic 450, “Contingencies,” when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated.

The Company and the Utilities own and operate natural gas distribution, transmission, and storage facilities, the operations of which are subject to various environmental laws, regulations, and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company’s or Utilities’ financial position and results of operations. As environmental laws, regulations, and their interpretations change, the Company or the Utilities may incur additional environmental liabilities that may result in additional costs.

In addition to matters noted below, the Company, Laclede Gas, and Alagasco are involved in other litigation, claims, and investigations arising in the normal course of business. Management, after discussion with counsel, believes that the final outcome will not have a material effect on the consolidated statements of income, balance sheets, and statements of cash flows of the Company, Laclede Gas, or Alagasco. However, there is uncertainty in the valuation of pending claims and prediction of litigation results.

In the natural gas industry, many gas distribution companies have incurred environmental liabilities associated with sites they or their predecessor companies formerly owned or operated where manufactured gas operations took place. The Utilities each have former manufactured gas plant (MGP) operations in their respective service territories.

Laclede Gas

Laclede Gas has identified three former MGP sites in eastern Missouri where costs have been incurred and claims have been asserted: one in Shrewsbury, Missouri and two in the City of St. Louis, Missouri. Laclede Gas has enrolled the two sites in the City of St. Louis in the Missouri Department of Natural Resources Brownfields/Voluntary Cleanup Program (BVCP). In Laclede Gas’ western service area, MGE has enrolled all of its owned former MGP sites in the BVCP.

With regard to the former MGP site located in Shrewsbury, Missouri, Laclede Gas and state and federal environmental regulators agreed upon certain remedial actions to a portion of the site in a 1999 Administrative Order on Consent (AOC), which actions have been completed. On September 22, 2008, Environmental Protection Agency (EPA) Region VII issued a letter of Termination and Satisfaction terminating the AOC. However, if after this termination of the AOC, regulators require additional remedial actions, or additional claims are asserted, Laclede Gas may incur additional costs.

In conjunction with redevelopment of one of the sites located in the City of St. Louis, Laclede Gas and another former owner of the site entered into an agreement (Remediation Agreement) with the City development agencies, the developer, and an environmental consultant that obligates one of the City agencies and the environmental consultant to remediate the site and obtain a No Further Action letter from the Missouri Department of Natural Resources (MDNR). The Remediation Agreement also provides for a release of Laclede Gas and the other former site owner from certain liabilities related to the past and current environmental condition of the site and requires the developer and the environmental consultant to maintain certain insurance coverage, including remediation cost containment, premises pollution liability, and professional liability. The operative provisions of the Remediation Agreement were triggered on December 20, 2010, on which date Laclede Gas and the other former site owner, as full consideration under the Remediation Agreement, paid a small percentage of the cost of remediation of the site. The amount paid by Laclede Gas did not materially impact the financial condition, results of operations, or cash flows of the Company.

Laclede Gas has not owned the other site located in the City of St. Louis for many years. In a letter dated June 29, 2011, the Attorney General for the state of Missouri informed Laclede Gas that the MDNR had completed an investigation of the site. The Attorney General requested that Laclede Gas participate in the follow up investigations of the site. In a letter dated January 10, 2012, Laclede Gas stated that it would participate in future environmental response activities at the site in conjunction with other potentially responsible parties (PRPs) that are willing to contribute to such efforts in a meaningful and equitable fashion. Accordingly, Laclede Gas entered into a cost sharing agreement for remedial investigation with other PRPs. Pending MDNR approval which has not occurred as of the date of filing, the remedial investigation of the site will begin. 

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Laclede Gas has notified its insurers that it seeks reimbursement for costs incurred in the past and future potential liabilities associated with the MGP sites. While some of the insurers have denied coverage and reserved their rights, Laclede Gas continues to discuss potential reimbursements with them.

On March 10, 2015, Laclede Gas received a Section 104(e) information request from EPA Region VII regarding the former Thompson Chemical/Superior Solvents site in St. Louis, Missouri. In turn, Laclede Gas issued a Freedom of Information Act (FOIA) request to the EPA on April 3, 2015, in an effort to identify the basis of the inquiry. The FOIA response from the EPA was received on July 15, 2015 and a response was provided to the EPA on August 15, 2015.

MGE has seven owned MGP sites enrolled in the BVCP, including Joplin MGP #1, St. Joseph MGP #1, Kansas City Coal Gas Station B, Kansas City Station A Railroad area, Kansas City Coal Gas Station A North, Kansas City Coal Gas Station A South, and Independence MGP #2. Source removal has been conducted at all of the owned sites since 2003 with the exception of Joplin. On September 15, 2016, a request was made with the MDNR for a restrictive covenant use limitation with respect to Joplin. Remediation efforts at the seven sites are at various stages of completion, ranging from groundwater monitoring and sampling following source removal activities to the aforementioned request in respect to Joplin. As part of its participation in the BVCP, MGE communicates regularly with the MDNR with respect to its remediation efforts and monitoring activities at these sites. On May 11, 2015, MDNR approved the next phase of investigation at the Kansas City Station A North and Railroad area.

To date, costs incurred for all Missouri Utilities’ MGP sites for investigation, remediation and monitoring these sites have not been material. However, the amount of costs relative to future remedial actions at these and other sites is unknown and may be material. The actual future costs that Laclede Gas may incur could be materially higher or lower depending upon several factors, including whether remediation actions will be required, final selection and regulatory approval of any remedial actions, changing technologies and government regulations, the ultimate ability of other potential responsible parties to pay, the successful completion of remediation efforts required by the Remediation Agreement described above, and any insurance recoveries.

In 2013, Laclede Gas retained an outside consultant to conduct probabilistic cost modeling of 19 former MGP sites owned or operated by Laclede Gas in eastern Missouri or MGE in western Missouri. The purpose of this analysis was to develop an estimated range of probabilistic future liability for each site. That analysis, completed in August 2014, provided a range of demonstrated possible future expenditures to investigate, monitor and remediate all 19 MGP sites. Laclede Gas has recorded its best estimate of the probable expenditures that relate to these matters. The amount is not material.

Costs associated with environmental remediation activities are accrued when such costs are probable and reasonably estimable. To the extent such costs (less any amounts received from insurance proceeds or as contributions from other PRP’s), are incurred prior to a rate case, Laclede Gas would request from the MoPSC authority to defer such costs and collect them in the next rate case. Laclede Gas and the Company do not expect potential liabilities that may arise from remediating these sites to have a material impact on their future financial condition or results of operations.

Alagasco

Alagasco is in the chain of title of nine former MGP sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. As of September 30, 2016, Alagasco does not foresee a probable or reasonably estimable loss associated with these nine sites. Alagasco and the Company do not expect potential liabilities that may arise from remediating these sites to have a material impact on their future financial conditions or results of operations.

In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of the Comprehensive Environment Response, Compensation, and Liability Act (CERCLA) relating to the 35th Avenue Superfund Site located in North Birmingham, Jefferson County, Alabama. Alagasco was identified as a PRP under CERCLA for the cleanup of the site or costs the EPA incurs in cleaning up the site. At this point, Alagasco has not been provided information that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and vigorously denies its inclusion as a PRP.

On December 17, 2013, an incident occurred at a Housing Authority apartment complex in Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. Alagasco cooperated with the National Transportation Safety Board (NTSB) which investigated the incident. The NTSB report of findings was issued on March 30, 2016 and no safety recommendations, fines, or penalties were contained therein. Alagasco has been named as a defendant in several lawsuits arising from the incident, and additional lawsuits and claims may be filed against Alagasco.

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Mobile Gas

Mobile Gas is in the chain of title of one former MGP site which it still owns in Mobile, Alabama. On September 15, 2010, Mobile Gas filed an application to enroll the site into the Alabama Department of Environmental Management’s (ADEM) Voluntary Cleanup Program (VCP). This application was accepted by ADEM on November 16, 2010. Investigation and testing have been completed. As of September 30, 2016, Mobile Gas has an approved remediation plan from ADEM which is currently in the process of being executed. Mobile Gas and the Company do not expect potential liabilities that may arise from remediating this site to have a material impact on their future financial conditions or results of operations.

Since April 2012, a total of 14 lawsuits have been filed against Mobile Gas in Mobile County Circuit Court alleging that in the first half of 2008, Mobile Gas spilled tert-butyl mercaptan, an odorant added to natural gas for safety reasons, in Eight Mile, Alabama. Eleven of the lawsuits have been settled. The remaining three lawsuits, which include approximately 270 individual plaintiffs, allege nuisance, fraud and negligence causes of actions, and seek unspecified compensatory and punitive damages. A claim has been made against the insurance carriers for Mobile Gas requesting reimbursement for costs accrued in respect to this spill. Mobile Gas and the Company do not expect potential liabilities that may arise from these lawsuits to have a material impact on their future financial conditions or results of operations.

17.    INTERIM FINANCIAL INFORMATION (UNAUDITED)

Spire

In the opinion of Spire, the quarterly information presented below for fiscal years 2016 and 2015 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in consolidated operations reported on a quarterly basis primarily reflect the seasonal nature of the business of the Utilities.

Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2016
Total Operating Revenues	$	399.4	$	609.3	$	249.3	$	279.3
Operating Income (Loss)	87.0		167.7		35.3		(7.7		)
Net Income (Loss)	46.9		100.8		10.7		(14.2		)
Basic Earnings (Loss) Per Share of Common Stock	$	1.08	$	2.32	$	0.24	$	(0.31	)
Diluted Earnings (Loss) Per Share of Common Stock	$	1.08	$	2.31	$	0.24	$	(0.31	)
Fiscal Year 2015
Total Operating Revenues	$	619.6	$	877.4	$	275.2	$	204.2
Operating Income (Loss)	87.3		157.7		36.0		(8.5		)
Net Income (Loss)	47.1		94.4		14.1		(18.7		)
Basic Earnings (Loss) Per Share of Common Stock	$	1.09	$	2.18	$	0.32	$	(0.43	)
Diluted Earnings (Loss) Per Share of Common Stock	$	1.09	$	2.18	$	0.32	$	(0.43	)

Laclede Gas

In the opinion of Laclede Gas, the quarterly information presented below for fiscal years 2016 and 2015 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in operations reported on a quarterly basis primarily reflect their seasonal nature.

Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2016
Total Operating Revenues	$	317.2	$	446.7	$	179.3	$	144.3
Operating Income	65.1		87.0		29.4		5.4
Net Income (Loss)	39.4		54.3		13.9		(1.7		)
Fiscal Year 2015
Total Operating Revenues	$	462.4	$	615.7	$	187.5	$	151.0
Operating Income	64.8		80.6		34.5		5.5
Net Income (Loss)	39.0		49.9		20.0		(3.6		)

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Alagasco

In the opinion of Alagasco, the quarterly information presented below for fiscal years 2016 and 2015 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in operations reported on a quarterly basis primarily reflect their seasonal nature.

Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2016
Total Operating Revenues	$	82.3	$	166.0	$	74.0	$	46.2
Operating Income (Loss)	18.9		80.4		9.3		(17.1		)
Net Income (Loss)	9.9		48.1		4.0		(8.8		)
Fiscal Year 2015
Total Operating Revenues	$	120.0	$	233.3	$	73.7	$	52.2
Operating Income (Loss)	20.4		77.4		3.9		(12.5		)
Net Income (Loss)	10.6		46.3		0.7		(9.6		)

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

There have been no changes in or disagreements on accounting and financial disclosure with Spire’s, Laclede Gas’, or Alagasco’s outside auditors that are required to be disclosed.

Item 9A. Controls and Procedures

Spire

Disclosure Controls and Procedures

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15e and Rule 15d-15e under the Securities Exchange Act of 1934, as amended.

We acquired EnergySouth, Inc. in the quarter ended September 30, 2016. As such, the scope of our assessment of the effectiveness of our disclosure controls and procedures did not include the internal control over financial reporting of EnergySouth, Inc. This exclusion is consistent with the SEC Staff’s guidance that an assessment of a recently acquired business may be omitted from the scope of our assessment of the effectiveness of disclosure controls and procedures that are also part of internal control over financial reporting in the year of acquisition. EnergySouth, Inc.’s net assets, total assets and revenues constitute 5.1 percent, 4.9 percent and 0.2 percent, respectively, of the consolidated financial statement amounts as of and for the year ended September 30, 2016.

Based upon such evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of September 30, 2016.

Change in Internal Control over Financial Reporting

Other than as a result of the EnergySouth, Inc. acquisition described above, there were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, 2016 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Laclede Gas

Disclosure Controls and Procedures

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15e and Rule 15d-15e under the Securities Exchange Act of 1934, as amended. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

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Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our fourth fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.

Alagasco

Disclosure Controls and Procedures

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures pursuant to Rule 13a-15e and Rule 15d-15e under the Securities Exchange Act of 1934, as amended. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The Management Reports on Internal Control Over Financial Reporting and the Reports of Independent Registered Public Accounting Firm are included under Item 8, Financial Statements and Supplementary Data.

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information about:

• our directors is incorporated by reference from the discussion under Proposal 1 of our proxy statement to be filed on or about December 15, 2016 (2016 proxy statement);

• our executive officers is reported in Part I of this Form 10-K;

• compliance with Section 16(a) of the Exchange Act is incorporated by reference from the discussion in our 2016 proxy statement under the heading “Section 16(a) Beneficial Ownership Reporting Compliance”;

• our Financial Code of Ethics is posted on our website, www.SpireEnergy.com, in the Corporate Governance section under Governance Documents; and

• our audit committee, our audit committee financial experts, and submitting nominations to the Corporate Governance Committee is incorporated by reference from the discussion in our 2016 proxy statement under the heading “Corporate Governance.”

In addition, our Code of Business Conduct, Corporate Governance Guidelines, and charters for our audit, compensation and corporate governance committees are available on our website, and a copy will be sent to any shareholder upon written request.

Item 11. Executive Compensation

Information about director and executive compensation is incorporated by reference from the discussion in our 2016 proxy statement under the headings: “Directors’ Compensation,” “Compensation Discussion and Analysis,” and “Executive Compensation.” The 2016 proxy statement also includes the “Compensation Committee Report,” which is deemed furnished and not filed.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information about security ownership of certain beneficial owners and management is incorporated by reference from the discussion in our 2016 proxy statement under “Beneficial Ownership of Spire Common Stock.”

The following table sets forth aggregate information regarding the Company’s equity compensation plans as of September 30, 2016:

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)	(c)
Equity compensation plans approved by security holders (1)	624,662	$—	721,605
Equity compensation plans not approved by security holders	—	—	—
Total	624,662	—	721,605

(1) Reflects the Company’s 2015 and 2006 Equity Incentive Plans.

Information regarding the above referenced plans is set forth in Note 3, Stock-Based Compensation, of the Notes to Financial Statements in Item 8 of this report.

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Item 13. Certain Relationships and Related Transactions, and Director Independence

Information about:

• our policy and procedures for related party transactions and

• the independence of our directors

is included in our 2016 proxy statement under “Corporate Governance” and is incorporated by reference. There were no related party transactions in fiscal year 2016.

Item 14. Principal Accounting Fees and Services

Information about fees paid to our independent registered public accountant and our policy for pre-approval of services provided by our independent registered public accountant is incorporated by reference from our 2016 proxy statement under “Fees of Independent Registered Public Accountant” and “Corporate Governance,” respectively.

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PART IV

Item 15. Exhibits, Financial Statement Schedules
(a)	(1)	Financial Statements
		See Item 8. Financial Statements and Supplementary Data, filed herewith, for a list of financial statements.
	(2)	Financial Statement Schedules
		Schedules have been omitted because they are not applicable, related significance tests were not met, or the required data has been included in the financial statements or notes to financial statements.
	(3)	Exhibits
		Incorporated herein by reference to Exhibit Index, page 142.
(b)		Incorporated herein by reference to Exhibit Index, page 142.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

			SPIRE INC.
Date	November 15, 2016	By	/s/ Steven P. Rasche
			Steven P. Rasche
			Executive Vice President
			and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date	Signature	Title
November 15, 2016	/s/ Suzanne Sitherwood	Director, President, and Chief Executive Officer
	Suzanne Sitherwood	(Principal Executive Officer)
November 15, 2016	/s/ Steven P. Rasche	Executive Vice President and Chief Financial Officer
	Steven P. Rasche	(Principal Financial and Accounting Officer)
November 15, 2016	/s/ Edward L. Glotzbach	Chairman of the Board
	Edward L. Glotzbach
November 15, 2016	/s/ Mark A. Borer	Director
	Mark A. Borer
November 15, 2016	/s/ Maria V. Fogarty	Director
	Maria V. Fogarty
November 15, 2016	/s/ Rob L. Jones	Director
	Rob L. Jones
November 15, 2016	/s/ Brenda D. Newberry	Director
	Brenda D. Newberry
November 15, 2016	/s/ John P. Stupp, Jr.	Director
	John P. Stupp, Jr.
November 15, 2016	/s/ Mary Ann Van Lokeren	Director
	Mary Ann Van Lokeren

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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

			LACLEDE GAS COMPANY
Date	November 15, 2016	By	/s/ Steven P. Rasche
			Steven P. Rasche
			Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date	Signature	Title
November 15, 2016	/s/ Suzanne Sitherwood	Chairman of the Board
	Suzanne Sitherwood
November 15, 2016	/s/ Steven P. Rasche	Director and Chief Financial Officer
	Steven P. Rasche	(Principal Financial and Accounting Officer)
November 15, 2016	/s/ Steven L. Lindsey	Director, Chief Executive Officer and President
	Steven L. Lindsey	(Principal Executive Officer)
November 15, 2016	/s/ Mark C. Darrell	Director
	Mark C. Darrell
November 15, 2016	/s/ L. Craig Dowdy	Director
	L. Craig Dowdy

140

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

			ALABAMA GAS CORPORATION
Date	November 15, 2016	By	/s/ Steven P. Rasche
			Steven P. Rasche
			Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date	Signature	Title
November 15, 2016	/s/ Suzanne Sitherwood	Chairman of the Board
	Suzanne Sitherwood
November 15, 2016	/s/ Steven P. Rasche	Director and Chief Financial Officer
	Steven P. Rasche	(Principal Financial and Accounting Officer)
November 15, 2016	/s/ Steven L. Lindsey	Director and Chief Executive Officer
	Steven L. Lindsey	(Principal Executive Officer)
November 15, 2016	/s/ Mark C. Darrell	Director
	Mark C. Darrell
November 15, 2016	/s/ L. Craig Dowdy	Director
	L. Craig Dowdy

141

EXHIBIT INDEX

Exhibit Number
2.01*	Agreement and Plan of Merger and Reorganization; filed as Appendix A to proxy statement/prospectus contained in the Company’s Registration Statement on Form S-4 filed October 27, 2000, No. 333-48794.
3.01*	Articles of Incorporation of Spire Inc., as amended, effective as of April 28, 2016; filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed May 3, 2016.
3.02*	Bylaws of Spire Inc., as amended, effective as of April 28, 2016; filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed May 3, 2016.
3.03*	Laclede Gas’ Restated Articles of Incorporation as amended March 8, 2013; filed as Exhibit 3.1 to Laclede Gas’ Quarterly Report on Form 10-Q/A for the fiscal quarter ended March 31, 2013.
3.04*	Amended and Restated Bylaws of Laclede Gas, effective as of August 1, 2015; filed as Exhibit 3.2 to Laclede Gas’ Current Report on Form 8-K filed July 31, 2015.
3.05*	Articles of Amendment and Restatement of the Articles of Incorporation of Alagasco, dated September 27, 1995, which was filed as Exhibit 3(i) to Alagasco’s Annual Report on Form 10-K for the year ended September 30, 1995.
3.06*	Bylaws of Alagasco (as amended September 2, 2014); filed as Exhibit 3(b) to Alagasco’s Annual Report on Form 10-KT for the fiscal year ended September 30, 2014.
4.01*	Mortgage and Deed of Trust, dated as of February 1, 1945; filed as Exhibit 7-A to registration statement No. 2-5586.
4.02*	Fourteenth Supplemental Indenture, dated as of October 26, 1976; filed as Exhibit b-4 to registration statement No. 2-64857 filed June 26, 1979.
4.03*	Twenty-Fourth Supplemental Indenture dated as of June 1, 1999, between Laclede Gas and State Street Bank and Trust Company of Missouri, N.A., as trustee; filed as Exhibit 4.01 to Laclede Gas’ Current Report on Form 8-K filed June 4, 1999.
4.04*	Twenty-Fifth Supplemental Indenture dated as of September 15, 2000, between Laclede Gas and State Street Bank and Trust Company of Missouri, as trustee; filed as Exhibit 4.01 to Laclede Gas’ Current Report on Form 8-K filed September 27, 2000.
4.05*	Twenty-Seventh Supplemental Indenture dated as of April 15, 2004, between Laclede Gas and UMB Bank & Trust, N.A., as trustee; filed as Exhibit 4.01 to Laclede Gas’ Current Report on Form 8-K filed April 28, 2004.
4.06*	Twenty-Eighth Supplemental Indenture dated as of April 15, 2004, between Laclede Gas and UMB Bank & Trust, N.A., as trustee; filed as Exhibit 4.02 to Laclede Gas’ Current Report on Form 8-K filed April 28, 2004.
4.07*	Twenty-Ninth Supplemental Indenture dated as of June 1, 2006, between Laclede Gas and UMB Bank and Trust, N.A., as trustee; filed as Exhibit 4.1 to Laclede Gas’ Current Report on Form 8-K filed June 9, 2006.
4.08*	Thirty-First Supplemental Indenture, dated as of March 15, 2013, between Laclede Gas and UMB Bank & Trust, N.A., as trustee; filed as Exhibit 4.1 to the Company’s Form 10-Q for the fiscal quarter ended March 31, 2013.
4.09*	Thirty-Second Supplemental indenture, dated as of August 13, 2013, between Laclede Gas and UMB Bank & Trust, N.A., as trustee; filed as Exhibit 4.1 to Laclede Gas’ Current Report on Form 8-K filed August 13, 2013.
4.10*	Laclede Gas Board of Directors’ Resolution dated August 28, 1986 which generally provides that the Board may delegate its authority in the adoption of certain employee benefit plan amendments to certain designated Executive Officers; filed as Exhibit 4.12 to Laclede Gas’ Annual Report on Form 10-K for the fiscal year ended September 30, 1991.
4.11*	Laclede Gas’ Board of Directors’ Resolutions dated March 27, 2003, updating authority delegated pursuant to August 28, 1986 Laclede Gas resolutions; filed as Exhibit 4.19(a) to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2003.
4.12*	Junior Subordinated Indenture, dated as of June 11, 2014, between the Company and U.S. Bank National Association, as trustee; filed as Exhibit 4.1 to Spire’s Current Report on Form 8-K filed June 11, 2014.
4.13*	First Supplemental Indenture, dated as of June 11, 2014, between the Company and U.S. Bank National Association, as trustee (including Form of Series A 2.00% Remarketable Junior Subordinated Notes due 2022); filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed June 11, 2014.

142

Exhibit Number
4.14*	Purchase Contract and Pledge Agreement, dated as of June 11, 2014, between the Company and US Bank National Association, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (including Form of Remarketing Agreement, Form of Corporate Units and Form of Treasury Units); filed as Exhibit 4.4 to the Company’s Current Report on Form 8-K filed June 11, 2014.
4.15*	Indenture, dated as of August 19, 2014, between the Company and UMB Bank & Trust, N.A., as trustee; filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed August 19, 2014.
4.16*	First Supplemental Indenture, dated as of August 19, 2014, between the Company and UMB Bank & Trust, N.A., as trustee (including Form of Floating Rate Senior Notes due 2017, Form of 2.55% Senior Notes due 2019 and Form of 4.70% Senior Notes due 2044); filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed August 10, 2014.
4.17*	Indenture dated as of November 1, 1993, between Alagasco and NationsBank of Georgia, National Association, Trustee, (“Alagasco 1993 Indenture”), which was filed as Exhibit 4(k) to Alagasco’s Registration Statement on Form S-3 (Registration No. 33-70466).
4.18*	Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alagasco 1993 Indenture setting forth the terms of the 5.20 percent Notes due January 15, 2020, which was filed as Exhibit 4.4 to Alagasco’s Current Report on Form 8-K filed January 14, 2005.
4.19*	Officers’ Certificate, dated November 17, 2005, pursuant to Section 301 of the Alagasco 1993 Indenture setting forth the terms of the 5.368 percent Notes due December 1, 2015, which was filed as Exhibit 4.2 to Alagasco’s Current Report on Form 8-K filed November 17, 2005.
4.20*	Officers’ Certificate, dated January 16, 2007, pursuant to Section 301 of the Alagasco 1993 Indenture setting forth the terms of the 5.90 percent Notes due January 15, 2037, which was filed as Exhibit 4.2 to Alagasco’s Current Report on Form 8-K filed January 16, 2007.
10.01*	Lease between Laclede Gas, as Lessee, and First National Bank in St. Louis, Trustee, as Lessor; filed as Exhibit 10.23 to Laclede Gas’ Annual Report on Form 10-K for the fiscal year ended September 30, 2002.
10.02*	Automated Meter Reading Services Agreement, dated as of March 11, 2005, between Cellnet Technology, Inc. and Laclede Gas; filed as Exhibit 10.1 to Laclede Gas’ Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2005. Confidential portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.
10.03*	Restated Laclede Gas Supplemental Retirement Benefit Plan, as amended and restated as of January 1, 2005; filed as Exhibit 10.06 to Laclede Gas’ Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008.
10.04*	Laclede Gas Supplemental Retirement Benefit Plan II, effective as of January 1, 2005; filed as Exhibit 10.7 to Laclede Gas’ Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008.
10.05*	Amendment and Restatement of Retirement Plan for Non-Employee Directors of Laclede Gas as of November 1, 2002; filed as Exhibit 10.08c to Laclede Gas’ Annual Report on Form 10-K for the fiscal year ended September 30, 2002.
10.06*	Amendment to Terms of Retirement Plan for Non-Employee Directors of Laclede Gas as of October 1, 2004; filed as Exhibit 10.2 to Laclede Gas’ Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2004.
10.07*	Salient Features of Laclede Gas’ Deferred Income Plan for Directors and Selected Executives, including amendments adopted by the Board of Directors on July 26, 1990; filed as Exhibit 10.12 to Laclede Gas’ Annual Report on Form 10-K for the fiscal year ended September 30, 1991.
10.08*	Amendment to Laclede Gas’ Deferred Income Plan for Directors and Selected Executives, adopted by the Board of Directors on August 27, 1992; filed as Exhibit 10.12a to Laclede Gas’ Annual Report on Form 10-K for the fiscal year ended September 30, 1992.
10.09*	Salient Features of Laclede Gas’ Deferred Income Plan II for Directors and Selected Executives (as amended and restated effective as of January 1, 2005); filed as Exhibit 10.1 to Laclede Gas’ Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008.
10.10*	Salient Features of the Company’s Deferred Income Plan for Directors and Selected Executives (effective as of January 1, 2005); filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008.

143

Exhibit Number
10.11*	The Company’s Deferred Income Plan for Directors and Selected Executives, as Amended and Restated as of January 1, 2015; filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed November 4, 2014.
10.12*	Form of Indemnification Agreement between Laclede Gas and its Directors and Officers; filed as Exhibit 10.13 to Laclede Gas’ Annual Report on Form 10-K for the fiscal year ended September 30, 1990.
10.13*	The Company’s Management Continuity Protection Plan, effective as of January 1, 2005; filed as Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008.
10.14*	Form of Management Continuity Protection Agreement; filed as Exhibit 10.05a to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008.
10.15*	The Company’s 2011 Management Continuity Protection Plan; filed as Exhibit 10.25 to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2010.
10.16*	Form of Agreement under the Company’s 2011 Management Continuity Protection Plan; filed as Exhibit 10.25a to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2010.
10.17*	Restricted Stock Plan for Non-Employee Directors as amended and effective January 29, 2009; filed as Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed December 22, 2008.
10.18*	Amendment to Restricted Stock Plan for Non-Employee Directors; filed as Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2011.
10.19*	Form of Non-Qualified Stock Option Award Agreement with Mandatory Retirement Provisions; filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed November 5, 2004.
10.20*	Form of Non-Qualified Stock Option Award Agreement without Mandatory Retirement Provisions; filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed November 5, 2004.
10.21*	The Laclede Group, Inc. 2002 Equity Incentive Plan; filed as Exhibit 10.22 to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2002.
10.22*	The Laclede Group 2006 Equity Incentive Plan, as amended effective February 1, 2012; filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2012.
10.23*	The Laclede Group 2015 Equity Incentive Plan; filed as the Appendix to the Company’s Definitive Proxy Statement on Form DEF 14A filed December 19, 2014.
10.24*	The Company’s Annual Incentive Plan; filed as Appendix 1 to the Company’s Definitive Proxy Statement on Schedule 14A filed December 17, 2010.
10.25*	The Company’s Form of Restricted Stock Award Agreement; filed as Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2008.
10.26*	The Company’s Form of Performance Contingent Restricted Stock Award Agreement; filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2009.
10.27*	The Company’s Form of Performance Contingent Restricted Stock Unit Award Agreement; filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2011.
10.28*	The Company’s Form of Performance Contingent Restricted Stock Unit Award Agreement; filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 31, 2012.
10.29*	Severance Benefits Agreement, dated September 1, 2011, between the Company and Suzanne Sitherwood; filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2011.

144

Exhibit Number
10.30*	First Amendment to the Severance Benefits Agreement, dated August 1, 2014, between the Company and Suzanne Sitherwood; filed as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2014.
10.31*	Performance Contingent Restricted Stock Agreement, dated September 1, 2011, between the Company and Suzanne Sitherwood; filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2011.
10.32*	Restricted Stock Unit Award Agreement, dated September 1, 2011, between the Company and Suzanne Sitherwood; filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2011.
10.33*	Restricted Stock Unit Award Agreement, dated October 1, 2012, between the Company and Steve Lindsey; filed as Ex 10.25 to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2012.
10.34*	Performance Contingent Restricted Stock Unit Award Agreement, dated October 1, 2012, between the Company and Steve Lindsey; filed as Ex 10.26 to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2012.
10.35*	Severance Benefits Agreement, dated October 1, 2012, between the Company and Steve Lindsey; filed as Exhibit 10.27 to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2012.
10.36*	Note Purchase Agreement, dated August 3, 2012, by and among the Company and the Purchasers listed in Schedule A thereto; filed as Exhibit 10.28 to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2012.
10.37*	Laclede Gas Cash Balance Supplemental Retirement Benefit Plan, effective as of January 1, 2009; filed as Exhibit 10.30 to Laclede Gas’ Annual Report on Form 10-K for the fiscal year ended September 30, 2012.
10.38*	Amended and Restated Firm (Rate Schedule FT) Transportation Service Agreement between Laclede Energy Resources, Inc. and CenterPoint Energy Gas Transmission Company TSA #1006667; filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2012.
10.39*	Amended and Restated Storage Service Agreement For Rate Schedule FSS, Contract #3147, dated July 30, 2013, between CenterPoint Energy-Mississippi River Transmission Corporation and Laclede Gas; filed as Exhibit 10.1 to Laclede Gas’ Current Report on Form 8-K filed August 2, 2013.
10.40*	Amended and Restated Transportation Service Agreement for Rate Schedule FTS, Contract #3310, dated July 30, 2013, between CenterPoint Energy-Mississippi River Transmission Corporation and Laclede Gas; filed as Exhibit 10.2 to Laclede Gas’ Current Report on Form 8-K filed August 2, 2013.
10.41*	Amended and Restated Transportation Service Agreement for Rate Schedule FTS, Contract #3311, dated July 30, 2013, between CenterPoint Energy-Mississippi River Transmission Corporation and Laclede Gas; filed as Exhibit 10.3 to Laclede Gas’ Current Report on Form 8-K filed August 2, 2013.
10.42*	Purchase and Sale Agreement for Missouri Gas Energy, dated as of December 14, 2012, by and among Southern Union Company, Plaza Missouri Acquisition, Inc. and the Company (solely for purposes of Section 13.19 of the Agreement); filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed December 17, 2012.
10.43*	Purchase and Sale Agreement for New England Gas Company, dated as of December 14, 2012, among Southern Union Company, Plaza Massachusetts Acquisition, Inc. and the Company; filed as Exhibit 2.2 to the Company’s Current Report on Form 8-K filed December 17, 2012.
10.44*	Employee Agreement for Missouri Gas Energy, dated as of December 14, 2012, among Southern Union Company, Plaza Missouri Acquisition, Inc. and the Company; filed as Exhibit 2.3 to the Company’s Current Report on Form 8-K filed December 17, 2012.
10.45*	Employee Agreement for New England Gas Company, dated as of December 14, 2012, among Southern Union Company, Plaza Missouri Acquisition, Inc. and the Company; filed as Exhibit 2.4 to the Company’s Current Report on Form 8-K filed December 17, 2012.
10.46*	Stock Purchase Agreement, dated as of February 11, 2013, by and among the Company, Plaza Massachusetts Acquisition, Inc., and Algonquin Power & Utilities Corp.; filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed February 12, 2013.
10.47*	Assignment and Assumption Agreement, dated as of January 11, 2013, by and between Plaza Missouri Acquisition, Inc. and Laclede Gas; filed as Exhibit 99.1 to Laclede Gas’ Current Report on Form 8-K filed January 14, 2013.

145

Exhibit Number
10.48*	Consent to Assignment executed by Southern Union Company dated as of January 11, 2013; filed as Exhibit 99.2 to Laclede Gas’ Current Report on Form 8-K filed January 14, 2013.
10.49*	Consent Agreement, dated as of February 11, 2013, by and among the Company, Plaza Massachusetts Acquisition, Inc. Southern Union Company and Algonquin Power & Utilities Corp.; filed as Exhibit 2.2 to the Company’s Current Report on Form 8-K filed February 12, 2013.
10.50*	Loan agreement, dated September 3, 2013, among the Company and the several bank parties thereto, including Wells Fargo Bank, National Association, as Administrative Agent, U.S. Bank National Association and JPMorgan Chase Bank, N.A. as Co-Syndication Agents; Bank of America, N.A., Fifth Third Bank and Morgan Stanley Bank, N.A., as Co-Documentation Agents; and Wells Fargo Securities LLC, U.S. Bank National Association and J.P. Morgan Securities LLC as Joint Lead Arrangers and Joint Bookrunners; and Commerce Bank, UMB Bank, N.A., and Stifel Bank & Trust as the other participating banks; filed as Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2013.
10.51*	First Amendment and Waiver to Loan Agreement, dated as of April 28, 2014, among the Company and the several banks parties thereto, including Wells Fargo Bank, National Association as Administrative Agent; filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2014.
10.52*	First Extension Agreement, dated as of September 3, 2014, to Loan Agreement, dated September 3, 2013, as amended, by and among the Company and the several banks party thereto, including Wells Fargo Bank, National Association, as administrative agent; filed as Exhibit 99.2 to the Company’s Current Report on Form 8-K filed September 4, 2014.
10.53*	Loan agreement, dated September 3, 2013, among Laclede Gas and the several bank parties thereto, including Wells Fargo Bank, National Association, as Administrative Agent, U.S. Bank National Association and JPMorgan Chase Bank, N.A. as Co-Syndication Agents; Bank of America, N.A., Fifth Third Bank and Morgan Stanley Bank, N.A., as Co-Documentation Agents; and Wells Fargo Securities LLC, U.S. Bank National Association and J.P. Morgan Securities LLC as Joint Lead Arrangers and Joint Bookrunners; and Commerce Bank, UMB Bank, N.A., and Stifel Bank & Trust as the other participating banks; filed as Exhibit 10.12 to Laclede Gas’ Annual Report on Form 10-K for the fiscal year ended September 30, 2013.
10.54*	First Extension Agreement, dated as of September 3, 2014, to Loan Agreement, dated September 3, 2013, as amended, by and among Laclede Gas and the several banks party thereto, including Wells Fargo Bank, National Association, as administrative agent; filed as Exhibit 99.3 to Laclede Gas’ Current Report on Form 8-K filed September 4, 2014.
10.55*	Lease Agreement, dated January 21, 2014, between the Company, as Tenant, and Market 700, LLC, as Landlord; filed as Exhibit 10.1 to Spire Inc.’s Current Report on Form 8-K filed January 27, 2014.
10.56*	Stock Purchase Agreement, dated as of April 5, 2014, between the Company and Energen Corporation; filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed April 7, 2014.
10.57*	Commitment Letter, dated April 5, 2014, among the Company and Credit Suisse AG and Wells Fargo Bank, National Association, and their respective affiliates; filed as Exhibit 99.1 to the Company’s Current Report on Form 8-K filed April 7, 2014.
10.58*	First Amendment to the Commitment Letter, dated June 16, 2014, among the Company and Credit Suisse AG and Wells Fargo Bank, National Association, and their respective affiliates; filed as Exhibit 99.1 to the Company’s Current Report on Form 8-K filed June 17, 2014.
10.59*	2nd Amendment to Commitment Letter, dated August 19, 2014, among the Company and Credit Suisse AG and Wells Fargo Bank, National Association, and their respective affiliates; filed as Exhibit 99.1 to the Company’s Current Report on Form 8-K filed August 21, 2014.
10.60*	The Company’s Executive Severance Plan effective January 1, 2015; filed as Exhibit 10.59 to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2014.
10.61*	Master Note Purchase Agreement, dated as of June 5, 2015, among Alagasco and certain institutional purchasers; filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2015.
10.62*	Credit Agreement dated September 2, 2014, by and among Alagasco, Wells Fargo Bank, National Association., as Administrative Agent, Credit Suisse AG, Cayman Islands Branch and U.S. Bank National Association, as CO-Syndication Agents, Wells Fargo Securities LLC, Credit Suisse Securities (USA) LLC and U.S. Bank National Association, as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 991. to Alagasco’s Current Report on Form 8-K filed September 4, 2014.

146

Exhibit Number
10.63*	Credit Agreement dated October 30, 2012, by and among Alagasco, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, Wells Fargo Bank, National Association and Regions Bank, and Co-Syndication Agents and L/C Issuers, Compass Bank and U.S. Bank National Association, as Co- Documentation Agents and L/C Issuers, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities LLC, Regions Capital Markets, a division of Regions Bank, Compass Bank and U.S. Bank National Association, as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 10.2 to Alagasco’s Current Report on Form 8-K filed October 31, 2012.
10.64*	Note Purchase Agreement, dated December 22, 2011, among Alagasco and the Purchasers thereto (the AIG purchasers) with respect to $25 million 3.86 percent Senior Notes due December 22, 2021, which was filed as Exhibit 10.1 to Alagasco’s Current Report on Form 8-K filed December 22, 2011.
10.65*	Note Purchase Agreement, dated December 22, 2011, among Alagasco and the Purchasers thereto (the Prudential purchasers) with respect to $25 million 3.86 percent Senior Notes due December 22, 2021, which was filed as Exhibit 10.2 to Alagasco’s Current Report on Form 8-K filed December 22, 2011.
10.66*	Service Agreement Under Rate Schedule CSS (No. SSNG1), between Southern Natural Gas Company and Alagasco, dated as of September 1, 2005, which was filed as Exhibit 10(a) to Alagasco’s Annual Report on Form 10-K for the year ended December 31, 2005.
10.67*	Amended Exhibit A, effective January 15, 2014, to Service Agreement Under Rate Schedule CSS (No. SSNG1) between Southern Natural Gas Company and Alagasco dated September 1, 2005 which was filed as Exhibit 10(g) to Alagasco’s Annual Report on Form 10-K for the year ended December 31, 2013.
10.68*	Firm Transportation Service Agreement Under Rate Schedule FT and/or FT-NN (No. FSNG1), between Southern Natural Gas Company and Alagasco dated as of September 1, 2005, which was filed as Exhibit 10(b) to Alagasco’s Annual Report on Form 10-K for the year ended December 31, 2005.
10.69*	Amended Exhibit A, effective October 1, 2013, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alagasco, which was filed as Exhibit 10(i) to Alagasco’s Annual Report on Form 10-K for the year ended December 31, 2013.
10.70*	Amended Exhibit B, effective November 1, 2013, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alagasco, which was filed as Exhibit 10(j) to Alagasco’s Annual Report on Form 10-K for the year ended December 31, 2013.
10.71*	Form of Service Agreement Under Rate Schedule IT (No. 790420), between Southern Natural Gas Company and Alagasco, which was filed as Exhibit 10(b) to Alagasco’s Annual Report on Form 10-K for the year ended September 30, 1993.
10.72*	Service Agreement between Transcontinental Gas Pipeline Corporation and Transco Energy Marketing Company as Agent for Alagasco, dated August 1, 1991 which was filed as Exhibit 3(e) to Alagasco’s Annual Report on Form 10-K for the year ended December 31, 2003.
10.73*	Amendment to Service Agreement between Transcontinental Gas Pipeline Corporation and Alagasco, dated December 2, 2005, which was filed as Exhibit 10(e) to Alagasco’s Annual Report on Form 10-K for the year ended December 31, 2005.
10.74*	Spire Inc. Annual Incentive Plan, as Amended, filed as Appendix to the Company’s Definitive Proxy Statement on Schedule 14A filed December 18, 2015.
10.75*	Spire Inc. Deferred Income Plan, as Amended and Restated as of January 1, 2016, which was filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed November 24, 2015.
12.1	Computation of Ratio of Earnings to Fixed Charges of the Company.
12.2	Computation of Ratio of Earnings to Fixed Charges of Laclede Gas.
21	Subsidiaries of the Company.
23.1	Consent of Independent Registered Public Accounting Firm of the Company.
23.2	Consent of Independent Registered Public Accounting Firm of Laclede Gas.
31.1	Certifications under Rule 13a-14(a) of the CEO and CFO of the Company.
31.2	Certifications under Rule 13a-14(a) of the CEO and CFO of Laclede Gas.
31.3	Certifications under Rule 13a-14(a) of the CEO and CFO of Alagasco.
32.1	Section 1350 Certifications under Rule 13a-14(b) of the CEO and CFO of the Company.

147

Exhibit Number
32.2	Section 1350 Certifications under Rule 13a-14(b) of the CEO and CFO of Laclede Gas.
32.3	Section 1350 Certifications under Rule 13a-14(b) of the CEO and CFO of Alagasco.
101.INS	XBRL Instance Document. (1)
101.SCH	XBRL Taxonomy Extension Schema. (1)
101.CAL	XBRL Taxonomy Extension Calculation Linkbase. (1)
101.DEF	XBRL Taxonomy Definition Linkbase. (1)
101.LAB	XBRL Taxonomy Extension Labels Linkbase. (1)
101.PRE	XBRL Taxonomy Extension Presentation Linkbase. (1)

(1) Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) Consolidated Statements of Income and Statements of Income for the years ended September 30, 2016, 2015, and 2014; (iii) Consolidated Statements of Comprehensive Income and Statements of Comprehensive Income for the years ended September 30, 2016, 2015, and 2014; (iv) Consolidated Statements of Common Shareholders’ Equity and Statements of Common Shareholder’s Equity for the years ended September 30, 2016, 2015, and 2014; (v) Consolidated Statements of Cash Flows and Statements of Cash Flows for the years ended September 30, 2016, 2015, and 2014; (vi) Consolidated Balance Sheets and Balance Sheets at September 30, 2016 and 2015; (vii) Consolidated Statements of Capitalization and Statements of Capitalization at September 30, 2016 and 2015; and (viii) Notes to Financial Statements. For Alagasco, the Statements of Income, Comprehensive Income, Common Shareholder’s Equity, and Cash Flows are for the year ended September 30, 2016 and 2015, and the nine months ended September 30, 2014. We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Annual Report. 

* Incorporated herein by reference and made a part hereof. The Company File No. 1-16681. Laclede Gas File No. 1-1822. Alagasco file No. 2-38960.

Bold items reflect management, contract or compensatory plan or arrangement.

148

EX-12.1

Exhibit 12.1

SPIRE INC. AND SUBSIDIARIES

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(Dollars in Millions)	Years Ended September 30,
	2016		2015		2014		2013		2012
Earnings
Income before income taxes	$	213.7	$	199.1	$	116.9	$	70.4	$	88.9
Add: Fixed Charges (from below)	80.8		78.0		48.3		30.6		26.5
Total Earnings	$	294.5	$	277.1	$	165.2	$	101.0	$	115.4
Fixed Charges
Interest on long-term debt	$	67.6	$	66.6	$	39.3	$	25.5	$	23.0
Other interest charges	9.6		8.0		6.9		3.1		2.0
One third of applicable rentals charged to operating expense (which approximates the interest portion)	3.4		3.4		2.1		2.0		1.5
Add back: Allowance for borrowed funds used during construction	0.2		—		—		—		—
Total Fixed Charges	$	80.8	$	78.0	$	48.3	$	30.6	$	26.5
Ratio of Earnings to Fixed Charges	3.64		3.55		3.41		3.30		4.35

EX-12.2

Exhibit 12.2

LACLEDE GAS COMPANY

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(Dollars in Millions)	Years Ended September 30,
	2016		2015		2014		2013		2012
Earnings
Income before income taxes	$	151.3	$	148.5	$	125.6	$	63.4	$	68.3
Add: Fixed Charges (from below)	40.1		39.7		39.5		28.1		26.7
Total Earnings	$	191.4	$	188.2	$	165.1	$	91.5	$	95.0
Fixed Charges
Interest on long-term debt	$	32.9	$	33.1	$	34.4	$	24.9	$	22.9
Other interest charges	4.5		3.3		3.0		1.2		2.2
One third of applicable rentals charged to operating expense (which approximates the interest portion)	2.5		3.3		2.1		2.0		1.6
Add back: Allowance for borrowed funds used during construction	0.2		—		—		—		—
Total Fixed Charges	$	40.1	$	39.7	$	39.5	$	28.1	$	26.7
Ratio of Earnings to Fixed Charges	4.77		4.74		4.18		3.26		3.56

EX-21

Exhibit 21

SPIRE INC.
SUBSIDIARIES OF THE REGISTRANT
Subsidiaries of Spire Inc. (Parent)	Percent of Voting Stock Owned
Laclede Gas Company	100%
Alabama Gas Corporation	100%
EnergySouth, Inc.(1)	100%
Laclede Pipeline Company	100%
Laclede Investment LLC(2)	100%
Laclede Development Company(3)	100%
Laclede Insurance Risk Services, Inc.	100%
Shared Services Corporation	100%
Spire Resources LLC(4)	100%
(1) Subsidiary Companies of EnergySouth, Inc.
Mobile Gas Service Corporation	100%
Willmut Gas and Oil Company	100%
(2) Subsidiary Company of Laclede Investment LLC
Laclede Energy Resources, Inc.*	100%
*Subsidiary Company of Laclede Energy Resources, Inc.
LER Storage Services, Inc.	100%
(3) Subsidiary Companies of Laclede Development Company
Laclede Venture Corp.	100%
Laclede Oil Services, LLC	100%
(4)Subsidiary Company of Spire Resources LLC
Spire Pipelines LLC**	100%
**Subsidiary Company of Spire Pipelines LLC
Spire STL Pipeline LLC	100%
All of the above corporations have been organized under the laws of the State of Missouri except Alabama Gas Corporation and Mobile Gas Company, which are organized under the laws of the State of Alabama, Willmut Gas and Oil Company, which is organized under the laws of the State of Mississippi, EnergySouth, Inc., which is organized under the laws of the State of Delaware, and Laclede Insurance Risk Services, Inc., which is organized under the laws of the State of South Carolina.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-213759 and 333-196919 of Spire Inc. and subsidiaries (formerly The Laclede Group, Inc.) on Forms S-3 and in Registration Statement Nos. 333-198699, 333-193772, 333-193770, 333-193771, 333-131830, 333-201863, and 333-204839 of Spire Inc. and subsidiaries on Forms S-8 of our reports dated November 15, 2016, relating to the consolidated financial statements of Spire Inc. and subsidiaries, and the effectiveness of Spire Inc. and subsidiaries' internal control over financial reporting, appearing in this Annual Report on Form 10-K of Spire Inc. and subsidiaries for the year ended September 30, 2016.

/s/DELOITTE & TOUCHE LLP

St. Louis, Missouri

November 15, 2016

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-213759 of Laclede Gas Company on Form S-3 of our report dated November 15, 2016, relating to the financial statements of Laclede Gas Company, appearing in this Annual Report on Form 10-K of Laclede Gas Company for the year ended September 30, 2016.

/s/DELOITTE & TOUCHE LLP

St. Louis, Missouri

November 15, 2016

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-121077 of Alabama Gas Corporation on Form S-3 of our report dated November 15, 2016, relating to the financial statements of Alabama Gas Corporation, appearing in this Annual Report on Form 10-K of Alabama Gas Corporation for the year ended September 30, 2016.

/s/DELOITTE & TOUCHE LLP

Birmingham, Alabama

November 15, 2016

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Suzanne Sitherwood, certify that:

1. I have reviewed this annual report on Form 10-K of Spire Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 15, 2016	Signature:	/s/ Suzanne Sitherwood
			Suzanne Sitherwood
			President and Chief Executive Officer

CERTIFICATION

I, Steven P. Rasche, certify that:

1. I have reviewed this annual report on Form 10-K of Spire Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 15, 2016	Signature:	/s/ Steven P. Rasche
			Steven P. Rasche
			Executive Vice President and Chief Financial Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Steven L. Lindsey, certify that:

1. I have reviewed this annual report on Form 10-K of Laclede Gas Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 15, 2016	Signature:	/s/ Steven L. Lindsey
			Steven L. Lindsey
			Chief Executive Officer and President

CERTIFICATION

I, Steven P. Rasche, certify that:

1. I have reviewed this annual report on Form 10-K of Laclede Gas Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 15, 2016	Signature:	/s/ Steven P. Rasche
			Steven P. Rasche
			Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION

I, Steven L. Lindsey, certify that:

1. I have reviewed this annual report on Form 10-K of Alabama Gas Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 15, 2016	Signature:	/s/ Steven L. Lindsey
			Steven L. Lindsey
			Chief Executive Officer

CERTIFICATION

I, Steven P. Rasche, certify that:

1. I have reviewed this annual report on Form 10-K of Alabama Gas Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 15, 2016	Signature:	/s/ Steven P. Rasche
			Steven P. Rasche
			Chief Financial Officer

EX-32.1

Exhibit 32.1

Section 1350 Certification

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, I, Suzanne Sitherwood, President and Chief Executive Officer of Spire Inc., hereby certify that

(a) To the best of my knowledge, the accompanying report on Form 10-K for the period ended September 30, 2016 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(b) To the best of my knowledge, the information contained in the accompanying report on Form 10-K for the period ended September 30, 2016 fairly presents, in all material respects, the financial condition and results of operations of Spire Inc.

Date:	November 15, 2016	Signature:	/s/ Suzanne Sitherwood
			Suzanne Sitherwood
			President and Chief Executive Officer

Section 1350 Certification

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, I, Steven P. Rasche, Executive Vice President and Chief Financial Officer of Spire Inc., hereby certify that

(a) To the best of my knowledge, the accompanying report on Form 10-K for the period ended September 30, 2016 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(b) To the best of my knowledge, the information contained in the accompanying report on Form 10-K for the period ended September 30, 2016 fairly presents, in all material respects, the financial condition and results of operations of Spire Inc.

Date:	November 15, 2016	Signature:	/s/ Steven P. Rasche
			Steven P. Rasche
			Executive Vice President and Chief Financial Officer

EX-32.2

Exhibit 32.2

Section 1350 Certification

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, I, Steven L. Lindsey, Chief Executive Officer and President of Laclede Gas Company, hereby certify that

(a) To the best of my knowledge, the accompanying report on Form 10-K for the period ended September 30, 2016 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(b) To the best of my knowledge, the information contained in the accompanying report on Form 10-K for the period ended September 30, 2016 fairly presents, in all material respects, the financial condition and results of operations of Laclede Gas Company.

Date:	November 15, 2016	Signature:	/s/ Steven L. Lindsey
			Steven L. Lindsey
			Chief Executive Officer and President

Section 1350 Certification

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, I, Steven P. Rasche, Chief Financial Officer of Laclede Gas Company, hereby certify that

(a) To the best of my knowledge, the accompanying report on Form 10-K for the period ended September 30, 2016 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(b) To the best of my knowledge, the information contained in the accompanying report on Form 10-K for the period ended September 30, 2016 fairly presents, in all material respects, the financial condition and results of operations of Laclede Gas Company.

Date:	November 15, 2016	Signature:	/s/ Steven P. Rasche
			Steven P. Rasche
			Executive Vice President and Chief Financial Officer

EX-32.3

Exhibit 32.3

Section 1350 Certification

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, I, Steven L. Lindsey, Chief Executive Officer and President of Alabama Gas Corporation, hereby certify that

(a) To the best of my knowledge, the accompanying report on Form 10-K for the period ended September 30, 2016 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(b) To the best of my knowledge, the information contained in the accompanying report on Form 10-K for the period ended September 30, 2016 fairly presents, in all material respects, the financial condition and results of operations of Alabama Gas Corporation.

Date:	November 15, 2016	Signature:	/s/ Steven L. Lindsey
			Steven L. Lindsey
			Chief Executive Officer

Section 1350 Certification

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, I, Steven P. Rasche, Chief Financial Officer of Alabama Gas Corporation, hereby certify that

(a) To the best of my knowledge, the accompanying report on Form 10-K for the period ended September 30, 2016 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(b) To the best of my knowledge, the information contained in the accompanying report on Form 10-K for the period ended September 30, 2016 fairly presents, in all material respects, the financial condition and results of operations of Alabama Gas Corporation.

Date:	November 15, 2016	Signature:	/s/ Steven P. Rasche
			Steven P. Rasche
			Chief Financial Officer

XML

Document and Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2016	Nov. 11, 2016	Mar. 31, 2016
Entity Information [Line Items]
Entity Registrant Name	SPIRE INC
Entity Central Index Key	0001126956
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 2,843,343,450
Entity Common Stock, Shares Outstanding		45,656,218
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Laclede Gas
Entity Information [Line Items]
Entity Registrant Name	LACLEDE GAS CO
Entity Central Index Key	0000057183
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			0
Entity Common Stock, Shares Outstanding		24,577
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Alagasco
Entity Information [Line Items]
Entity Registrant Name	ALABAMA GAS CORP
Entity Central Index Key	0000003146
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		1,972,052
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Sep. 30, 2016

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Operating Revenues:
Gas Utility		$ 1,457.2	$ 1,891.8	$ 1,462.6
Gas Marketing and other		80.1	84.6	164.6
Total Operating Revenues		1,537.3	1,976.4	1,627.2
Gas Utility
Natural and propane gas		492.2	882.4	731.7
Other operation and maintenance expenses		377.5	390.6	287.8
Depreciation and amortization		136.9	129.9	82.4
Taxes, other than income taxes		125.2	142.1	112.0
Total Gas Utility Operating Expenses		1,131.8	1,545.0	1,213.9
Gas Marketing and other		123.2	158.9	246.9
Total Operating Expenses		1,255.0	1,703.9	1,460.8
Operating Income		282.3	272.5	166.4
Other Income and (Income Deductions) – Net		8.6	1.2	(3.3)
Interest Charges:
Interest on long-term debt		67.6	66.6	39.3
Other interest charges		9.6	8.0	6.9
Total Interest Charges		77.2	74.6	46.2
Income Before Income Taxes		213.7	199.1	116.9
Income Tax Expense		69.5	62.2	32.3
Net Income		$ 144.2	$ 136.9	$ 84.6
Weighted Average Number of Common Shares Outstanding:
Basic (in shares)		44.1	43.2	35.8
Diluted (in shares)		44.3	43.3	35.9
Basic Earnings Per Share of Common Stock (in dollars per share)		$ 3.26	$ 3.16	$ 2.36
Diluted Earnings Per Share of Common Stock (in dollars per share)		$ 3.24	$ 3.16	$ 2.35
Laclede Gas
Operating Revenues:
Gas Utility		$ 1,087.5	$ 1,416.6	$ 1,448.1
Other		0.0	0.0	0.1
Total Operating Revenues		1,087.5	1,416.6	1,448.2
Gas Utility
Natural and propane gas		471.3	786.1	816.9
Other operation and maintenance expenses		244.4	253.6	276.4
Depreciation and amortization		88.6	82.6	78.5
Taxes, other than income taxes		96.3	108.9	110.1
Total Gas Utility Operating Expenses		900.6	1,231.2	1,281.9
Gas Marketing and other		0.0	0.0	(0.1)
Total Operating Expenses		900.6	1,231.2	1,281.8
Operating Income		186.9	185.4	166.4
Other Income and (Income Deductions) – Net		1.8	(0.5)	(3.4)
Interest Charges:
Interest on long-term debt		32.9	33.1	34.4
Other interest charges		4.5	3.3	3.0
Total Interest Charges		37.4	36.4	37.4
Income Before Income Taxes		151.3	148.5	125.6
Income Tax Expense		45.4	43.2	35.5
Net Income		105.9	105.3	$ 90.1
Alagasco
Operating Revenues:
Gas Utility	$ 417.2	368.5	479.2
Total Operating Revenues	417.2	368.5	479.2
Gas Utility
Natural and propane gas	184.5	67.3	171.5
Other operation and maintenance expenses	107.5	133.5	138.0
Depreciation and amortization	34.4	47.8	47.3
Taxes, other than income taxes	28.6	28.4	33.2
Total Operating Expenses	355.0	277.0	390.0
Operating Income	62.2	91.5	89.2
Other Income and (Income Deductions) – Net	2.2	7.9	2.0
Interest Charges:
Interest on long-term debt	10.1	11.4	11.6
Other interest charges	1.4	2.4	2.3
Total Interest Charges	11.5	13.8	13.9
Income Before Income Taxes	52.9	85.6	77.3
Income Tax Expense	19.9	32.4	29.3
Net Income	$ 33.0	$ 53.2	$ 48.0

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Net income	$ 144.2	$ 136.9	$ 84.6
Cash flow hedging derivative instruments:
Net hedging loss arising during the period	(4.0)	(5.5)	(4.5)
Reclassification adjustment for loss included in net income	1.1	4.4	2.5
Net unrealized loss on cash flow hedging derivative instruments	(2.9)	(1.1)	(2.0)
Defined benefit pension and other postretirement benefit plans:
Net actuarial gain arising during the period	0.0	0.1	0.0
Amortization of actuarial (gain) loss included in net periodic pension and postretirement benefit cost	(0.3)	0.4	0.5
Net defined benefit pension and other postretirement benefit plans	(0.3)	0.5	0.5
Other Comprehensive Loss, Before Tax	(3.2)	(0.6)	(1.5)
Income Tax Benefit Related to Items of Other Comprehensive Loss	(1.0)	(0.3)	(0.6)
Other Comprehensive Loss, Net of Tax	(2.2)	(0.3)	(0.9)
Comprehensive Income	142.0	136.6	83.7
Laclede Gas
Net income	105.9	105.3	90.1
Cash flow hedging derivative instruments:
Net hedging loss arising during the period	0.0	(1.2)	0.1
Reclassification adjustment for loss included in net income	0.5	0.9	(0.2)
Net unrealized loss on cash flow hedging derivative instruments	0.5	(0.3)	(0.1)
Defined benefit pension and other postretirement benefit plans:
Net actuarial gain arising during the period	0.0	0.1	0.0
Amortization of actuarial (gain) loss included in net periodic pension and postretirement benefit cost	(0.3)	0.4	0.4
Net defined benefit pension and other postretirement benefit plans	(0.3)	0.5	0.4
Loss on available for sale securities	(0.1)	0.0	0.0
Other Comprehensive Loss, Before Tax	0.1	0.2	0.3
Income Tax Benefit Related to Items of Other Comprehensive Loss	0.2	0.0	0.1
Other Comprehensive Loss, Net of Tax	(0.1)	0.2	0.2
Comprehensive Income	$ 105.8	$ 105.5	$ 90.3

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
ASSETS
Utility Plant	$ 4,793.6	$ 4,234.5
Less: Accumulated depreciation and amortization	1,506.4	1,307.0
Net Utility Plant	3,287.2	2,927.5
Non-utility property (net of accumulated depreciation and amortization, $8.1 and $7.5 at September 30, 2016 and 2015, respectively)	13.7	13.7
Goodwill	1,164.9	946.0
Other investments	62.1	59.9
Other Property and Investments	1,240.7	1,019.6
Current Assets:
Cash and cash equivalents	5.2	13.8
Accounts receivable:
Utility	127.8	138.1
Other	113.4	86.7
Allowance for doubtful accounts	(20.5)	(14.2)
Delayed customer billings	1.6	2.6
Inventories:
Natural gas	174.0	188.6
Propane gas	12.0	12.0
Materials and supplies	16.3	14.8
Natural gas receivable	9.7	17.3
Derivative instrument assets	11.4	4.6
Unamortized purchased gas adjustments	49.7	12.9
Other regulatory assets	44.2	27.6
Deferred income tax	0.0	5.8
Prepayments and other	24.8	25.3
Total Current Assets	569.6	530.1
Deferred Charges:
Regulatory assets	838.0	737.6
Other	141.9	75.4
Total Deferred Charges	979.9	813.0
Total Assets	6,077.4	5,290.2
Capitalization:
Common stock equity	1,768.2	1,573.6
Long-term debt	1,833.7	1,771.5
Total Capitalization	3,601.9	3,345.1
Current Liabilities:
Current portion of long-term debt	250.0	80.0
Notes payable	398.7	338.0
Accounts payable	210.9	146.5
Advance customer billings	70.2	44.3
Wages and compensation accrued	39.8	32.7
Dividends payable	23.5	21.1
Customer deposits	34.9	32.1
Interest accrued	14.8	14.3
Unamortized purchased gas adjustments	1.7	28.2
Taxes accrued	55.2	51.7
Other regulatory liabilities	28.9	32.4
Other	32.7	32.5
Total Current Liabilities	1,161.3	853.8
Deferred Credits and Other Liabilities:
Deferred income taxes	607.3
Deferred income taxes		482.1
Pension and postretirement benefit costs	303.7	253.4
Asset retirement obligations	206.4	159.2
Regulatory liabilities	130.7	119.3
Other	66.1	77.3
Total Deferred Credits and Other Liabilities	1,314.2	1,091.3
Commitments and Contingencies
Total Capitalization and Liabilities	6,077.4	5,290.2
Laclede Gas
ASSETS
Utility Plant	2,718.5	2,579.1
Less: Accumulated depreciation and amortization	604.5	590.0
Net Utility Plant	2,114.0	1,989.1
Goodwill	210.2	210.2
Other investments	57.3	55.3
Other Property and Investments	267.5	265.5
Current Assets:
Cash and cash equivalents	2.1	1.7
Accounts receivable:
Utility	87.9	103.4
Other	11.4	25.2
Allowance for doubtful accounts	(16.1)	(10.0)
Delayed customer billings	1.6	2.6
Receivables from associated companies	2.2	2.5
Inventories:
Natural gas	127.3	138.2
Propane gas	12.0	12.0
Materials and supplies	9.2	9.3
Derivative instrument assets	4.9	0.0
Unamortized purchased gas adjustments	43.1	12.9
Other regulatory assets	23.9	16.2
Deferred income tax	0.0	0.4
Prepayments and other	14.5	12.5
Total Current Assets	324.0	326.5
Deferred Charges:
Regulatory assets	589.8	573.6
Other	5.3	12.8
Total Deferred Charges	595.1	586.4
Total Assets	3,300.6	3,167.5
Capitalization:
Common stock equity	1,068.5	1,037.8
Long-term debt	808.3	808.1
Total Capitalization	1,876.8	1,845.9
Current Liabilities:
Notes payable	243.7	233.0
Accounts payable	67.6	61.5
Accounts payable to associated companies	5.4	5.5
Advance customer billings	49.1	25.2
Wages and compensation accrued	29.9	26.8
Dividends payable	14.0	19.9
Customer deposits	13.5	13.0
Interest accrued	7.7	7.6
Taxes accrued	29.1	25.4
Other regulatory liabilities	1.3	0.6
Other	9.9	18.5
Total Current Liabilities	471.2	437.0
Deferred Credits and Other Liabilities:
Deferred income taxes	556.9
Deferred income taxes		485.2
Pension and postretirement benefit costs	211.8	207.8
Asset retirement obligations	75.2	72.4
Regulatory liabilities	67.3	70.6
Other	41.4	48.6
Total Deferred Credits and Other Liabilities	952.6	884.6
Commitments and Contingencies
Total Capitalization and Liabilities	3,300.6	3,167.5
Alagasco
ASSETS
Utility Plant	1,729.6	1,655.4
Less: Accumulated depreciation and amortization	756.6	717.0
Net Utility Plant	973.0	938.4
Current Assets:
Cash and cash equivalents	0.0	7.2
Accounts receivable:
Utility	34.0	34.7
Other	7.2	5.2
Allowance for doubtful accounts	(3.3)	(4.2)
Inventories:
Natural gas	34.6	40.4
Materials and supplies	5.9	5.4
Unamortized purchased gas adjustments	5.6	0.0
Other regulatory assets	14.9	11.4
Deferred income tax	0.0	6.2
Prepayments and other	5.1	4.6
Total Current Assets	104.0	110.9
Deferred Charges:
Regulatory assets	230.7	163.6
Deferred income tax	221.4
Deferred income tax		248.4
Other	63.2	57.7
Total Deferred Charges	515.3	469.7
Total Assets	1,592.3	1,519.0
Capitalization:
Common stock equity	867.3	874.6
Long-term debt	250.0	170.0
Total Capitalization	1,117.3	1,044.6
Current Liabilities:
Current portion of long-term debt	0.0	80.0
Notes payable	82.0	31.0
Accounts payable	34.3	21.8
Accounts payable to associated companies	0.4	0.2
Advance customer billings	21.1	19.1
Wages and compensation accrued	7.8	5.8
Customer deposits	18.2	19.1
Interest accrued	3.3	3.5
Unamortized purchased gas adjustments	0.0	28.2
Taxes accrued	21.6	26.0
Other regulatory liabilities	22.7	31.8
Other	6.3	5.4
Total Current Liabilities	217.7	271.9
Deferred Credits and Other Liabilities:
Pension and postretirement benefit costs	74.3	45.6
Asset retirement obligations	120.1	86.6
Regulatory liabilities	41.7	48.7
Other	21.2	21.6
Total Deferred Credits and Other Liabilities	257.3	202.5
Total Capitalization and Liabilities	$ 1,592.3	$ 1,519.0

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Assets
Non-utility property, accumulated depreciation and amortization	$ 8.1	$ 7.5

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CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Common Stock Equity:
Common stock, par value $1 per share	$ 45.6	$ 43.3
Paid-in capital	1,175.9	1,038.1
Retained earnings	550.9	494.2
Accumulated other comprehensive loss	(4.2)	(2.0)
Total Common Stock Equity	1,768.2	1,573.6
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	1,835.8	1,773.8
Unamortized discounts on long-term debt	(2.1)	(2.3)
Total Long-Term Debt	1,833.7	1,771.5
Total Capitalization	3,601.9	3,345.1
Spire | Floating Rate Senior Notes, due August 15, 2017
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	0.0	250.0
Spire | 2.55% Senior Notes, due August 15, 2019
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	125.0	125.0
Spire | 2.52% Senior Notes, due September 1, 2021
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	35.0	0.0
Spire | 2.0% Series A Remarketable Subordinated Notes, due April 1, 2022
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	143.8	143.8
Spire | 3.31% Notes Payable, due December 15, 2022
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	25.0	25.0
Spire | 3.13% Senior Notes, due September 1, 2026
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	130.0	0.0
Spire | 4.70% Senior Notes, due August 15, 2044
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	250.0	250.0
Laclede Gas
Common Stock Equity:
Common stock, par value $1 per share	0.1	0.1
Paid-in capital	751.9	748.2
Retained earnings	318.3	291.2
Accumulated other comprehensive loss	(1.8)	(1.7)
Total Common Stock Equity	1,068.5	1,037.8
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	810.0	810.0
Unamortized discounts on long-term debt	(1.7)	(1.9)
Total Long-Term Debt	808.3	808.1
Total Capitalization	1,876.8	1,845.9
Laclede Gas | 2.0% Series, due August 15, 2018
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	100.0	100.0
Laclede Gas | 5.5% Series, due May 1, 2019
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	50.0	50.0
Laclede Gas | 3.0% Series, due March 15, 2023
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	55.0	55.0
Laclede Gas | 3.4% Series, due August 15, 2023
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	250.0	250.0
Laclede Gas | 3.4% Series, due March 15, 2028
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	45.0	45.0
Laclede Gas | 7.0% Series, due June 1, 2029
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	25.0	25.0
Laclede Gas | 7.9% Series, due September 15, 2030
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	30.0	30.0
Laclede Gas | 6.0% Series, due May 1, 2034
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	100.0	100.0
Laclede Gas | 6.15% Series, due June 1, 2036
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	55.0	55.0
Laclede Gas | 4.625% Series, due August 15, 2043
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	100.0	100.0
Alagasco
Common Stock Equity:
Common stock, par value $1 per share, and paid-in capital	451.9	480.9
Retained earnings	415.4	393.7
Total Common Stock Equity	867.3	874.6
Long-Term Debt - Laclede Gas:
Total Long-Term Debt	250.0	170.0
Total Capitalization	1,117.3	1,044.6
Alagasco | 5.2% Notes, due January 15, 2020
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	40.0	40.0
Alagasco | 3.86% Notes, due December 23, 2021
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	50.0	50.0
Alagasco | 3.21% Notes, due September 15, 2025
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	35.0	35.0
Alagasco | 5.9% Notes, due January 15, 2037
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	45.0	45.0
Alagasco | 4.31% Notes, due December 1, 2045
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	80.0	0.0
Other | 3.10%, due December 30, 2018
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	5.0	0.0
Other | 4.14%, due September 30, 2021
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	20.0	0.0
Other | 5.00%, due September 30, 2031
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	$ 42.0	$ 0.0

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares	Sep. 30, 2016	Sep. 30, 2015
Long - Term Debt - Laclede Gas:
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, authorized (in shares)	70,000,000	70,000,000
Common stock, outstanding (in shares)	45,650,642	43,335,012
Spire | 2.55% Senior Notes, due August 15, 2019
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	2.55%	2.55%
Spire | 2.52% Senior Notes, due September 1, 2021
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	2.52%	2.52%
Spire | 3.31% Notes Payable, due December 15, 2022
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	3.31%	3.31%
Spire | 2.0% Series A Remarketable Subordinated Notes, due April 1, 2022
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	2.00%	2.00%
Spire | 3.13% Senior Notes, due September 1, 2026
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	3.13%	3.13%
Spire | 4.70% Senior Notes, due August 15, 2044
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	4.70%	4.70%
Laclede Gas
Long - Term Debt - Laclede Gas:
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, authorized (in shares)	50,000,000	50,000,000
Common stock, outstanding (in shares)	24,577	24,577
Laclede Gas | 2.0% Series, due August 15, 2018
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	2.00%	2.00%
Laclede Gas | 5.5% Series, due May 1, 2019
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	5.50%	5.50%
Laclede Gas | 3.0% Series, due March 15, 2023
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	3.00%	3.00%
Laclede Gas | 3.4% Series, due August 15, 2023
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	3.40%	3.40%
Laclede Gas | 3.4% Series, due March 15, 2028
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	3.40%	3.40%
Laclede Gas | 7.0% Series, due June 1, 2029
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	7.00%	7.00%
Laclede Gas | 7.9% Series, due September 15, 2030
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	7.90%	7.90%
Laclede Gas | 6.0% Series, due May 1, 2034
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	6.00%	6.00%
Laclede Gas | 6.15% Series, due June 1, 2036
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	6.15%	6.15%
Laclede Gas | 4.625% Series, due August 15, 2043
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	4.625%	4.625%
Alagasco
Long - Term Debt - Laclede Gas:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, authorized (in shares)	3,000,000	3,000,000
Common stock, outstanding (in shares)	1,972,052	1,972,052
Alagasco | 5.2% Notes, due January 15, 2020
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	5.20%	5.20%
Alagasco | 3.86% Notes, due December 23, 2021
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	3.86%	3.86%
Alagasco | 3.21% Notes, due September 15, 2025
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	3.21%	3.21%
Alagasco | 5.9% Notes, due January 15, 2037
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	5.90%	5.90%
Alagasco | 4.31% Notes, due December 1, 2045
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	4.31%	4.31%
Other | 3.10%, due December 30, 2018
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	3.10%	3.10%
Other | 4.14%, due September 30, 2021
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	4.14%	4.14%
Other | 5.00%, due September 30, 2031
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	5.00%	5.00%

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CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY - USD ($) $ in Millions	Total	Common Stock Outstanding	Paid-in Capital	Retained Earnings	AOCI	Laclede Gas	Laclede Gas Common Stock Outstanding	Laclede Gas Paid-in Capital	Laclede Gas Retained Earnings	Laclede Gas AOCI	Alagasco	Alagasco Common Stock Outstanding	Alagasco Paid-in Capital	Alagasco Retained Earnings
BALANCE (in shares) at Sep. 30, 2013		32,696,836					24,549
BALANCE at Sep. 30, 2013	$ 1,046.3	$ 32.7	$ 594.3	$ 420.1	$ (0.8)	$ 973.9	$ 0.1	$ 738.1	$ 237.8	$ (2.1)
Stockholders' Equity Rollforward
Net income	84.6			84.6		90.1			90.1
Common stock offering (in shares)		10,350,000					28
Common stock offering	456.8	$ 10.4	446.4			1.1		1.1
Equity units offering	(19.7)		(19.7)
Dividend reinvestment plan (in shares)		33,667
Dividend reinvestment plan	1.5	$ 0.0	1.5
Stock-based compensation costs	5.8		5.8			4.2		4.2
Equity Incentive Plan (in shares)		97,902
Equity Incentive Plan	1.7	$ 0.1	1.6
Employees’ taxes paid associated with restricted shares withheld upon vesting	(1.1)		(1.1)
Tax benefit - stock compensation	0.6		0.6			0.6		0.6
Dividends declared on common stock	(67.2)			(67.2)		(62.3)			(62.3)
Other comprehensive loss, net of tax	(0.9)				(0.9)	0.2				0.2
BALANCE (in shares) at Sep. 30, 2014		43,178,405					24,577					1,972,052
BALANCE at Sep. 30, 2014	1,508.4	$ 43.2	1,029.4	437.5	(1.7)	1,007.8	$ 0.1	744.0	265.6	(1.9)	$ 849.6	$ 0.0	$ 503.9	$ 345.7
BALANCE (in shares) at Dec. 31, 2013												1,972,052
BALANCE at Dec. 31, 2013											384.6	$ 0.0	34.5	350.1
Stockholders' Equity Rollforward
Net income											33.0			33.0
Purchase accounting adjustments											469.4		469.4
Dividends declared on common stock											(37.4)			(37.4)
BALANCE (in shares) at Sep. 30, 2014		43,178,405					24,577					1,972,052
BALANCE at Sep. 30, 2014	1,508.4	$ 43.2	1,029.4	437.5	(1.7)	1,007.8	$ 0.1	744.0	265.6	(1.9)	849.6	$ 0.0	503.9	345.7
Stockholders' Equity Rollforward
Net income	136.9			136.9		105.3			105.3		48.0			48.0
Purchase accounting adjustments											4.0		4.0
Dividend reinvestment plan (in shares)		31,166
Dividend reinvestment plan	1.6		1.6
Stock-based compensation costs	3.0		3.0			3.7		3.7
Equity Incentive Plan (in shares)		125,441
Equity Incentive Plan	5.1	$ 0.1	5.0
Employees’ taxes paid associated with restricted shares withheld upon vesting	(1.6)		(1.6)
Tax benefit - stock compensation	0.7		0.7			0.5		0.5
Dividends declared on common stock	(80.2)			(80.2)		(79.7)			(79.7)
Return of capital to Spire											(27.0)		(27.0)
Other comprehensive loss, net of tax	(0.3)				(0.3)	0.2				0.2
BALANCE (in shares) at Sep. 30, 2015		43,335,012					24,577					1,972,052
BALANCE at Sep. 30, 2015	1,573.6	$ 43.3	1,038.1	494.2	(2.0)	1,037.8	$ 0.1	748.2	291.2	(1.7)	874.6	$ 0.0	480.9	393.7
Stockholders' Equity Rollforward
Net income	144.2			144.2		105.9			105.9		53.2			53.2
Common stock offering (in shares)		2,185,000
Common stock offering	133.2	$ 2.2	131.0
Dividend reinvestment plan (in shares)		22,878
Dividend reinvestment plan	1.4		1.4
Stock-based compensation costs	2.2		2.2			3.7		3.7
Equity Incentive Plan (in shares)		107,752
Equity Incentive Plan	5.1	$ 0.1	5.0
Employees’ taxes paid associated with restricted shares withheld upon vesting	(1.8)		(1.8)
Dividends declared on common stock	(87.5)			(87.5)		(78.8)			(78.8)		(31.5)			(31.5)
Return of capital to Spire											(29.0)		(29.0)
Other comprehensive loss, net of tax	(2.2)				(2.2)	(0.1)				(0.1)
BALANCE (in shares) at Sep. 30, 2016		45,650,642					24,577					1,972,052
BALANCE at Sep. 30, 2016	$ 1,768.2	$ 45.6	$ 1,175.9	$ 550.9	$ (4.2)	$ 1,068.5	$ 0.1	$ 751.9	$ 318.3	$ (1.8)	$ 867.3	$ 0.0	$ 451.9	$ 415.4

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CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Statement of Stockholders' Equity [Abstract]
Dividends declared, common stock (in dollars per share)	$ 1.96	$ 1.84	$ 1.76

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Operating Activities:
Net income		$ 144.2	$ 136.9	$ 84.6
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, amortization and accretion		137.5	130.8	83.3
Deferred income taxes and investment tax credits		68.8	65.5	31.4
Changes in assets and liabilities:
Accounts receivable – net		(12.3)	(4.8)	(5.3)
Unamortized purchased gas adjustments		(64.3)	46.9	(36.4)
Deferred purchased gas costs		11.5	(19.8)	13.9
Accounts payable		30.0	(30.0)	8.6
Delayed / advance customer billings – net		26.9	20.3	(19.1)
Taxes accrued		(0.4)	(17.0)	(0.8)
Inventories		16.5	54.8	(15.5)
Other assets and liabilities		(35.0)	(67.6)	(27.5)
Other		4.9	6.4	5.4
Net cash provided by operating activities		328.3	322.4	122.6
Investing Activities:
Capital expenditures		(293.3)	(289.8)	(171.0)
Acquisition of EnergySouth (net of $2.0 cash acquired)		(317.7)	0.0	0.0
Acquisition of Alagasco (net of $12.1 cash acquired in 2014)		0.0	(8.2)	(1,305.2)
Acquisition of MGE		0.0	0.0	23.9
Proceeds from sale of right to acquire New England Gas Company		0.0	0.0	11.0
Other		(1.7)	(0.7)	3.7
Net cash used in investing activities		(612.7)	(298.7)	(1,437.6)
Financing Activities:
Issuance of long-term debt		245.0	35.0	768.8
Repayment of long-term debt		(80.0)	(34.8)	(80.0)
Issuance of short-term debt - net		60.7	50.8	198.1
Issuance of common stock		137.1	3.1	460.0
Dividends paid		(85.2)	(79.0)	(61.9)
Other		(1.8)	(1.1)	(6.9)
Net cash provided by (used in) financing activities		275.8	(26.0)	1,278.1
Net Decrease in Cash and Cash Equivalents		(8.6)	(2.3)	(36.9)
Cash and Cash Equivalents at Beginning of Year		13.8	16.1	53.0
Cash and Cash Equivalents at End of Year	$ 16.1	5.2	13.8	16.1
Supplemental disclosure of cash (paid) refunded for:
Interest		(72.5)	(65.3)	(40.6)
Income taxes		2.9	1.3	(3.4)
Laclede Gas
Operating Activities:
Net income		105.9	105.3	90.1
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, amortization and accretion		88.6	82.6	78.5
Deferred income taxes and investment tax credits		45.3	45.4	35.6
Changes in assets and liabilities:
Accounts receivable – net		35.7	9.9	(21.5)
Unamortized purchased gas adjustments		(30.2)	41.1	(36.4)
Deferred purchased gas costs		11.5	(19.8)	13.9
Accounts payable		0.9	(11.4)	6.8
Delayed / advance customer billings – net		24.9	17.9	(19.1)
Taxes accrued		4.9	(14.6)	10.0
Inventories		11.0	51.2	(26.4)
Other assets and liabilities		(29.6)	(32.8)	(3.3)
Other		2.3	2.8	2.8
Net cash provided by operating activities		271.2	277.6	131.0
Investing Activities:
Capital expenditures		(197.8)	(198.6)	(163.0)
Acquisition of MGE		0.0	0.0	23.9
Other		1.1	2.9	4.1
Net cash used in investing activities		(196.7)	(195.7)	(135.0)
Financing Activities:
Repayment of long-term debt		0.0	0.0	(80.0)
Issuance of short-term debt - net		10.7	(5.7)	164.6
Borrowings from Spire		0.0	18.4	276.1
Repayment of borrowings from Spire		0.0	(18.4)	(322.7)
Issuance of common stock		0.0	0.0	1.2
Dividends paid		(84.8)	(78.7)	(57.2)
Other		0.0	0.5	1.8
Net cash provided by (used in) financing activities		(74.1)	(83.9)	(16.2)
Net Decrease in Cash and Cash Equivalents		0.4	(2.0)	(20.2)
Cash and Cash Equivalents at Beginning of Year		1.7	3.7	23.9
Cash and Cash Equivalents at End of Year	3.7	2.1	1.7	3.7
Supplemental disclosure of cash (paid) refunded for:
Interest		(35.7)	(31.0)	(36.4)
Income taxes		2.1	0.7	(0.2)
Alagasco
Operating Activities:
Net income	33.0	53.2	48.0
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, amortization and accretion	34.4	47.8	47.3
Deferred income taxes and investment tax credits	4.0	33.2	29.2
Changes in assets and liabilities:
Accounts receivable – net	26.4	(11.1)	(9.1)
Unamortized purchased gas adjustments	24.8	(33.8)	5.8
Accounts payable	(11.5)	9.1	(10.4)
Delayed / advance customer billings – net	(0.3)	2.0	2.4
Taxes accrued	1.9	(5.2)	(4.0)
Inventories	(11.8)	5.3	7.2
Other assets and liabilities	17.1	(3.2)	(18.0)
Other	(3.0)	0.9	2.0
Net cash provided by operating activities	115.0	98.2	100.4
Investing Activities:
Capital expenditures	(46.2)	(93.4)	(85.8)	(46.2)
Proceeds from the sale of assets	0.8	0.0	0.0
Other	0.0	(2.5)	(1.0)
Net cash used in investing activities	(45.4)	(95.9)	(86.8)
Financing Activities:
Issuance of long-term debt	0.0	80.0	35.0
Repayment of long-term debt	0.0	(80.0)	(34.8)
Issuance of short-term debt - net	(34.0)	51.0	15.0
Return of capital to Spire	0.0	(29.0)	(27.0)
Dividends paid	(37.4)	(31.5)	0.0
Other	4.4	0.0	(0.2)
Net cash provided by (used in) financing activities	(67.0)	(9.5)	(12.0)
Net Decrease in Cash and Cash Equivalents	2.6	(7.2)	1.6
Cash and Cash Equivalents at Beginning of Year	3.0	7.2	5.6
Cash and Cash Equivalents at End of Year	5.6	0.0	7.2	$ 5.6
Supplemental disclosure of cash (paid) refunded for:
Interest	(9.6)	(12.4)	(12.3)
Income taxes	$ (20.4)	$ 0.8	$ 0.0

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2014
Statement of Cash Flows [Abstract]
Cash acquired from acquisition	$ 2.0	$ 12.1

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION –These notes are an integral part of the accompanying audited financial statements of Spire Inc. (Spire or the Company), as well as Laclede Gas Company (Laclede Gas or the Missouri Utilities) and Alabama Gas Corporation (Alagasco). Laclede Gas, which includes the operations of Missouri Gas Energy (MGE), and Alagasco are wholly owned subsidiaries of the Company. Laclede Gas, Alagasco and the subsidiaries of EnergySouth, Inc. (EnergySouth) are collectively referred to as the Utilities. The subsidiaries of EnergySouth are Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas and Oil Company (Willmut Gas). The accompanying audited financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

The consolidated financial position, results of operations, and cash flows of Spire are primarily derived from the financial position, results of operations, and cash flows of the Utilities. In compliance with GAAP, transactions between Laclede Gas and Alagasco and their affiliates, as well as intercompany balances on their balance sheets, have not been eliminated from their separate financial statements. The Company’s September 12, 2016 acquisition of EnergySouth and the August 31, 2014 acquisition of Alagasco are included in the results of operations since their acquisition dates and impact the comparability of the financial statement periods presented for the Company. For a further discussion of the acquisitions, see Note 2, Acquisitions. The Utilities are regulated natural gas distribution utilities. Due to the seasonal nature of the Utilities, the earnings of Spire, Laclede Gas and Alagasco are typically concentrated during the heating season of November through April each fiscal year.

Effective September 2, 2014, Alagasco amended its bylaws to change Alagasco’s fiscal year from beginning January 1 and ending on December 31, to beginning October 1 and ending September 30. As a result, the financial statements covering the nine-month period from January 1, 2014 through September 30, 2014 (the “transition period”) were included in Alagasco’s transition report on Form 10-K/T for such period and are presented in the financial statements and notes herein.

NATURE OF OPERATIONS – Spire Inc. (NYSE: SR), headquartered in St. Louis, Missouri, is a public utility holding company. The Company has two reportable segments: Gas Utility and Gas Marketing. The Gas Utility segment consists of the regulated natural gas distribution operations of the Company and is the core business segment of Spire in terms of revenue and earnings generation. The Gas Utility segment is comprised of the operations of the Missouri Utilities, serving St. Louis and eastern Missouri, Kansas City and western Missouri (through MGE), Alagasco serving central and northern Alabama, and the subsidiaries of EnergySouth, serving southern Alabama and south-central Mississippi. Spire’s primary non-utility business, Laclede Energy Resources, Inc. (LER), included in the Gas Marketing segment, provides non-regulated natural gas services. The activities of other subsidiaries are described in Note 14, Information by Operating Segment, and are reported as Other. Laclede Gas and Alagasco each have a single reportable segment.

USE OF ESTIMATES – The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

SYSTEM OF ACCOUNTS – The accounts of the Utilities are maintained in accordance with the Uniform System of Accounts prescribed by the applicable state public service commissions, which systems substantially conform to that prescribed by the Federal Energy Regulatory Commission (FERC).

UTILITY PLANT, DEPRECIATION AND AMORTIZATION – Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overheads, and an allowance for funds used during construction. The costs of units of property retired, replaced, or renewed are removed from utility plant and are charged to accumulated depreciation. Maintenance and repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expenses.

For Laclede Gas, utility plant is depreciated on a straight-line basis at rates based on estimated service lives of the various classes of property. In fiscal years 2016, 2015 and 2014, annual depreciation and amortization expense averaged 3.0% of the original cost of depreciable and amortizable property.

Laclede Gas’ capital expenditures were $197.8, $198.6 and $163.0 for fiscal years 2016, 2015, and 2014, respectively. Additionally, Laclede Gas had recorded accruals for capital expenditures totaling $14.8 at September 30, 2016, $9.6 at September 30, 2015, and $3.0 at September 30, 2014.

For Alagasco, depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of utility property at rates approved by the Alabama Public Service Commission (APSC). On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1%. As required by the APSC, Alagasco performed another depreciation study in 2015. The composite depreciation rate from this study was also approximately 3.1%. Alagasco anticipates refunding approximately $9.3 of refundable negative salvage costs through lower tariff rates over the next twelve months.

Related to the lower depreciation rates, an estimated $18.7 of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a three year period through 2019. 

Alagasco’s capital expenditures were $93.4, $85.8 and $46.2 for fiscal years 2016, 2015, and 2014, respectively. Additionally, Alagasco recorded accruals for capital expenditures totaling $6.8 at September 30, 2016, $3.1 at September 30, 2015 and $5.0 at September 30, 2014.

Accrued capital expenditures are excluded from the capital expenditures included in the statements of cash flows of the Company, Laclede Gas and Alagasco.

ASSET RETIREMENT OBLIGATIONS – Spire, Laclede Gas, and Alagasco record legal obligations associated with the retirement of long-lived assets in the period in which the obligations are incurred, if sufficient information exists to reasonably estimate the fair value of the obligations. Obligations are recorded as both a cost of the related long-lived asset and as a corresponding liability. Subsequently, the asset retirement costs are depreciated over the life of the asset and the asset retirement obligations are accreted to the expected settlement amounts. The Company, Laclede Gas and Alagasco record asset retirement obligations associated with certain safety requirements to purge and seal gas distribution mains upon retirement, the plugging and abandonment of storage wells and other storage facilities, specific service line obligations, and certain removal and disposal obligations related to components of Laclede Gas’, Alagasco’s and Mobile Gas’ distribution systems and general plant. Asset retirement obligations recorded by Spire’s other subsidiaries are not material. As authorized by the Missouri Public Service Commission (MoPSC) and APSC, Laclede Gas, Alagasco and Mobile Gas accrue future asset removal costs associated with their property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities or assets. When those utilities retire depreciable utility plant and equipment, they charge the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities or assets. The difference between removal costs recognized in depreciation rates and the accretion expense and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes. Accordingly, these differences are deferred as regulatory liabilities or assets. In the rate setting process, the regulatory liability or asset is excluded from the rate base upon which those utilities have the opportunity to earn their allowed rates of return. The costs associated with asset retirement obligations of Laclede Gas, Alagasco and Mobile Gas are either currently being recovered in rates or are probable of recovery in future rates.

The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30, as reported in the balance sheets.

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Asset retirement obligations, beginning of year	$	159.2		$	99.2		$	72.4		$	71.2		$	86.6		$	27.7
Liabilities incurred during the period	4.1			2.3			1.2			0.6			2.9			1.7
Liabilities settled during the period	(9.5		)	(2.0		)	(1.9		)	(1.9		)	(6.8		)	(0.1		)
Accretion	13.2			4.5			3.5			3.4			9.7			1.1
Revisions in estimated cash flows	27.5			55.2			—			(0.9		)	27.7			56.2
Addition of EnergySouth asset retirement obligations	11.9			—			—			—			—			—
Asset retirement obligations, end of year	$	206.4		$	159.2		$	75.2		$	72.4		$	120.1		$	86.6

REGULATED OPERATIONS – The Utilities account for their regulated operations in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.” This Topic sets forth the application of GAAP for those companies whose rates are established by or are subject to approval by an independent third-party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. In addition, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities). Management believes that the current regulatory environment supports the continued use of these regulatory accounting principles and that all regulatory assets and regulatory liabilities are recoverable or refundable through the regulatory process. See additional discussion on regulated operations in Note 15, Regulatory Matters.

As discussed below for Laclede Gas and Alagasco, the Purchased Gas Adjustment (PGA) clauses and Gas Supply Adjustment (GSA) riders allow the Utilities to pass through to customers the cost of purchased gas supplies. Regulatory assets and liabilities related to the PGA clauses and the GSA rider are both labeled Unamortized Purchased Gas Adjustments herein.

Laclede Gas

As authorized by the MoPSC, the PGA clause allows Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. To better match customer billings with market natural gas prices, Laclede Gas is allowed to file to modify, on a periodic basis, the level of gas costs in its PGA. Certain provisions of the PGA clause are included below:

• Laclede Gas has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. The MoPSC clarified that costs, cost reductions, and carrying costs associated with the Utility’s use of natural gas derivative instruments are gas costs recoverable through the PGA mechanism.

• The tariffs allow Laclede Gas flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months.

• Laclede Gas is authorized to apply carrying costs to all over- or under-recoveries of gas costs, including costs and cost reductions associated with the use of derivative instruments, including cash payments for margin deposits. Laclede Gas’ eastern Missouri service territory is also authorized to recover gas inventory carrying costs through its PGA rates to recover costs it incurs to finance its investment in gas supplies that are purchased during the storage injection season for sale during the heating season.

• The MoPSC approved a plan applicable to Laclede Gas’ gas supply commodity costs under which it retains a portion of cost savings associated with the acquisition of natural gas below an established benchmark level. This gas supply cost management program allows Laclede Gas to retain 10% of cost savings, up to a maximum of $3.0 annually. Laclede Gas did not record any income under the plan during the three fiscal years reported. Income recorded under the plan, if any, is included in Gas Utility Operating Revenues on the Consolidated Statements of Income and under Operating Revenues on Laclede Gas’ Statements of Income.

Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA clause are reflected as a deferred charge or credit at the end of the fiscal year. These costs include costs and cost reductions associated with the use of derivative instruments and gas inventory carrying costs, amounts due to or from customers related to operation of the gas supply cost management program, refunds received from the Company’s suppliers in connection with gas supply, transportation, and storage services, and carrying costs on such over- or under-recoveries. At that time, the balance is classified as a current asset or current liability and recovered from, or credited to, customers over an annual period commencing in November. The balance in the current account is amortized as amounts are reflected in customer billings.

The PGA clause also provides for the treatment of income from off-system sales and capacity release revenues. Pre-tax income from off-system sales and capacity release revenues is shared with customers, with an estimated amount assumed in PGA rates. The difference between the actual amount allocated to customers for each fiscal year and the estimated amount assumed in PGA rates is recovered from, or credited to, customers over an annual period commencing in the subsequent November. The customer share of such income is determined in accordance with the following tables, shown for each service territory for which the PGA clauses were approved by the MoPSC.

	Customer Share	Company Share
Eastern Missouri
First $2.0*	100%	—%
Next $2.0	80%	20%
Next $2.0	75%	25%
Amounts exceeding $6.0	70%	30%
* Customer share reverts to 85% and company share reverts to 15% in 2017.
Western Missouri
First $1.2	85%	15%
Next $1.2	80%	20%
Next $1.2	75%	25%
Amounts exceeding $3.6	70%	30%

Alagasco

Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA rider, which is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather-related conditions that may affect customer usage are not included in the temperature adjustment.

NATURAL GAS AND PROPANE GAS – For Laclede Gas’ eastern Missouri utility, inventory of natural gas in storage is priced on a last in, first out (LIFO) basis and inventory of propane gas in storage is priced on a first in, first out (FIFO) basis. For the rest of the Gas Utility segment, inventory of natural gas in storage is priced on the weighted average cost basis. The replacement cost of Laclede Gas’ natural gas for current use in eastern Missouri at September 30, 2016 and September 30, 2015 was less than the LIFO cost by $11.4 and $20.4, respectively. The carrying value of Laclede Gas’ inventory is not adjusted to the lower of cost or market prices because, pursuant to the Missouri Utilities’ PGA clauses, actual gas costs are recovered in customer rates. Natural gas and propane gas storage inventory in Spire’s other operating segments is recorded at the lower of average cost or market.

BUSINESS COMBINATIONS – The EnergySouth and Alagasco acquisitions are accounted for by Spire using business combination accounting. Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value. For additional information on the acquisition of EnergySouth and Alagasco, refer to Note 2, Acquisitions.

GOODWILL – Goodwill is measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Spire and Laclede Gas evaluate goodwill for impairment as of July 1st of each year, or more frequently if events and circumstances indicate that goodwill might be impaired. At July 1, 2016, 2015 and 2014, Spire and Laclede Gas each applied a quantitative goodwill evaluation model to their reporting units and concluded goodwill was not impaired because the fair value exceeded the carrying amount. The changes in the carrying amount of goodwill by reportable segment were as follows:

	Gas Utility			Gas Marketing		Other		Total
Balance as of September 30, 2013	$	247.1		$	—	$	—	$	247.1
Adjustments to finalize the 2013 acquisition of MGE	(36.9		)	—		—		(36.9		)
Acquisition of Alagasco	—			—		727.6		727.6
Balance as of September 30, 2014	210.2			—		727.6		937.8
Adjustments to finalize the acquisition of Alagasco	—			—		8.2		8.2
Balance as of September 30, 2015	210.2			—		735.8		946.0
Acquisition of EnergySouth	—			—		218.9		218.9
Balance as of September 30, 2016	$	210.2		$	—	$	954.7	$	1,164.9

IMPAIRMENT OF LONG-LIVED ASSETS – Long-lived assets classified as held and used are evaluated for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, the Company recognizes an impairment charge equal to the amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which the Company determines an asset meets held-for-sale criteria, an impairment charge is recorded to the extent the book value exceeds its fair value less cost to sell.

REVENUE RECOGNITION – The Utilities read meters and bill customers on monthly cycles. The Missouri Utilities record their gas utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues for Laclede Gas at September 30, 2016 and 2015 were $26.1 and $27.6, respectively.

Alagasco records natural gas distribution revenues in accordance with the tariff established by the APSC. The amount of accrued unbilled revenues, which are not recorded as revenues until billed, for Alagasco at September 30, 2016 and 2015 were $5.9 and $6.4, respectively. All related costs and margins are also deferred.

The subsidiaries of EnergySouth record natural gas revenues in accordance with tariffs established by the APSC and MSPSC. Unbilled revenues are accrued and related costs and margins are also deferred.

Spire’s other subsidiaries, including LER, record revenues when earned, either when the product is delivered or when services are performed.

In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. Certain of its derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815, “Derivatives and Hedging.” Those contracts are accounted for as executory contracts and recorded on an accrual basis. Revenues and expenses from such contracts are recorded using a gross presentation. Contracts not designated as normal purchases or normal sales are recorded as derivatives with changes in fair value recognized in earnings in the periods prior to physical delivery. For additional information on derivative instruments, refer to Note 10, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions are classified as trading activities for financial reporting purposes. Under GAAP, revenues and expenses associated with trading activities are presented on a net basis in Gas Marketing operating revenues (or expenses, if negative) in the Consolidated Statements of Income. This net presentation has no effect on operating income or net income.

INCOME TAXES – Spire and its subsidiaries account for income taxes under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and the respective tax basis and for tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effects on deferred tax assets and liabilities of a change in enacted tax rates is recognized in income or loss for a non-regulated company, and in a regulatory asset or regulatory liability for a regulated company. A valuation allowance is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized.

The Company accounts for uncertain tax positions in accordance with authoritative guidance. The authoritative guidance addresses the determination of whether tax benefits claimed, or expected to be claimed, on a tax return should be recorded in the financial statements. Spire may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the position will be sustained upon examination by the taxing authority, based on the technical merits of the position. Tax-related interest and penalties, if any, are classified as a liability on the balance sheets.

CASH AND CASH EQUIVALENTS – All highly liquid debt instruments purchased with original maturities of three months or less are considered to be cash equivalents. Such instruments are carried at cost, which approximates market value. Outstanding checks on the Company’s and Utilities’ bank accounts in excess of funds on deposit create book overdrafts (which are funded at the time checks are presented for payment) and are classified as Other in the Current Liabilities section of the balance sheets. Changes in book overdrafts are reflected as Operating Activities in the statements of cash flows.

NATURAL GAS RECEIVABLE – LER enters into natural gas transactions with natural gas pipeline companies known as park and loan arrangements. Under the terms of the arrangements, LER purchases natural gas from a third party and delivers that natural gas to the pipeline company for the right to receive the same quantity of natural gas from the pipeline company at the same location in a future period. These arrangements are accounted for as non-monetary transactions under GAAP and are recorded at the carrying amount. As such, natural gas receivables are reflected on the Consolidated Balance Sheets at cost, which includes related pipeline fees associated with the transactions. In the period that the natural gas is returned to LER, concurrent with the sale of the natural gas to a third party, the related natural gas receivable is expensed in the Consolidated Statements of Income. In conjunction with these transactions, LER usually enters into New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE) natural gas futures, options, and swap contracts or fixed price sales agreements to protect against market changes in future sales prices.

EARNINGS PER COMMON SHARE – GAAP requires dual presentation of basic and diluted earnings per share (EPS). EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareholders. Certain of the Company’s stock-based compensation awards pay non-forfeitable dividends to the participants during the vesting period and, as such, are deemed participating securities. Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding that are increased for additional shares that would be outstanding if potentially dilutive non-participating securities were converted to common shares, pursuant to the treasury stock method. Shares attributable to equity units, non-participating stock options and time-vested restricted stock/units are excluded from the calculation of diluted earnings per share if the effect would be antidilutive. Shares attributable to non-participating performance-contingent restricted stock awards are only included in the calculation of diluted earnings per share to the extent the underlying performance and/or market conditions are satisfied (a) prior to the end of the reporting period or (b) would be satisfied if the end of the reporting period were the end of the related contingency period and the result would be dilutive. The Company’s EPS computations are presented in Note 4, Earnings Per Common Share.

GROSS RECEIPTS AND SALES TAXES – Gross receipts taxes associated with the Company’s natural gas utility services are imposed on the Company, Laclede Gas, and Alagasco and billed to its customers. The revenue and expense amounts are recorded gross in the “Operating Revenues” and “Taxes, other than income taxes” lines, respectively, in the statements of income.

The following table presents gross receipts taxes recorded:

	2016		2015		2014
Spire	$	75.5	$	97.3	$	77.5
Laclede Gas	57.4		74.5		76.3
Alagasco	17.9		22.6		20.6

Sales taxes imposed on applicable Alagasco and Laclede Gas sales are billed to customers. These amounts are not recorded in the statements of income but are recorded as tax collections payable and included in the Other line of the Current Liabilities section of the balance sheets.

TRANSACTIONS WITH AFFILIATES –Transactions between affiliates of the Company have been eliminated from the consolidated financial statements of Spire. Other than borrowings from Spire reflected in Alagasco’s Balance Sheets and Statements of Cash Flows and normal intercompany shared services transactions, there were no transactions between Alagasco and affiliates. Laclede Gas had the following transactions with affiliates:

	2016		2015		2014
Purchases of natural gas from LER	$	46.3	$	74.1	$	89.1
Sales of natural gas to LER	1.9		4.0		5.1
Services received from Laclede Insurance Risk Services, Inc.	1.8		1.0		0.6

ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS – Trade accounts receivable are recorded at the amounts due from customers, including unbilled amounts. Estimates of the collectability of trade accounts receivable are based on historical trends, age of receivables, economic conditions, credit risk of specific customers, and other factors. Accounts receivable are written off against the allowance for doubtful accounts when they are deemed to be uncollectible. Spire’s provision for uncollectible accounts includes the amortization of previously deferred uncollectible expenses for Laclede Gas and Alagasco, as approved by the MoPSC and the APSC.

FINANCE RECEIVABLES – Alagasco finances third party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2016 and September 30, 2015, the Company’s finance receivable totaled approximately $11.8 and $11.2, respectively. Financing is available only to qualified customers who meet creditworthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third party collection agency. Alagasco had finance receivables past due 90 days or more of $0.4 at September 30, 2016 and September 30, 2015. Alagasco recorded an allowance for credit losses at September 30, 2016 and September 30, 2015 of $0.4.

GROUP MEDICAL AND WORKERS’ COMPENSATION RESERVES – The Company self-insures its group medical and workers’ compensation costs and carries stop-loss coverage in relation to medical claims and workers’ compensation claims. Reserves for amounts incurred but not reported are established based on historical cost levels and lags between occurrences and reporting.

FAIR VALUE MEASUREMENTS – Certain assets and liabilities are recognized or disclosed at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.

The levels of the hierarchy are described below:

• Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities.

• Level 2 – Pricing inputs other than quoted prices included within Level 1, which are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data.

• Level 3 – Pricing that is based upon inputs that are generally unobservable that are based on the best information available and reflect management’s assumptions about how market participants would price the asset or liability.

Assessment of the significance of a particular input to the fair value measurements may require judgment and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. Additional information about fair value measurements is provided in Note 8, Fair Value of Financial Instruments, Note 9, Fair Value Measurements, and Note 13, Pension Plans and Other Postretirement Benefits.

STOCK-BASED COMPENSATION – The Company measures stock-based compensation awards at fair value at the date of grant and recognizes the compensation cost of the awards over the requisite service period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. Refer to Note 3, Stock-Based Compensation, for further discussion of the accounting for the Company’s stock-based compensation plans.

REVISIONS TO PRIOR FINANCIAL STATEMENTS - Certain amounts in the prior period have been adjusted to conform with the current period presentation for Spire and Laclede Gas. The adjustment was related to the presentation of categories of deferred tax assets in Note 12, Income Taxes.

NEW ACCOUNTING PRONOUNCEMENTS – In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers. The core principle of the standard is when an entity transfers goods or services to customers it will recognize revenue in an amount that reflects the consideration the entity expects to be entitled to for those goods or services. ASU No. 2014-09 also requires disclosures that will enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which made the guidance in ASU No. 2014-09 effective for fiscal years beginning after December 15, 2017 and interim periods within those years, but companies may choose to adopt it one year earlier. In 2016, the FASB issued related ASU Nos. 2016-08, 2016-10, 2016-11 and 2016-12, which further modified the standards for accounting for revenue. The Company, Laclede Gas and Alagasco are currently assessing the available transition methods and the potential impacts of the updates, which must be adopted by the first quarter of fiscal year 2019.

In April 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. Currently, debt issuance costs are recorded as a deferred charge (asset), while debt discount and debt premium costs are recorded as a liability adjustment. This amendment will require debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU No. 2015-15 clarified that ASU No. 2015-03 does not address the presentation of debt issuance costs related to line-of-credit arrangements, and the Company intends to continue to report such costs as deferred charges. The new guidance is effective for the Company, Laclede Gas and Alagasco beginning in the first quarter of fiscal 2017. The application of this standard will be retrospective, wherein each balance sheet presented will be adjusted to reflect the impacts of applying the new guidance. If this ASU had been adopted as of September 30, 2016, the amounts reclassified from other deferred charges to reduce long-term debt at September 30, 2016 and 2015, respectively, would have been $13.2 and $13.0 for Spire, $4.2 and $4.8 for Laclede Gas, and $2.6 and $2.4 for Alagasco.

In November 2015, the FASB issued ASU No. 2015-17, Income Taxes: Balance Sheet classification of Deferred Taxes, to require that deferred tax liabilities and assets be classified entirely as noncurrent. This was part of the FASB’s simplification initiative intended to reduce cost and complexity in financial reporting while improving or maintaining the usefulness of the information reported to investors. The Company, Laclede Gas and Alagasco adopted this ASU in the fourth quarter of fiscal 2016. Prior periods were not retrospectively adjusted. The adoption of this accounting standard was not material to the financial statements.

In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall: Recognition and Measurement of Financial Assets and Financial Liabilities, which provides revised guidance concerning certain matters involving the recognition, measurement, and disclosure of financial instruments. It is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Company, Laclede Gas and Alagasco are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of fiscal year 2019.

In February 2016, the FASB issued ASU No. 2016-02, Leases. The new standard requires lessees to recognize a right-of-use asset and lease liability for almost all lease contracts based on the present value of lease payments. There is an exemption for short-term leases. The ASU provides new guidelines for identifying and classifying a lease, and classification affects the pattern and income statement line item for the related expense. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company, Laclede Gas and Alagasco are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of fiscal year 2020.

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The standard is intended to simplify several areas of accounting for share-based compensation arrangements, including the income tax impact, classification on the statement of cash flows and forfeitures. The ASU is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Company, Laclede Gas and Alagasco are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of fiscal year 2018.

On June 16, 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments. The standard introduces new guidance for the accounting for credit losses on instruments within its scope, including trade receivables. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, but may be adopted up to two years earlier. The Company, Laclede Gas and Alagasco are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of fiscal year 2021.

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ACQUISITIONS

12 Months Ended

Sep. 30, 2016

Business Combinations [Abstract]

ACQUISITIONS

ACQUISITIONS

Spire’s recent acquisitions are described below. The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed at the acquisition dates. Measurement period adjustments were immaterial.

	Alagasco			EnergySouth
Recognized amounts of identifiable assets acquired and liabilities assumed:
Utility plant	$	892.7		$	199.5
Cash	12.1			2.0
Other current assets	99.4			17.5
Deferred tax assets	282.0			—
Other assets	143.4			79.8
Long-term debt	(249.8		)	(67.0		)
Current portion of long-term debt	(15.0		)	—
Other current liabilities	(173.4		)	(42.7		)
Deferred tax liabilities	—			(35.5		)
Other liabilities	(130.4		)	(52.8		)
Total identifiable net assets	861.0			100.8
Goodwill	735.8			218.9
Deferred tax elimination (Spire)	(271.3		)	—
Consideration (cash)	$	1,325.5		$	319.7

Acquisition of Alagasco

Spire completed the acquisition of 100% of the common stock of Alagasco from Energen effective on August 31, 2014. Total cash consideration paid at closing, net of cash acquired and debt assumed was $1,305.2. Subsequently, the Company and Energen agreed to a final reconciliation of net assets, and $8.2 was paid by the Company to Energen on January 6, 2015, effectively increasing the total net consideration to $1,313.4.

The goodwill of $735.8 arising from this acquisition, $717.6 of which is expected to be deductible for tax purposes, is attributable to Alagasco’s assembled workforce and the expected cost efficiencies and strategic benefits of the transaction. The acquisition was supportive of the strategic focus on growing the Company’s regulated footprint and created geographic and regulatory diversity. The Company determined that the Alagasco acquisition met the scope exceptions for pushdown accounting; therefore, the goodwill was recorded on the Spire parent company balance sheet rather than the Alagasco subsidiary balance sheet and included in disclosures of segment assets under Other rather than the Gas Utility segment.

The Company and Energen made an election under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended, to treat the Alagasco acquisition as a deemed purchase and sale of assets for tax purposes. As a result of the election, goodwill was generated for tax purposes at Alagasco. For book purposes, as noted above, goodwill was recorded on the Spire parent entity and not pushed down to Alagasco. Consequently, a deferred tax asset (DTA) was recorded at Alagasco related to the excess of tax deductible goodwill over book goodwill for the stand-alone entity. That initial goodwill DTA is eliminated (along with the investment in subsidiary and Alagasco’s equity) in the Spire consolidated balance sheet because, at that consolidated level, there is no excess of tax deductible goodwill over book goodwill. As the tax goodwill is amortized and deducted for tax purposes, the DTA at Alagasco is reduced, and for Spire, a deferred tax liability (DTL) is created. For both Alagasco and consolidated Spire, the changes to the goodwill DTA/DTL are reported as a component of deferred tax expense in the income statement. Because the deferred tax expense impact will be offset by an opposite current tax expense impact, there will be no significant impact on the effective tax rate of the Company.

Acquisition of EnergySouth

Effective September 12, 2016, Spire completed the acquisition of 100% of the common stock of EnergySouth, the parent company of Mobile Gas and Willmut Gas, serving natural gas utility customers in Alabama and Mississippi. This acquisition is supportive of the strategic focus on growing Spire’s gas utility business and creating geographic and regulatory diversity. Total cash consideration paid at closing, net of cash acquired and debt assumed was $317.7. The goodwill of $218.9 arising from this acquisition, which is not deductible for tax purposes, is attributable to the assembled workforce and the expected cost efficiencies and strategic benefits of the transaction. The Company did not elect pushdown accounting, so the goodwill was recorded on the Spire parent company balance sheet rather than the EnergySouth subsidiary balance sheet and is included in disclosures of segment assets under Other. Because the acquisition occurred near the end of the fiscal year and certain assessments are still in progress, the assignment of goodwill to reporting units has not yet been completed. Similarly, the recorded values of some of the assets acquired and liabilities assumed, such as those related to income taxes and contingencies, are provisional pending completion of analyses of those items.

Actual and Pro Forma Results

The results of operations of each of the acquisitions are included in the Spire statements of income from the date of acquisition, as shown in the following table.

	Alagasco							EnergySouth
	2016		2015		2014			2016
Total Operating Revenues	$	368.5	$	479.2	$	19.7		$	3.3
Net Income (Loss)	53.2		48.0		(2.9		)	(0.2		)
Earnings (Loss) Per Share	$	1.20	$	1.11	$	(0.08	)	$	—

The following unaudited pro forma financial information presents Spire’s combined results of operations as though the EnergySouth acquisition had occurred as of the beginning of fiscal year 2015 and the Alagasco acquisition had occurred as of the beginning of fiscal year 2013. The unaudited pro forma financial information is not necessarily indicative of either future results of operations or results that would have been achieved if the acquisitions had occurred as of those earlier dates. It does not reflect the costs of any integration activities. It includes estimates and assumptions which management believes are reasonable.

	2016		2015		2014
Total Operating Revenues	$	1,632.4	$	2,081.6	$	2,187.1
Net Income	153.9		143.6		133.5
Basic Earnings Per Share	$	3.48	$	3.32	$	3.11
Diluted Earnings Per Share	3.46		3.31		3.10

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STOCK-BASED COMPENSATION

12 Months Ended

Sep. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION

Spire’s 2015 incentive plan, The Laclede Group 2015 Equity Incentive Plan (the 2015 Plan), was approved at the annual meeting of shareholders of Spire on January 29, 2015. The purpose of the 2015 Plan is to encourage directors, officers, and employees of the Company and its subsidiaries to contribute to the Company’s success and align their interests with that of shareholders. To accomplish this purpose, the Compensation Committee (Committee) of the Board of Directors may grant awards under the 2015 Plan that may be earned by achieving performance objectives and/or other criteria as determined by the Committee. Under the terms of the 2015 Plan, officers and employees of the Company and its subsidiaries, as determined by the Committee, are eligible to be selected for awards. The 2015 Plan provides for restricted stock, restricted stock units, qualified and non-qualified stock options, stock appreciation rights, and performance shares payable in stock, cash, or a combination of both. The 2015 Plan generally provides a minimum vesting period of at least three years for each type of award, with pro rata vesting permitted during the minimum three-year vesting period. The maximum number of shares reserved for issuance under the 2015 Plan is 1,000,000. The 2015 Plan replaced The Laclede Group 2006 Equity Incentive Plan (the 2006 Plan), which in turn replaced The Laclede Group, Inc. 2002 Equity Incentive Plan (the 2002 Plan). Shares reserved under the 2006 Plan and the 2002 Plan, other than those needed for currently outstanding awards, were canceled upon shareholder approval of the 2015 Plan.

The Company issues new shares to satisfy employee restricted stock awards and stock option exercises.

Restricted Stock Awards

During fiscal year 2016, the Company granted 199,140 performance-contingent restricted share units to executive officers and key employees at a weighted average grant date fair value of $45.95 per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. The share units have a performance period ending September 30, 2018. While the participants have no interim voting rights on these share units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying share units do not vest.

The number of share units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP and is discussed further below.

The weighted average grant date fair value of performance-contingent restricted shares and share units granted during fiscal years 2015 and 2014 was $36.69 and $37.21 per share, respectively.

Fiscal year 2016 activity of restricted stock and restricted stock units subject to performance and/or market conditions is presented below:

	Shares/ Units		Weighted Average Grant Date Fair Value Per Share
Nonvested at September 30, 2015	397,270		$	36.28
Granted (maximum shares that can be earned)	199,140		$	45.95
Vested	(62,593	)	$	35.29
Forfeited	(23,234	)	$	30.96
Nonvested at September 30, 2016	510,583		$	40.37

During fiscal year 2016, the Company granted 35,210 shares of time-vested restricted stock to executive officers and key employees at a weighted average grant date fair value of $59.40 per share. These shares were awarded between December 2015 and September 2016 and vest between December 2018 and September 2019 based on terms of the agreements. In the interim, participants receive full voting rights and dividends, which are not subject to forfeiture. The weighted average grant date fair value of time-vested restricted stock and restricted stock units awarded to employees during fiscal year 2015 and 2014 was $50.90 and $45.66 per share, respectively.

During fiscal year 2016, the Company granted 13,520 shares of time-vested restricted stock to non-employee directors at a weighted average grant date fair value of $63.93 per share. The weighted average grant date fair value of restricted stock awarded to non-employee directors during fiscal years 2015 and 2014 was $54.66 and $46.02 per share, respectively.

Time-vested restricted stock and stock unit activity for fiscal year 2016 is presented below:

	Shares/ Units		Weighted Average Grant Date Fair Value Per Share
Nonvested at September 30, 2015	129,304		$	44.89
Granted	48,730		$	60.65
Vested	(44,645	)	$	47.30
Forfeited	(610	)	$	53.12
Nonvested at September 30, 2016	132,779		$	49.83

During fiscal year 2016, 107,238 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on October 1, 2012, December 3, 2012, February 1, 2013, June 3, 2013, and August 1, 2013 vested. The Company withheld 30,712 of the vested shares at a weighted average price of $57.29 per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year 2015, 128,135 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on December 1, 2011, May 1, 2012, December 2, 2013 and January 1, 2014 vested. The Company withheld 31,688 of the vested shares at a weighted average price of $50.65 per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year 2014, 88,533 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on December 1, 2010, September 1, 2011, October 1, 2012, January 30, 2014 and February 21, 2014 vested. The Company withheld 23,776 of these vested shares at a weighted average price of $45.96 per share pursuant to elections by employees to satisfy tax withholding obligations.

The total fair value of restricted stock (performance-contingent and time-vested) vested during fiscal years 2016, 2015, and 2014 was $6.3, $6.4, and $4.1, respectively, and the related tax benefit was $2.4, $2.4 and $1.6, respectively. None of the tax benefits have been realized.

Stock Option Awards

No stock options were granted during fiscal years 2016, 2015, and 2014. Stock option activity for fiscal year 2016 is presented below:

	Stock Options		Weighted Average Exercise Price Per Share
Outstanding at September 30, 2015	28,500		$	33.65
Exercised	(27,750	)	$	33.66
Forfeited	(750	)	$	33.45
Outstanding at September 30, 2016	—		$	—

During fiscal year 2016, cash received from the exercise of stock options was $0.7 and the related intrinsic value was $0.7. During fiscal year 2015, cash received from the exercise of stock options was $1.5 and the related intrinsic value was $0.9. During fiscal year 2014, cash received from the exercise of stock options was $1.7 and the related intrinsic value was $0.9. Related tax benefits were not material in any of those years.

The closing price of the Company’s common stock was $63.74 per share at September 30, 2016.

Equity Compensation Costs

Compensation cost for performance-contingent restricted stock and stock unit awards is based upon the probable outcome of the performance conditions. For shares or units that do not vest or that are not expected to vest due to the outcome of the performance conditions (excluding market conditions), no compensation cost is recognized and any previously recognized compensation cost is reversed.

The fair value of awards of performance-contingent and time-vested restricted stock and restricted stock units, not subject to the TSR provision, are estimated using the closing price of the Company’s stock on the date of the grant. For those awards that do not pay dividends during the vesting period, the estimate of fair value is reduced by the present value of the dividends expected to be paid on the Company’s common stock during the performance period, discounted using an appropriate US Treasury yield. For shares subject to the TSR provision, the estimated impact of this market condition is reflected in the grant date fair value per share of the awards. Accordingly, compensation cost is not reversed to reflect any actual reductions in the awards that may result from the TSR provision. However, if the Company’s TSR during the performance period ranks below the level specified in the award agreements, relative to a comparator group of companies, and the Committee elects not to reduce the award (or reduce by a lesser amount), this election would be accounted for as a modification of the original award and additional compensation cost would be recognized at that time. The grant date fair value of the awards subject to the TSR provision awarded during fiscal years 2016, 2015, and 2014 was valued by a Monte Carlo simulation model that assessed the probabilities of various TSR outcomes. The significant assumptions used in the Monte Carlo simulations are as follows:

	2016	2015	2014
Risk free interest rate	1.14%	0.83%	0.53%
Expected dividend yield of stock	—	—	—
Expected volatility of stock	15.0%	14.0%	18.0%
Vesting period	2.8 years	2.8 years	2.8 years

The risk free interest rate was based on the yield on US Treasury securities matching the vesting period. A zero percent dividend yield was used, which is mathematically equivalent to the assumption that dividends are reinvested as they are paid. The expected volatility is based on the historical volatility of the Company’s stock. Volatility assumptions were also made for each of the companies included in the comparator group. The vesting period is equal to the performance period set forth in the terms of the award.

The amounts of compensation cost recognized for share-based compensation arrangements are presented below:

	2016			2015			2014
Total equity compensation cost	$	6.7		$	6.7		$	5.8
Compensation cost capitalized	(2.2		)	(1.8		)	(1.8		)
Compensation cost recognized in net income	$	4.5		$	4.9		$	4.0
Income tax benefit recognized in net income	(1.7		)	(1.9		)	(1.5		)
Compensation cost recognized in net income, net of income tax	$	2.8		$	3.0		$	2.5

As of September 30, 2016, there was $9.2 of total unrecognized compensation cost related to non-vested share-based compensation arrangements. That cost is expected to be recognized over a weighted average period of 1.8 years.

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EARNINGS PER COMMON SHARE

12 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE

	2016		2015		2014
Basic EPS:
Net Income	$	144.2	$	136.9	$	84.6
Less: Income allocated to participating securities	0.5		0.5		0.3
Net Income Available to Common Shareholders	$	143.7	$	136.4	$	84.3
Weighted Average Shares Outstanding (millions)	44.1		43.2		35.8
Earnings Per Share of Common Stock	$	3.26	$	3.16	$	2.36
Diluted EPS:
Net Income	$	144.2	$	136.9	$	84.6
Less: Income allocated to participating securities	0.5		0.5		0.3
Net Income Available to Common Shareholders	$	143.7	$	136.4	$	84.3
Weighted Average Shares Outstanding (millions)	44.1		43.2		35.8
Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units (millions)	0.2		0.1		0.1
Weighted Average Diluted Shares (millions)	44.3		43.3		35.9
Earnings Per Share of Common Stock	$	3.24	$	3.16	$	2.35
Outstanding Shares (in millions) Excluded from the Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to performance and/or market conditions	0.3		0.3		0.3

Spire’s 2014 2.0% Series Equity Units issued in June 2014 are potentially dilutive securities, but were excluded from the calculation of diluted EPS for the years ended September 30, 2016, 2015 and 2014. The potential shares were not included in the outstanding shares excluded from the calculation of Diluted EPS in the table above. See Note 5 for more information.

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STOCKHOLDERS' EQUITY

12 Months Ended

Sep. 30, 2016

Stockholders' Equity Note [Abstract]

STOCKHOLDERS' EQUITY

STOCKHOLDERS’ EQUITY

Equity Units

In June 2014, Spire issued 2.875 million equity units, initially consisting of Corporate Units, for an aggregate stated amount of approximately $143.8. Each Corporate Unit has a stated amount of fifty dollars and consists of (i) a stock purchase contract obligating the holder to purchase shares of Spire’s common stock, par value $1.00 per share, and (ii) a 1/20, or 5%, undivided beneficial ownership interest in one thousand dollars principal amount of Spire’s 2014 Series A 2.00% Remarketable Junior Subordinated Notes due 2022 (RSNs). The stock purchase contracts obligate the holders to purchase shares of common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price to be paid under the stock purchase contracts is fifty dollars per Corporate Unit and the number of shares to be purchased will be determined as follows:

If the applicable market value per share of Spire common stock is:	Number of shares to be purchased per purchase contract is:
Equal to or greater than $57.8125	0.8649
Less than $57.8125, but greater than $46.25	$50 ÷ applicable market value
Less than or equal to $46.25	1.0811

The RSNs are pledged as collateral to secure the purchase of Spire’s common stock under the related stock purchase contracts.

The Company makes quarterly interest payments on the RSNs and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. The Company may defer payments on the stock purchase contracts and the RSNs for one or more consecutive periods but generally not beyond the purchase contract settlement date. If payments are deferred, interest on the RSNs and contract adjustment payments will compound on each respective payment date in which the payment was deferred. Also, during the deferral period, the Company may not make any cash distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Additionally, the Company may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the RSNs during the deferral period. The Company has recorded the present value of the stock purchase contract payments as a liability offset by a charge to additional paid-in capital in equity. Interest payments on the RSNs are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS, the Company applies the treasury stock method to the Corporate Units. These securities did not have an effect on diluted EPS for the years ended September 30, 2016 and 2015.

Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Spire will issue between approximately 2.5 million and 3.1 million shares of its common stock in April 2017. A total of approximately 4.2 million shares of common stock have been reserved for issuance in connection with the stock purchase contracts. The stock purchase contracts obligate the holders to purchase shares of common stock at a future settlement date (April 1, 2017, or if such day is not a business day, the following business day) prior to the relevant RSN maturity date.

Selected information about the Company’s equity units is presented below:

Issuance Date	Units Issued (Millions)	Total Net Proceeds	Total Long-term Debt	RSN Annual Interest Rate	Stock Purchase Contract Annual Rate	Stock Purchase Contract Liability
6/11/2014	2.875	$139.4	$143.8	2.00%	4.75%	$19.7

Other Stock Information

Spire

On June 20, 2014, Spire filed a registration statement on Form S-3 for the issuance and sale of up to 168,698 shares of its common stock under its Dividend Reinvestment and Stock Purchase Program. There were 106,535 and 101,439 shares at September 30, 2016 and November 11, 2016, respectively, remaining available for issuance under this Form S-3.

On May 17, 2016, Spire completed a public offering of 2,185,000 shares of its common stock, generating $133.2 of proceeds net of issuance costs. On September 23, 2016, Spire and Laclede Gas filed with the SEC a joint shelf registration statement on Form S-3 for issuance of various types of debt and equity securities, which registration statement will expire September 22, 2019. The amount, timing, and type of additional financing to be issued under this shelf registration statement will depend on cash requirements and market conditions.

At September 30, 2016 and 2015, Spire had authorized 5,000,000 shares of preferred stock, but none were issued and outstanding.

Laclede Gas

Laclede Gas periodically sells shares of its stock to Spire at prices per share equal to book value on the last day of the quarter preceding each sale. There was no sale of shares to Spire during fiscal years 2016 or 2015. Laclede Gas sold 28 shares to Spire for $1.1 during fiscal year 2014. Exemption from registration for all of the sales was claimed under section 4(a)(2) of the Securities Act of 1933, as amended.

Substantially all of Laclede Gas plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on Laclede Gas’ ability to pay cash dividends on its common stock or to make loans to its parent company. These mortgage restrictions are applicable regardless of whether the stock is publicly held or held solely by Laclede Gas’ parent company. Under the most restrictive of these provisions, no cash dividend may be declared or paid if, after the dividend, the aggregate net amount spent for all dividends after September 30, 1953 would exceed a maximum amount determined by a formula set out in the mortgage. Under that formula, the maximum amount is the sum of $8.0 plus earnings applicable to common stock (adjusted for stock repurchases and issuances) for the period from September 30, 1953 to the last day of the quarter before the declaration or payment date for the dividends. As of September 30, 2016 and 2015, the amount under the mortgage’s formula that was available to pay dividends was $916.8 and $891.7, respectively. Thus, all of Laclede Gas’ retained earnings were free from such dividend restrictions as of those dates.

On September 23, 2016, Spire and Laclede Gas filed with the SEC a joint shelf registration statement on Form S-3 for issuance of various types of debt and equity securities, which registration statement will expire September 22, 2019. The amount, timing, and type of additional financing to be issued under this shelf registration statement will depend on cash requirements and market conditions, as well as future MoPSC authorizations.

Laclede Gas has authority from the MoPSC to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in capital, and enter into capital lease agreements, all for a total of up to $300.0. Laclede Gas has issued no securities under this authorization.

At September 30, 2016 and 2015, Laclede Gas had authorized 1,480,000 shares of preferred stock, but none were issued and outstanding.

Alagasco

At September 30, 2016 and 2015, Alagasco has authorized 120,000 shares of preferred stock, but none were issued and outstanding.

Other Comprehensive Income

The components of accumulated other comprehensive income (loss), net of income taxes, recognized in the balance sheets at September 30 were as follows:

	Net Unrealized Gains (Losses) on Cash Flow Hedges			Defined Benefit Pension and Other Postretirement Benefit Plans			Net Unrealized Losses on Available for Sale Securities			Total
Spire
Balance at September 30, 2014	$	0.2		$	(1.9	)	$	—		$	(1.7	)
Other comprehensive (loss) income	(0.6		)	0.4			(0.1		)	(0.3		)
Balance at September 30, 2015	(0.4		)	(1.5		)	(0.1		)	(2.0		)
Other comprehensive (loss) income	(1.9		)	(0.3		)	—			(2.2		)
Balance at September 30, 2016	$	(2.3	)	$	(1.8	)	$	(0.1	)	$	(4.2	)
Laclede Gas
Balance at September 30, 2014	$	—		$	(1.9	)	$	—		$	(1.9	)
Other comprehensive (loss) income	(0.2		)	0.4			—			0.2
Balance at September 30, 2015	(0.2		)	(1.5		)	—			(1.7		)
Other comprehensive income (loss)	0.3			(0.3		)	(0.1		)	(0.1		)
Balance at September 30, 2016	$	0.1		$	(1.8	)	$	(0.1	)	$	(1.8	)

Income tax expense (benefit) recorded for items of other comprehensive income (loss) reported in the statements of comprehensive income is calculated by applying statutory federal, state, and local income tax rates applicable to ordinary income. The tax rates applied to individual items of other comprehensive income are similar within each reporting period. For the periods presented, Alagasco had no accumulated other comprehensive income (loss) balances.

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LONG-TERM DEBT

12 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

LONG-TERM DEBT

LONG-TERM DEBT

Composition of long-term debt for Spire, Laclede Gas and Alagasco are shown in each registrant’s statements of capitalization as part of the financial statements. Maturities of long-term debt for Spire, Laclede Gas and Alagasco for the five fiscal years subsequent to September 30, 2016 are as follows:

	Spire		Laclede Gas		Alagasco
2017	$	250.0	$	—	$	—
2018	100.0		100.0		—
2019	180.0		50.0		—
2020	40.0		—		40.0
2021	55.0		—		—

Spire’s, Laclede Gas’ and Alagasco’s short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of September 30, 2016, there were no events of default under these covenants.

The Company’s, Laclede Gas’, and Alagasco’s access to capital markets, including the commercial paper market, and their respective financing costs, may depend on the credit rating of the entity that is accessing the capital markets. The credit ratings of the Company, Laclede Gas and Alagasco remain at investment grade, but are subject to review and change by the rating agencies.

It is management’s view that the Company, Laclede Gas and Alagasco have adequate access to capital markets and will have sufficient capital resources, both internal and external, to meet anticipated capital requirements, which primarily include capital expenditures, interest payments on long-term debt, scheduled maturities of long-term debt, short-term seasonal needs, and dividends.

Spire

Spire entered into a master note purchase agreement on June 20, 2016, with certain institutional purchasers pursuant to which Spire issued a total of $165.0 unsecured notes in the private placement market. These notes were issued on September 9, 2016 to fund a portion of the purchase price for the EnergySouth acquisition and consisted of $35 million in aggregate principal amount of its unsecured Series 2016 Senior Notes, Tranche A, due September 1, 2021 (Tranche A Notes) and $130 million in aggregate principal amount of its unsecured Series 2016 Senior Notes, Tranche B, due September 1, 2026 (Tranche B Notes). Tranche A Notes and Tranche B Notes bear interest at a rate per annum of 2.52% and 3.13%, respectively.

At September 30, 2016, including the current portion but excluding unamortized discounts and net hedging gains, Spire had long-term debt totaling $2,085.8, of which $810.0 was issued by Laclede Gas, $250.0 was issued by Alagasco, and $67.0 was issued by other subsidiaries. With the exception of $250.0 floating rate senior notes issued by Spire, all long-term debt bears fixed rates and is subject to changes in fair value as market interest rates change. However, increases and decreases in fair value would impact earnings and cash flows only if the Company were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to the Utilities’ regulated operations, losses or gains on early redemption of long-term debt typically would be deferred as regulatory assets or liabilities and amortized over a future period.

Of the Company’s $1,942.0 senior long-term debt (including the current portion) , $25.0 have no call options, $937.0 have make-whole call options, $250.0 is callable currently, and $730.0 are callable at par between one to six months prior to maturity. The remainder of the Company’s long-term debt is $143.8 of 2% Remarketable Junior Subordinated Notes due in 2022. None of the debt has put options.

Spire has a shelf registration statement on Form S-3 on file with the SEC for the issuance and sale of up to 168,698 shares of common stock under its Dividend Reinvestment and Direct Stock Purchase Plan. There were 106,535 and 101,439 at September 30, 2016 and November 11, 2016, respectively, remaining available for issuance under this Form S-3. Spire also has a shelf registration statement on Form S-3 on file with the SEC for the issuance of equity and debt securities.

The Company’s capitalization at September 30, 2016 consisted of 49.1% of Spire common stock equity and 50.9% long-term debt, compared to 47.0% of Spire common stock equity and 53.0% of long-term debt at September 30, 2015. The decline in the proportion of long-term debt is due primarily to the reclassification of $250.0 of Spire’s long-term debt to “current.”

Laclede Gas

At September 30, 2016, Laclede Gas had fixed-rate long-term debt, including the current portion, totaling $810.0. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. Of Laclede Gas’ $810.0 in long-term debt, $25.0 have no call options, $435.0 have make-whole call options and $350.0 are callable at par three to six months prior to maturity. None of the debt has any put options.

Laclede Gas has authority from the MoPSC to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in-capital, and enter into capital lease agreements, all for a total of up to $300.0 for financings placed any time before September 30, 2018. On March 31, 2016, Laclede Gas filed an appeal with Missouri’s Western District Court of Appeals challenging the level of authority. On July 20, 2016, Laclede Gas filed its initial brief in the appeal. Oral arguments are scheduled for November 17, 2016. During the year ended September 30, 2016, Laclede Gas issued no securities under this authorization, so that as of November 11, 2016, $300.0 remains available to be issued. On September 23, 2016, Laclede Gas filed a shelf registration on Form S-3 with the SEC for issuance of first mortgage bonds, unsecured debt, and preferred stock, which expires on September 22, 2019. The amount, timing, and type of additional financing to be issued under this shelf registration will depend on cash requirements and market conditions, as well as future MoPSC authorizations. This authorization is more fully described in Note 5, Stockholders’ Equity.

Laclede Gas’ capitalization at September 30, 2016 consisted of 56.9% of Laclede Gas common stock equity and 43.1% long-term debt compared to 56.2% of Laclede Gas common stock equity and 43.8% of long-term debt at September 30, 2015.

Substantially all of Laclede Gas’ plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on Laclede Gas’ ability to pay cash dividends on its common stock, which are described more fully in Note 5, Stockholders’ Equity.

Alagasco

Because Alagasco has no standing authority to issue long-term debt, it must petition the APSC for each planned issuance. On November 3, 2014, Alagasco received authorization and approval from the APSC to borrow $35.0 for the purpose of redeeming, without penalty, $34.8 in existing long-term, callable debt financed at 5.7%. Pursuant to a call notice issued on December 15, 2014, Alagasco redeemed $34.8 of debt effective January 15, 2015. On February 3, 2015, Alagasco received authorization and approval from the APSC to borrow $80.0 for the purpose of refinancing the scheduled maturity on December 1, 2015 of $80.0 of existing debt. Pursuant to these authorizations, Alagasco committed to issue $115.0 unsecured notes in the private placement market: $35.0 at a rate of 3.21% for 10 years issued on September 15, 2015, and $80.0 at a rate of 4.31% for 30 years issued on December 1, 2015. The Notes are senior unsecured obligations of Alagasco and rank equal in right to payment with all other senior unsecured indebtedness. Alagasco used the proceeds from the sale of the Notes to refinance existing indebtedness and for general corporate purposes.

At September 30, 2016, Alagasco had fixed-rate long-term debt totaling $250.0. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. All of Alagasco’s $250.0 long-term debt has make-whole call options.

Alagasco’s capitalization at September 30, 2016 consisted of 77.6% of Alagasco common stock equity and 22.4% long-term debt compared to 83.7% of Alagasco common stock equity and 16.3% of long-term debt at September 30, 2015.

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NOTES PAYABLE AND CREDIT AGREEMENTS

12 Months Ended

Sep. 30, 2016

Short-term Debt [Abstract]

NOTES PAYABLE AND CREDIT AGREEMENTS

NOTES PAYABLE AND CREDIT AGREEMENTS

Short-term cash requirements outside of the Utilities have generally been funded by Spire or met with internally generated funds. AtSeptember 30, 2016, Spire had a $150.0 syndicated line of credit from nine banks maturing on September 3, 2019, with the largest portion provided by a single bank being 15.6%. The line of credit has a covenant limiting the total debt of the consolidated Spire to no more than 70% of the Company’s total capitalization. As defined in the line of credit, this ratio was 58.5% on September 30, 2016. Spire’s line may be used to provide for the funding needs of various subsidiaries. The maturity date of the loan agreement is September 3, 2019.

The Utilities’ short-term borrowing requirements typically peak during the colder months while the Company’s needs are less seasonal. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. At September 30, 2016, Laclede Gas had a syndicated line of credit of $450.0 in place from ten banks. The largest portion provided by a single bank is 15.6%. Laclede Gas’ line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. As defined in the line of credit, on September 30, 2016 total debt was 49.7% of total capitalization. Laclede Gas’ commercial paper program is backed by the line of credit. The maturity date of the line of credit is September 3, 2019.

On September 2, 2014, Alagasco entered into a new $150.0 syndicated line of credit with twelve banks and extinguished the line that was in place prior to its acquisition by Spire. The largest portion provided by a single bank is 10%. The line of credit, which matures on September 2, 2019, has a covenant limiting total debt to no more than 70% of Alagasco’s total capitalization. As defined in the line of credit, this ratio stood at 27.8% on September 30, 2016.

Spire

Information about Spire’s short-term borrowings (excluding intercompany borrowings) during the twelve months ended September 30, and as of September 30, is presented below for 2016 and 2015:

	Laclede Gas Commercial Paper Borrowings	Spire Bank Line Borrowings*	Alagasco Bank Line Borrowings	Total Short-Term Borrowings
Year Ended September 30, 2016
Weighted average borrowings outstanding	$201.0	$42.7	$30.2	$273.9
Weighted average interest rate	0.7%	1.6%	1.4%	0.9%
Range of borrowings outstanding	$43.0 - $307.2	$0.0 - $82.0	$0.0 - $82.0	$73.1 - $427.2
As of September 30, 2016
Borrowings outstanding at end of period	$243.7	$73.0	$82.0	$398.7
Weighted average interest rate	0.8%	1.8%	1.5%	1.1%
Year Ended September 30, 2015
Weighted average borrowings outstanding	$212.7	$65.6	$22.3	$300.6
Weighted average interest rate	0.4%	1.4%	1.1%	0.7%
Range of borrowings outstanding	$ 102.1 - $341.0	$32.5 - $80.0	$0.0 - $69.5	$180.1 - $488.5
As of September 30, 2015
Borrowings outstanding at end of period	$233.0	$74.0	$31.0	$338.0
Weighted average interest rate	0.5%	1.5%	1.2%	0.8%

* Spire Inc., excluding its wholly owned subsidiaries.

Based on average short-term borrowings for the twelve months ended September 30, 2016, an increase in the average interest rate of 100 basis points would decrease Spire’s pre-tax earnings and cash flows by approximately $2.7 on an annual basis, portions of which may be offset through the application of PGA or GSA carrying costs.

Laclede Gas

Information about Laclede Gas’ short-term borrowings during the twelve months ended September 30, and as of September 30, is presented below for 2016 and 2015:

	Commercial Paper Borrowings	Borrowings from Spire	Total Short-Term Borrowings
Year Ended September 30, 2016
Weighted average borrowings outstanding	$201.0	$14.7	$215.7
Weighted average interest rate	0.7%	0.8%	0.7%
Range of borrowings outstanding	$43.0 - $307.2	$0.0 - $114.2	$127.8 - $ 307.2
As of September 30, 2016
Borrowings outstanding at end of period	$243.7	$—	$243.7
Weighted average interest rate	0.8%	—%	0.8%
Year Ended September 30, 2015
Weighted average borrowings outstanding	$212.7	$0.3	$213.0
Weighted average interest rate	0.4%	0.5%	0.4%
Range of borrowings outstanding	$102.1 - $341.0	$0.0 - $10.4	$104.2 - $ 341.0
As of September 30, 2015
Borrowings outstanding at end of period	$233.0	$—	$233.0
Weighted average interest rate	0.5%	—%	0.5%

Based on average short-term borrowings for the twelve months ended September 30, 2016, an increase in the average interest rate of 100 basis points would decrease Laclede Gas’ pre-tax earnings and cash flows by approximately $2.2 on an annual basis, portions of which may be offset through the application of PGA carrying costs.

Alagasco

Information about Alagasco’s short-term borrowings during the twelve months ended September 30, and as of September 30, is presented below for 2016 and 2015:

	Bank Line Borrowings	Borrowings from Spire	Total Short-Term Borrowings
Year Ended September 30, 2016
Weighted average borrowings outstanding	$30.2	$12.4	$42.6
Weighted average interest rate	1.4%	1.4%	1.4%
Range of borrowings outstanding	$0.0 - $82	$0.0 - $61.9	$19.0 - $82.0
As of September 30, 2016
Borrowings outstanding at end of period	$82.0	$—	$82.0
Weighted average interest rate	1.5%	—%	1.5%
Year Ended September 30, 2015
Weighted average borrowings outstanding	$22.3	$—	$22.3
Weighted average interest rate	1.1%	—%	1.1%
Range of borrowings outstanding	$0.0 - $69.5	0	$0.0- $69.5
As of September 30, 2015
Borrowings outstanding at end of period	$31.0	$—	$31.0
Weighted average interest rate	1.2%	—%	1.2%

Based on average short-term borrowings for the twelve months ended September 30, 2016, an increase in the average interest rate of 100 basis points would decrease Alagasco’s pre-tax earnings and cash flows by approximately $0.4 on an annual basis, portions of which may be offset through the application of GSA carrying costs.

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FAIR VALUE OF FINANCIAL INSTRUMENTS

12 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

FAIR VALUE OF FINANCIAL INSTRUMENTS

Spire

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis for the Company are as follows:

					Classification of Estimated Fair Value
	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of September 30, 2016
Cash and cash equivalents	$	5.2	$	5.2	$	5.2	$	—	$	—
Short-term debt	398.7		398.7		—		398.7		—
Long-term debt, including current portion	2,083.7		2,257.1		—		2,257.1		—
As of September 30, 2015
Cash and cash equivalents	$	13.8	$	13.8	$	13.8	$	—	$	—
Short-term debt	338.0		338.0		—		338.0		—
Long-term debt, including current portion	1,851.5		1,944.2		—		1,944.2		—

Laclede Gas

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis for Laclede Gas are as follows:

					Classification of Estimated Fair Value
	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of September 30, 2016
Cash and cash equivalents	$	2.1	$	2.1	$	2.1	$	—	$	—
Short-term debt	243.7		243.7		—		243.7		—
Long-term debt	808.3		900.4		—		900.4		—
As of September 30, 2015
Cash and cash equivalents	$	1.7	$	1.7	$	1.7	$	—	$	—
Short-term debt	233.0		233.0		—		233.0		—
Long-term debt	808.1		880.2		—		880.2		—

Alagasco

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis for Alagasco are as follows:

					Classification of Estimated Fair Value
	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of September 30, 2016
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—
Short-term debt	82.0		82.0		—		82.0		—
Long-term debt	250.0		275.5		—		275.5		—
As of September 30, 2015
Cash and cash equivalents	$	7.2	$	7.2	$	7.2	$	—	$	—
Short-term debt	31.0		31.0		—		31.0		—
Long-term debt, including current portion	250.0		263.2		—		263.2		—

The carrying amounts for cash and cash equivalents and short-term debt approximate fair value due to the short maturity of these instruments. The fair values of long-term debt are estimated based on market prices for similar issues. Refer to Note 9, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis.

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FAIR VALUE MEASUREMENTS

12 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

Spire

The information presented below categorizes the assets and liabilities in the balance sheets that are accounted for at fair value on a recurring basis in periods subsequent to initial recognition.

The mutual funds included in Level 1 are valued based on exchange-quoted market prices of individual securities. The mutual funds included in Level 2 are valued based on the closing net asset value per unit.

Derivative instruments included in Level 1 are valued using quoted market prices on the NYMEX. Derivative instruments classified as Level 2 include physical commodity derivatives that are valued using Over-the-Counter Bulletin Board (OTCBB), broker, or dealer quotation services whose prices are derived principally from, or are corroborated by, observable market inputs. Also included in Level 2 are certain derivative instruments that have values that are similar to, and correlate with, quoted prices for exchange-traded instruments in active markets. Derivative instruments included in Level 3 are valued using generally unobservable inputs that are based upon the best information available and reflect management’s assumptions about how market participants would price the asset or liability. There were no material Level 3 balances as of September 30, 2016 or 2015. The Company’s and the Utilities’ policy is to recognize transfers between the levels of the fair value hierarchy, if any, as of the beginning of the interim reporting period in which circumstances change or events occur to cause the transfer.

The mutual funds are included in the “Other investments” line of the balance sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the balance sheets when a legally enforceable netting agreement exist between the Company or Laclede Gas and the counterparty to the derivative contract. For additional information on derivative instruments, see Note 10, Derivative Instruments and Hedging Activities.

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of September 30, 2016
ASSETS
Gas Utility
US stock/bond mutual funds	$	16.8	$	4.1	$	—	$	—		$	20.9
NYMEX/ICE natural gas contracts	5.3		—		—		(0.4		)	4.9
Gasoline and heating oil contracts	0.4		—		—		(0.3		)	0.1
Subtotal	22.5		4.1		—		(0.7		)	25.9
Gas Marketing
NYMEX/ICE natural gas contracts	0.4		3.4		—		(3.4		)	0.4
Natural gas commodity contracts	—		8.7		0.2		(0.9		)	8.0
Total	$	22.9	$	16.2	$	0.2	$	(5.0	)	$	34.3
LIABILITIES
Gas Utility
NYMEX/ICE natural gas contracts	$	1.6	$	—	$	—	$	(1.6	)	$	—
OTCBB natural gas contracts	—		0.2		—		—			0.2
Subtotal	1.6		0.2		—		(1.6		)	0.2
Gas Marketing
NYMEX/ICE natural gas contracts	3.5		1.6		—		(5.1		)	—
Natural gas commodity contracts	—		2.6		—		(0.9		)	1.7
Other
Interest rate swaps	—		3.0		—		—			3.0
Total	$	5.1	$	7.4	$	—	$	(7.6	)	$	4.9
As of September 30, 2015
ASSETS
Gas Utility
US stock/bond mutual funds	$	15.5	$	4.0	$	—	$	—		$	19.5
NYMEX/ICE natural gas contracts	1.3		—		—		(1.3		)	—
Subtotal	16.8		4.0		—		(1.3		)	19.5
Gas Marketing
NYMEX natural gas contracts	6.3		4.3		—		(6.6		)	4.0
Natural gas commodity contracts	—		1.5		0.2		(0.5		)	1.2
Total	$	23.1	$	9.8	$	0.2	$	(8.4	)	$	24.7
LIABILITIES
Gas Utility
NYMEX/ICE natural gas contracts	$	16.4	$	—	$	—	$	(16.4	)	$	—
OTCBB natural gas contracts	—		5.9		—		—			5.9
NYMEX gasoline and heating oil contracts	0.3		—		—		(0.3		)	—
Subtotal	16.7		5.9		—		(16.7		)	5.9
Gas Marketing
NYMEX/ICE natural gas contracts	1.2		3.9		—		(5.1		)	—
Natural gas commodity contracts	—		2.2		—		(0.5		)	1.7
Total	$	17.9	$	12.0	$	—	$	(22.3	)	$	7.6

Laclede Gas

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of September 30, 2016
ASSETS
US stock/bond mutual funds	$	16.8	$	4.1	$	—	$	—		$	20.9
NYMEX/ICE natural gas contracts	5.3		—		—		(0.4		)	4.9
Gasoline and heating oil contracts	0.3		—		—		(0.3		)	—
Total	$	22.4	$	4.1	$	—	$	(0.7	)	$	25.8
LIABILITIES
NYMEX/ICE natural gas contracts	$	1.6	$	—	$	—	$	(1.6	)	$	—
OTCBB natural gas contracts	—		0.2		—		—			0.2
Total	$	1.6	$	0.2	$	—	$	(1.6	)	$	0.2
As of September 30, 2015
ASSETS
US stock/bond mutual funds	$	15.5	$	4.0	$	—	$	—		$	19.5
NYMEX/ICE natural gas contracts	1.3		—		—		(1.3		)	—
Total	$	16.8	$	4.0	$	—	$	(1.3	)	$	19.5
LIABILITIES
NYMEX/ICE natural gas contracts	$	16.4	$	—	$	—	$	(16.4	)	$	—
OTCBB natural gas contracts	—		5.9		—		—			5.9
NYMEX gasoline and heating oil contracts	0.3		—		—		(0.3		)	—
Total	$	16.7	$	5.9	$	—	$	(16.7	)	$	5.9

Alagasco

During the fiscal second quarter of 2016 Alagasco commenced a gasoline derivative program to stabilize the cost of fuel used in operations. As of September 30, 2016, the fair value of related gasoline contracts was not significant.

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

12 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Spire

Laclede Gas has a risk management policy to utilize various derivatives, including futures contracts, exchange-traded options, swaps and over-the-counter instruments for the explicit purpose of managing price risk associated with purchasing and delivering natural gas on a regular basis to customers in accordance with its tariffs. The objective of this policy is to limit Laclede Gas’ exposure to natural gas price volatility and to manage, hedge and mitigate substantial price risk. Further discussion of this policy can be found in the Laclede Gas section.

From time to time Laclede Gas and Alagasco purchase NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of their business. Further information on these derivatives can be found in the Laclede Gas and Alagasco sections, respectively.

In the course of its business, Spire’s gas marketing subsidiary, LER, which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At September 30, 2016, the fair values of 122.7 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 110.8 million MMBtu will settle during fiscal year 2017, and 11.4 million MMBtu, 0.2 million MMBtu, and 0.3 million MMBtu will settle during 2018, 2019, and 2020, respectively. These contracts have not been designated as hedges; therefore, changes in the fair value of these contracts are reported in earnings each period.

Furthermore, LER manages the price risk associated with its fixed-priced commitments by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of NYMEX or ICE futures, swap, and option contracts to lock in margins.

At September 30, 2016, LER’s unmatched fixed-price positions were not material to Spire’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.

On April 14, 2014, as amended on July 8, 2014, Spire entered into certain interest rate swap agreements, with a notional amount $375.0, to effectively lock in interest rates on a portion of the long-term debt it anticipated issuing to finance its acquisition of Alagasco. These derivative instruments were designated as cash flow hedges of forecasted transactions. These forward starting swaps involved the payment of a fixed interest rate and the receipt of a floating interest rate (the London Interbank Offered Rate, also known as LIBOR) over the terms specified in the contracts. On August 6, 2014, the interest rate swap agreements were terminated and the settlement resulted in a $19.0 loss by Spire, which assigned the loss as a regulatory asset since the interest rate swaps were entered into to hedge the interest payments on the $625.0 of long-term debt issued on August 19, 2014 by Spire.

During the second quarter of fiscal year 2015, Alagasco entered into certain interest rate swap transactions to protect itself against adverse movement in interest rates in anticipation of its issuance of $115.0 of long-term debt. Alagasco received prior approval from the APSC to enter into these hedges. The notional amount of interest rate swaps outstanding was $80.5 with stated maturities ranging from 2025 to 2045 and fixed interest rates ranging between 2.18% and 2.85%. In April 2015, Alagasco entered into an additional hedge with a notional amount of $24.0 and terms within the same range. These derivative instruments were designated as cash flow hedges of forecasted transactions. These forward starting swaps involved the payment of a fixed interest rate and the receipt of LIBOR over the terms specified in the contracts. On May 21, 2015, the interest rate swap agreements were terminated and the settlement resulted in a $2.7 gain which was recorded as a regulatory liability. Of the total issuance of long-term debt, $35.0 was issued on September 15, 2015 and the remaining $80.0 was issued on December 1, 2015.

During the second quarter of fiscal 2016, Spire entered into five-year interest rate swap transactions with a fixed interest rate of 1.776% and a notional amount of $105.0 to protect itself against adverse movement in interest rates in anticipation of the issuance of long-term debt in 2017. During the third quarter of 2016, the Company entered into seven-year swap transactions with an average fixed interest rate of 1.501% and a notional amount of $120.0 to hedge against additional debt expected to be issued in 2017 or early 2018. As a result, a $1.0 mark-to-market gain and $3.0 mark-to-market losses were recognized for the three and twelve months ended September 30, 2016, respectively.

On May 5, 2016, Spire entered into certain interest rate swap agreements, with a notional amount of $85.0, to effectively lock in interest rates on a portion of the long-term debt it anticipated issuing to finance its acquisition of EnergySouth. These derivative instruments were designated as cash flow hedges of forecasted transactions. On June 3, 2016, the interest rate swap agreements were terminated and the settlement resulted in a $0.4 payment recorded in accumulated other comprehensive loss to be amortized over the life of the related debt issuances.

The Company’s and Laclede Gas’ exchange-traded/cleared derivative instruments consist primarily of NYMEX, OTCBB, and ICE positions. The NYMEX and OTCBB is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX/ICE and OTCBB natural gas futures and swap positions at September 30, 2016 were as follows:

	Gas Utility			Gas Marketing
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
NYMEX/ICE Open short futures positions
Fiscal 2017	—	$	—	12.20	$	2.86
Fiscal 2018	—	—		1.27	2.95
NYMEX/ICE Open long futures/swap positions
Fiscal 2017	18.43	2.95		4.62	3.12
Fiscal 2018	0.33	2.83		0.45	3.02
Fiscal 2019	—	—		0.04	2.89
ICE Open long basis swap positions
Fiscal 2017	—	—		16.62	0.34
Fiscal 2018	—	—		2.01	0.43
Fiscal 2019	—	—		0.08	0.40
ICE Open short basis swap positions
Fiscal 2017	—	—		11.88	0.19
Fiscal 2018	—	—		0.93	0.27
Fiscal 2019	—	—		2.27	0.13
OTC Open long futures/swap positions
Fiscal 2017	0.32	3.64		—	—

At September 30, 2016, Laclede Gas also had 19.8 million MMBtu of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies while LER had none.

Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the balance sheets of the Company at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in other comprehensive income or loss (OCI). Accumulated other comprehensive income or loss (AOCI) is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at September 30, 2016, it is expected that an immaterial amount of unrealized gains will be reclassified into the Consolidated Statements of Income of the Company during the next twelve months. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the Consolidated Statements of Cash Flows.

Effect of Derivative Instruments on the Consolidated Statements of Income and Consolidated Statements of Comprehensive Income
	Location of Gain (Loss)
	Recorded in Income	2016			2015			2014
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
Gas Marketing natural gas contracts		$	(0.6	)	$	(4.3	)	$	(4.6	)
Gas Utility gasoline and heating oil contracts		—			(1.2		)	0.1
Interest Rate Swaps		(3.4		)	—			—
Total		$	(4.0	)	$	(5.5	)	$	(4.5	)
Effective portion of gain (loss) reclassified from AOCI to income:
Natural gas contracts	Gas Marketing Operating Revenues	$	4.3		$	1.7		$	4.2
	Gas Marketing Operating Expenses	(4.9		)	(5.2		)	(1.5		)
Subtotal		(0.6		)	(3.5		)	2.7
Gasoline and heating oil contracts	Gas Utility Other Operating Expenses	(0.5		)	(0.9		)	(0.2		)
Total		$	(1.1	)	$	(4.4	)	$	2.5
Ineffective portion of gain (loss) on derivatives recognized in income:
Natural gas contracts	Gas Marketing Operating Revenues	$	0.1		$	—		$	(0.1	)
	Gas Marketing Operating Expenses	0.1			(0.5		)	0.1
Subtotal		0.2			(0.5		)	—
Gasoline and heating oil contracts	Gas Utility Other Operating Expenses	0.1			0.1			(0.2		)
Total		$	0.3		$	(0.4	)	$	(0.2	)
Derivatives Not Designated as Hedging Instruments*
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	12.3		$	(1.3	)	$	(8.7	)
NYMEX / ICE natural gas contracts	Gas Marketing Operating Revenues	(1.7		)	(9.6		)	3.0
Gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	—			(0.2		)	—
Total		$	10.6		$	(11.1	)	$	(5.7	)

* Gains and losses on Laclede Gas’ natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Missouri Utilities’ PGA clauses and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the statements of income. Such amounts are recognized in the statements of income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA clause and reflected in customer billings.

Fair Value of Derivative Instruments in the Consolidated Balance Sheet
	Asset Derivatives*			Liability Derivatives*
September 30, 2016	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Gas Utility:
Gasoline and heating oil contracts	Derivative Instrument Assets	$	0.3	Derivative Instrument Assets	$	—
Gas Marketing:
Natural gas contracts	Derivative Instrument Assets	2.5		Derivative Instrument Assets	0.8
	Deferred Charges – Other	0.4		Deferred Charges – Other	0.1
Other: Interest swaps	Derivative Instrument Assets	—		Derivative Instrument Assets	3.0
Subtotal		3.2			3.9
Derivatives not designated as hedging instruments
Gas Utility:
Natural gas contracts	Accounts Receivable – Other	5.4		Accounts Receivable – Other	1.6
	Derivative Instrument Assets	—		Derivative Instrument Assets	0.2
Gas Marketing:
NYMEX / ICE natural gas contracts	Derivative Instrument Assets	0.8		Derivative Instrument Assets	4.1
	Deferred Charges – Other	—		Deferred Charges – Other	0.1
Natural gas commodity	Derivative Instrument Assets	6.5		Derivative Instrument Assets	0.2
	Other Deferred Charges	2.1		Other Deferred Charges	0.3
	Current Liabilities – Other	0.2		Current Liabilities – Other	2.0
	Deferred Credits – Other	0.2		Deferred Credits – Other	0.1
Subtotal		15.2			8.6
Total derivatives		$	18.4		$	12.5
September 30, 2015
Derivatives designated as hedging instruments
Gas Utility:
Gasoline and heating oil contracts	Accounts Receivable – Other	$	—	Accounts Receivable – Other	$	0.3
Gas Marketing:
Natural gas contracts	Derivative Instrument Assets	4.1		Derivative Instrument Assets	3.2
	Deferred Charges – Other	1.1		Deferred Charges – Other	0.5
Subtotal		5.2			4.0
Derivatives not designated as hedging instruments
Gas Utility:
Natural gas contracts	Accounts Receivable – Other	1.2		Accounts Receivable – Other	16.4
	Derivative Instrument Assets	—		Derivative Instrument Assets	5.7
	Deferred Charges – Other	—		Deferred Charges – Other	0.2
Gas Marketing:
NYMEX / ICE natural gas contracts	Derivative Instrument Assets	4.7		Derivative Instrument Assets	0.6
	Deferred Charges – Other	0.7		Deferred Charges – Other	0.7
Natural gas commodity	Derivative Instrument Assets	1.4		Derivative Instrument Assets	0.1
	Current Liabilities – Other	0.2		Current Liabilities – Other	1.4
	Deferred Credits – Other	0.1		Deferred Credits – Other	0.7
Subtotal		8.3			25.8
Total derivatives		$	13.5		$	29.8

* The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the balance sheets. As such, the gross balances presented in the table above are not indicative of the Company’s net economic exposure. Refer to Note 9, Fair Value Measurements, for information on the valuation of derivative instruments.

Following is a reconciliation of the amounts in the tables above to the amounts presented in the Consolidated Balance Sheets:

	2016			2015
Fair value of asset derivatives presented above	$	18.4		$	13.5
Fair value of cash margin receivables offset with derivatives	2.5			13.9
Netting of assets and liabilities with the same counterparty	(7.6		)	(22.2		)
Total	$	13.3		$	5.2
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	$	11.4		$	4.6
Deferred Charges – Other	1.9			0.6
Total	$	13.3		$	5.2
Fair value of liability derivatives presented above	$	12.5		$	29.8
Netting of assets and liabilities with the same counterparty	(7.6		)	(22.2		)
Total	$	4.9		$	7.6
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Current Liabilities – Other	$	4.8		$	6.8
Deferred Credits – Other	0.1			0.8
Total	$	4.9		$	7.6

Additionally, at September 30, 2016 and 2015, the Company had $2.9 and $5.9, respectively, in cash margin receivables not offset with derivatives, which are presented in Accounts Receivable – Other.

Laclede Gas

Laclede Gas has a risk management policy to utilize various derivatives, including futures contracts, exchange-traded options, swaps and over-the-counter instruments for the explicit purpose of managing price risk associated with purchasing and delivering natural gas on a regular basis to customers in accordance with its tariffs. The objective of this policy is to limit Laclede Gas’ exposure to natural gas price volatility and to manage, hedge and mitigate substantial price risk. This policy strictly prohibits speculation and permits Laclede Gas to hedge current physical natural gas purchase commitments or forecasted or anticipated future peak (maximum) physical need for natural gas delivered. Costs and cost reductions, including carrying costs, associated with Laclede Gas’ use of natural gas derivative instruments are allowed to be passed on to Laclede Gas customers through the operation of its PGA clause, through which the MoPSC allows Laclede Gas to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, Laclede Gas does not expect any adverse earnings impact as a result of the use of these derivative instruments.

Laclede Gas does not designate these instruments as hedging instruments for financial reporting purposes because gains or losses associated with the use of these derivative instruments are deferred and recorded as regulatory assets or regulatory liabilities pursuant to ASC Topic 980, “Regulated Operations,” and, as a result, have no direct impact on the statements of income.

The timing of the operation of the PGA clause may cause interim variations in short-term cash flows, because Laclede Gas is subject to cash margin requirements associated with changes in the values of these instruments. Nevertheless, carrying costs associated with such requirements are recovered through the PGA clause.

From time to time, Laclede Gas purchases NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At September 30, 2016, Laclede Gas held 1.8 million gallons of gasoline futures contracts at an average price of $1.37 per gallon. Most of these contracts, the longest of which extends to December 2016, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815, “Derivatives and Hedging.” The gains or losses on these derivative instruments are not subject to Laclede Gas’ PGA clause.

Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the balance sheets at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in OCI. AOCI is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at September 30, 2016, it is expected that an immaterial amount of pre-tax gains will be reclassified into the statements of income during fiscal year 2016. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the statements of cash flows.

Laclede Gas’ derivative instruments consist primarily of NYMEX and OTCBB positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX and OTCBB natural gas futures positions at September 30, 2016 were as follows:

	MMBtu (millions)	Avg. Price Per MMBtu
NYMEX/ICE Open long futures/swap positions
Fiscal 2017	18.43	$	2.95
Fiscal 2018	0.33	2.83
OTC Open long futures/swap positions
Fiscal 2017	0.32	$	3.64

At September 30, 2016, Laclede Gas also had 19.8 million MMBtu of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies.

Effect of Derivative Instruments on the Statements of Income and Statements of Comprehensive Income
	Location of Gain (Loss)
	Recorded in Income	2016			2015			2014
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
Gasoline and heating oil contracts		$	—		$	(1.2	)	$	0.1
Effective portion of gain (loss) reclassified from AOCI to income:
Gasoline and heating oil contracts	Gas Utility Other Operating Expenses	$	(0.5	)	$	(0.9	)	$	(0.2	)
Ineffective portion of gain (loss) on derivatives recognized in income:
Gasoline and heating oil contracts	Gas Utility Other Operating Expenses	$	0.1		$	0.1		$	(0.2	)
Derivatives Not Designated as Hedging Instruments*
Gain (loss) recognized in income on derivatives:
Gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	$	—		$	(0.2	)	$	—

* Gains and losses on Laclede Gas’ natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Laclede Gas’ PGA clauses and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the Statements of Income. Such amounts are recognized in the Statements of Income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA clause and reflected in customer billings.

Fair Value of Derivative Instruments in the Balance Sheet at September 30, 2016
	Asset Derivatives*				Liability Derivatives*
	Balance Sheet Location	Fair Value			Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Gasoline and heating oil contracts	Derivative Instrument Assets	$	0.3		Derivative Instrument Assets	$	—
Subtotal		0.3				—
Derivatives not designated as hedging instruments
Natural gas contracts	Accounts Receivable – Other	5.4			Accounts Receivable – Other	1.6
OTCBB natural gas contracts	Derivative Instrument Assets	—			Derivative Instrument Assets	0.2
Subtotal		5.4				1.8
Total derivatives		$	5.7			$	1.8
Fair Value of Derivative Instruments in the Balance Sheet at September 30, 2015
	Asset Derivatives				Liability Derivatives*
	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Gasoline and heating oil contracts	Accounts Receivable – Other	$	—		Accounts Receivable – Other	$	0.3
Subtotal		—				0.3
Derivatives not designated as hedging instruments
Natural gas contracts	Accounts Receivable – Other	1.2			Accounts Receivable – Other	16.4
	Derivative Instrument Assets	—			Derivative Instrument Assets	5.7
	Deferred Charges - Other	—			Deferred Charges - Other	0.2
Subtotal		1.2				22.3
Total derivatives		$	1.2			$	22.6

* The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the Balance Sheets. As such, the gross balances presented in the table above are not indicative of Laclede Gas’ net economic exposure. Refer to Note 9, Fair Value Measurements, for information on the valuation of derivative instruments.

Following is a reconciliation of the amounts in the tables above to the amounts presented in Laclede Gas’ Balance Sheets:

	2016			2015
Fair value of asset derivatives presented above	$	5.7		$	1.2
Fair value of cash margin receivables offset with derivatives	0.8			15.5
Netting of assets and liabilities with the same counterparty	(1.6		)	(16.7		)
Total	$	4.9		$	—
Derivative Instrument Assets, per Balance Sheets:
Derivative instrument assets	$	4.9		$	—
Total	$	4.9		$	—
Fair value of liability derivatives presented above	$	1.8		$	22.6
Netting of assets and liabilities with the same counterparty	(1.6		)	(16.7		)
Total	$	0.2		$	5.9
Derivative Instrument Liabilities, per Balance Sheets:
Current Liabilities – Other	$	0.2		$	5.7
Deferred Credits – Other	—			0.2
Total	$	0.2		$	5.9

Additionally, at September 30, 2016 and 2015, Laclede Gas had $0.5 and $5.9, respectively, in cash margin receivables not offset with derivatives, which are presented in Accounts Receivable – Other.

Alagasco

In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the GSA rider in accordance with Alagasco’s APSC approved tariff.

During the second quarter of fiscal year 2015, Alagasco entered into certain interest rate swap transactions to protect itself against adverse movement in interest rates in anticipation of its issuance of $115.0 of long-term debt. Alagasco received prior approval from the APSC to enter into these hedges. The notional amount of interest rate swaps outstanding was $80.5 with stated maturities ranging from 2025 to 2045 and fixed interest rates ranging between 2.18% and 2.85%. In April 2015, Alagasco entered into an additional hedge with a notional amount of $24.0 and terms within the same range. These derivative instruments were designated as cash flow hedges of forecasted transactions. These forward starting swaps involved the payment of a fixed interest rate and the receipt of LIBOR over the terms specified in the contracts. On May 21, 2015, the interest rate swap agreements were terminated and the settlement resulted in a $2.7 gain which was recorded as a regulatory liability. Of the total issuance of long-term debt, $35.0 was issued on September 15, 2015 and the remaining $80.0 was issued on December 1, 2015.

During the fiscal second quarter of 2016, Alagasco commenced a gasoline derivative program to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At September 30, 2016, Alagasco held 0.6 million gallons of gasoline futures contracts at an average price of $1.53 per gallon. Most of these contracts, the longest of which extends to December 2017, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815, “Derivatives and Hedging.” The gains or losses on these derivative instruments are not subject to Alagasco’s GSA clause. As of September 30, 2016, the fair value of related gasoline contracts was not significant.

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CONCENTRATIONS OF CREDIT RISK

12 Months Ended

Sep. 30, 2016

Risks and Uncertainties [Abstract]

CONCENTRATIONS OF CREDIT RISK

CONCENTRATIONS OF CREDIT RISK

Other than in LER (the Gas Marketing segment), Spire has no significant concentration of credit risk.

A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to $15.8 at September 30, 2016 ($12.4 reflecting netting arrangements). LER’s accounts receivable attributable to utility companies and their marketing affiliates comprised $52.8 of total accounts receivable at September 30, 2016 ($50.5 reflecting netting arrangements).

LER also has concentrations of credit risk with certain individually significant counterparties and with pipeline companies associated with its natural gas receivable amount. At September 30, 2016, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure) totaled $31.2 ($27.2 reflecting netting arrangements). These five counterparties are either investment-grade rated or owned by investment-grade rated companies.

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INCOME TAXES

12 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

Spire

The Company’s provision for income taxes charged during the fiscal years ended September 30, 2016, 2015, and 2014 are as follows:

	2016			2015			2014
Federal
Current	$	0.1		$	(3.3	)	$	0.3
Deferred	62.0			58.8			30.6
Investment tax credits	(0.2		)	(0.2		)	(0.2		)
State and local
Current	0.6			—			0.6
Deferred	7.0			6.9			1.0
Total income tax expense	$	69.5		$	62.2		$	32.3

The Company’s effective income tax rate varied from the federal statutory income tax rate for each year due to the following:

	2016		2015		2014
Federal income tax statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal income tax benefits	2.8		3.0		1.8
Certain expenses capitalized on books and deducted on tax return	(3.4	)	(3.7	)	(4.9	)
Taxes related to prior years	(0.2	)	(0.6	)	(0.7	)
Other items – net *	(1.7	)	(2.5	)	(3.6	)
Effective income tax rate	32.5	%	31.2	%	27.6	%

* Other consists primarily of property adjustments.

The Company’s significant items comprising the net deferred tax liability recorded in the Consolidated Balance Sheets as of September 30 are as follows:

	2016		2015
Deferred tax assets:
Reserves not currently deductible	$	21.3	$	14.8
Pension and other postretirement benefits	68.3		62.5
Operating losses	102.3		47.3
Other	—		1.5
Deferred tax assets	191.9		126.1
Less: valuation allowance	0.9		—
Total deferred tax assets	191.0		126.1
Deferred tax liabilities:
Relating to property	623.1		472.1
Regulatory pension and other postretirement benefits	106.8		110.6
Deferred gas costs	20.0		8.1
Other	48.4		11.6
Total deferred tax liabilities	798.3		602.4
Net deferred tax liability	607.3		476.3
Net deferred tax asset – current	—		5.8
Net deferred tax liability – noncurrent	$	607.3	$	482.1

In assessing whether deferred tax assets are realizable, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all significant available positive and negative evidence, including the existence of losses in recent years, the timing of deferred tax liability reversals, projected future taxable income, taxable income in carryback years, and tax planning strategies to assess the need for a valuation allowance. Based upon this evidence, management believes it is more likely than not the Company will realize the benefits of these deferred tax assets.

The Company has federal and state loss carryforwards of approximately $297.0 at September 30, 2016. The Company also has contribution carryforwards of approximately $12.2 at September 30, 2016. The loss carryforwards begin to expire in the fiscal year ending 2030 for certain state purposes and 2035 for federal and other states purposes. The contribution carryforwards begin to expire in fiscal year 2017. The Company has established a valuation allowance of $0.9 during the fiscal year as a portion of the charitable contribution carryforward will not be realized prior to its expiration. The Company also has various tax credit carryforwards of approximately $3.5 that begin to expire in 2017.

The Company recognizes the tax benefit from a tax position only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The Company records potential interest and penalties related to its uncertain tax positions as interest expense and other income deductions, respectively. Unrecognized tax benefits, accrued interest payable, and accrued penalties payable are reported as a reduction of a deferred tax asset for an operating loss carryforward.

The following table presents a reconciliation of the beginning and ending balances of the Company’s unrecognized tax benefits:

	2016			2015			2014
Unrecognized tax benefits, beginning of year	$	7.1		$	4.6		$	2.4
Increases related to tax positions taken in current year	3.4			2.9			2.6
Reductions due to lapse of applicable statute of limitations	(0.5		)	(0.4		)	(0.4		)
Unrecognized tax benefits, end of year	$	10.0		$	7.1		$	4.6

The amount of unrecognized tax benefits which, if recognized, would affect the Company’s effective tax rate were $3.3 and $3.1 as of September 30, 2016 and 2015, respectively. It is reasonably possible that events will occur in the next 12 months that could increase or decrease the amount of the Company’s unrecognized tax benefits. The Company does not expect that any such change will be significant to the Consolidated Balance Sheets.

As of September 30, 2016 and 2015, interest accrued associated with the Company’s uncertain tax positions was de minimis, and no penalties were accrued as of September 30, 2016.

The Company is subject to US federal income tax as well as income tax in various state and local jurisdictions. The Company is no longer subject to examination for fiscal years prior to 2013.

Regarding the Company’s recent EnergySouth acquisition, tax returns for the calendar years 2013 through 2015 remain open and subject to examination by the Internal Revenue Service and state taxing jurisdictions. These returns cover periods during which EnergySouth was owned by Sempra Global. The impact of any adjustments made to these returns by the relevant taxing authorities would be addressed by the indemnification provisions of the stock purchase agreement with Sempra Global.

Laclede Gas

Laclede Gas’ provision for income taxes charged during the fiscal years ended September 30, 2016, 2015, and 2014 are as follows:

	2016			2015			2014
Federal
Current	$	—		$	(2.1	)	$	(0.1	)
Deferred	37.5			40.9			34.3
Investment tax credits	(0.2		)	(0.2		)	(0.2		)
State and local
Current	0.1			(0.1		)	—
Deferred	8.0			4.7			1.5
Total income tax expense	$	45.4		$	43.2		$	35.5

Laclede Gas’ effective income tax rate varied from the federal statutory income tax rate for each year due to the following:

	2016		2015		2014
Federal income tax statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal income tax benefits	2.8		2.8		1.8
Certain expenses capitalized on books and deducted on tax return	(4.8	)	(4.9	)	(4.5	)
Taxes related to prior years	(0.2	)	(0.8	)	(0.7	)
Other items – net *	(2.8	)	(3.0	)	(3.3	)
Effective income tax rate	30.0	%	29.1	%	28.3	%

* Other consists primarily of property adjustments.

Laclede Gas’ significant items comprising the net deferred tax liability reported in the Balance Sheets as of September 30 are as follows:

	2016		2015
Deferred tax assets:
Reserves not currently deductible	$	14.9	$	15.4
Pension and other postretirement benefits	56.9		62.5
Operating losses	29.9		3.7
Other	—		1.5
Deferred tax assets	101.7		83.1
Less: valuation allowance	0.9		—
Total deferred tax assets	100.8		83.1
Deferred tax liabilities:
Relating to utility property	497.0		425.0
Regulatory pension and other postretirement benefits	106.8		120.2
Deferred gas costs	20.0		8.2
Other	33.9		14.5
Total deferred tax liabilities	657.7		567.9
Net deferred tax liability	556.9		484.8
Net deferred tax asset – current	—		0.4
Net deferred tax liability – noncurrent	$	556.9	$	485.2

Spire files a consolidated federal return and various state income tax returns and allocates income taxes to Laclede Gas and its other subsidiaries as if each entity were a separate taxpayer.

In assessing whether deferred tax assets are realizable, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all significant available positive and negative evidence, including the existence of losses in recent years, the timing of deferred tax liability reversals, projected future taxable income, taxable income in carryback years, and tax planning strategies to assess the need for a valuation allowance. Based upon this evidence, management believes it is more likely than not that Laclede Gas will realize the benefits of these deferred tax assets.

Laclede Gas has state and federal loss carryforwards of approximately $105.0, at September 30, 2016, based on a separate company basis. For federal tax purposes, these loss carryforwards may be utilized against income from another member of the consolidated group. Laclede Gas also has contribution carryforwards of approximately $12.0 at September 30, 2016. The loss carryforwards begin to expire in the fiscal year ending 2035 for federal and state purposes. The contribution carryforwards begin to expire in fiscal year ending 2017. Laclede Gas has established a valuation allowance of $0.9 during the fiscal year as a portion of the charitable contribution carryforward will not be realized prior to its expiration. Laclede Gas also has approximately $2.0 of various tax credit carryforwards with expiration dates which begin to expire in 2017.

Laclede Gas recognizes the tax benefit from a tax position only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. Laclede Gas records potential interest and penalties related to its uncertain tax positions as interest expense and other income deductions, respectively. Unrecognized tax benefits, accrued interest payable, and accrued penalties payable are reported as a reduction of a deferred tax asset for an operating loss carryforward.

The following table presents a reconciliation of the beginning and ending balances of Laclede Gas unrecognized tax benefits:

	2016			2015			2014
Unrecognized tax benefits, beginning of year	$	6.9		$	4.2		$	2.0
Increases related to tax positions taken in current year	3.3			2.9			2.5
Reductions due to lapse of applicable statute of limitations	(0.5		)	(0.2		)	(0.3		)
Unrecognized tax benefits, end of year	$	9.7		$	6.9		$	4.2

The amount of unrecognized tax benefits, which, if recognized, would affect Laclede Gas’ effective tax rate were $3.1 and $2.9 as of September 30, 2016 and 2015, respectively. It is reasonably possible that events will occur in the next 12 months that could increase or decrease the amount of Laclede Gas’ unrecognized tax benefits. Laclede Gas does not expect that any such change will be significant to Laclede Gas’ Balance Sheets.

As of September 30, 2016 and 2015, interest accrued associated with Laclede Gas’ uncertain tax positions was de minimis, and no penalties were accrued.

Laclede Gas is subject to US federal income tax as well as income tax in various state and local jurisdictions, and is no longer subject to examination for fiscal years prior to 2013.

Alagasco

Alagasco’s provision for income taxes charged during the fiscal years ended September 30, 2016 and 2015, and the nine months ended September 30, 2014, are as follows:

	Year Ended September 30,			Year Ended September 30,		Nine Months Ended September 30,
	2016			2015		2014
Federal
Current	$	(0.8	)	$	—	$	14.1
Deferred	29.4			25.9		3.5
State and local
Current	—			0.1		1.8
Deferred	3.8			3.3		0.5
Total income tax expense	$	32.4		$	29.3	$	19.9

Alagasco’s effective income tax rate varied from the federal statutory income tax rate for each year due to the following:

	Year Ended September 30,		Year Ended September 30,		Nine Months Ended September 30,
	2016		2015		2014
Federal income tax statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal income tax benefits	2.8		2.8		2.8
Other items – net	0.1		0.1		(0.2	)
Effective income tax rate	37.9	%	37.9	%	37.6	%

Alagasco’s significant items comprising the net deferred tax asset reported in the Balance Sheets as of September 30 are as follows:

	2016		2015
Deferred tax assets:
Reserves not currently deductible	$	6.3	$	7.0
Pension and other postretirement benefits	11.4		9.6
Goodwill	233.4		251.5
Operating losses	60.2		32.4
Other	—		1.4
Total deferred tax assets	311.3		301.9
Deferred tax liabilities:
Relating to utility property	87.6		45.1
Other	2.3		2.2
Total deferred tax liabilities	89.9		47.3
Net deferred tax asset	221.4		254.6
Net deferred tax asset – current	—		6.2
Net deferred tax asset – noncurrent	$	221.4	$	248.4

Spire files a consolidated federal return and various state income tax returns and allocates income taxes to Alagasco and its other subsidiaries as if each entity were a separate taxpayer.

In assessing whether deferred tax assets are realizable, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all significant available positive and negative evidence, including the existence of losses in recent years, the timing of deferred tax liability reversals, projected future taxable income, taxable income in carryback years, and tax planning strategies to assess the need for a valuation allowance. Based upon this evidence, management believes it is more likely than not that Alagasco will realize the benefits of these deferred tax assets.

On a separate company basis, Alagasco has state and federal loss carryforwards of approximately $159.0, at September 30, 2016 generated since the acquisition. The loss carryforwards begin to expire in the fiscal year ending 2030 for state purposes and 2035 for federal purposes. For federal tax purposes, these loss carryforwards may be utilized against income from another member of the consolidated group.

Alagasco recognizes the tax benefit from a tax position only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. Alagasco records potential interest and penalties related to its uncertain tax positions as interest expense and other income deductions, respectively. Alagasco has reported no unrecognized tax benefits since the acquisition by Spire in August 2014.

The following table presents a reconciliation of the beginning and ending balances of Alagasco’s unrecognized tax benefits:

	Year Ended September 30,		Year Ended September 30,		Nine Months Ended September 30,
	2016		2015		2014
Unrecognized tax benefits, beginning of period	$	—	$	—	$	0.3
Reduction for transfer of balance to Energen	—		—		(0.3		)
Unrecognized tax benefits, end of period	$	—	$	—	$	—

Alagasco is subject to US federal income tax as well as income tax in various state and local jurisdictions. Alagasco’s tax returns for the periods after 2012 remain open and subject to examination by the Internal Revenue Service and state taxing jurisdictions. The returns covering 2013 and 2014 include periods during which Alagasco was owned by Energen. The impact of any adjustments made to those returns by the relevant taxing authorities would be addressed by the indemnification provisions of the stock purchase agreement with Energen.

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

12 Months Ended

Sep. 30, 2016

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

The Spire information in this note reflects all plans of the Company, including information for plans of EnergySouth since September 12, 2016 and Alagasco since August 31, 2014. The net pension and postretirement obligations were re-measured at those acquisition dates as well as at the fiscal year end.

Pension Plans

The pension plans of Spire consist of plans for employees at the Missouri Utilities, plans covering the employees of Alagasco, and plans covering employees for EnergySouth.

The Missouri Utilities have non-contributory, defined benefit, trusteed forms of pension plans covering the majority of their employees. Plan assets consist primarily of corporate and US government obligations and a growth segment consisting of exposure to equity markets, commodities, real estate and inflation-indexed securities, achieved through derivative instruments and investments in diversified mutual funds.

Alagasco has non-contributory, defined benefit, trusteed forms of pension plans covering the majority of its employees. Qualified plan assets are comprised of United States equities consisting of mutual and commingled funds with varying strategies, global equities consisting of mutual funds, alternative investments of limited partnerships and commingled and mutual funds, and fixed income investments.

The net periodic pension costs include the following components:

	Spire									Laclede Gas									Alagasco
	2016			2015			2014			2016			2015			2014			2016			2015			2014*
Service cost – benefits earned during the period	$	15.3		$	17.3		$	10.2		$	10.0		$	11.5		$	9.7		$	5.3		$	5.8		$	5.1
Interest cost on projected benefit obligation	28.0			29.5			24.5			21.7			23.3			24.0			6.3			6.2			4.1
Expected return on plan assets	(34.9		)	(37.4		)	(27.2		)	(26.7		)	(29.2		)	(26.5		)	(8.2		)	(8.2		)	(5.2		)
Amortization of other comprehensive income	—			—			0.4			—			—			—			—			—			—
Amortization of prior service cost	0.4			0.5			0.5			0.4			0.5			0.5			—			—			0.1
Amortization of actuarial loss	8.0			7.5			7.1			7.9			7.5			7.1			0.1			—			2.2
Loss on lump-sum settlements	3.3			19.6			1.5			—			18.0			1.5			3.3			1.6			10.1
Special termination benefits	1.6			—			—			1.6			—			—			—			—			—
Subtotal	21.7			37.0			17.0			14.9			31.6			16.3			6.8			5.4			16.4
Regulatory adjustment	17.8			(2.1		)	10.4			11.7			(5.2		)	10.4			6.1			3.1			0.4
Net pension cost	$	39.5		$	34.9		$	27.4		$	26.6		$	26.4		$	26.7		$	12.9		$	8.5		$	16.8
													* Nine months ended September 30

Other changes in plan assets and pension benefit obligations recognized in other comprehensive income or loss (OCI) include the following:

	Spire									Laclede Gas									Alagasco
	2016			2015			2014			2016			2015			2014			2016			2015			2014*
Current year actuarial loss	$	46.8		$	48.3		$	15.7		$	21.6		$	26.0		$	14.2		$	25.2		$	22.3		$	1.5
Amortization of actuarial loss	(8.0		)	(7.5		)	(7.1		)	(7.9		)	(7.5		)	(7.1		)	(0.1		)	—			—
Acceleration of loss recognized due to settlement	(3.3		)	(19.6		)	(1.5		)	—			(18.0		)	(1.5		)	(3.3		)	(1.6		)	—
Amortization of current year service cost	5.0			—			—			5.0			—			—			—			—			—
Amortization of prior service cost	(0.4		)	(0.5		)	(0.5		)	(0.4		)	(0.5		)	(0.5		)	—			—			—
Subtotal	40.1			20.7			6.6			18.3			—			5.1			21.8			20.7			1.5
Regulatory adjustment	(39.8		)	(21.2		)	(6.1		)	(18.0		)	(0.5		)	(4.7		)	(21.8		)	(20.7		)	(1.5		)
Total recognized in OCI	$	0.3		$	(0.5	)	$	0.5		$	0.3		$	(0.5	)	$	0.4		$	—		$	—		$	—
													* Nine months ended September 30

Spire pension obligations are driven by separate plan and regulatory provisions governing Laclede Gas, Alagasco and EnergySouth pension plans.

Pursuant to the provisions of the Missouri Utilities’ and Alagasco’s pension plans, pension obligations may be satisfied by lump-sum cash payments. Lump-sum payments are recognized as settlements (which can result in gains or losses) only if the total of such payments exceeds 100% of the sum of service and interest costs in a specific year. Special termination benefits, when offered, are also recognized as settlements which can result in gains or losses. Two Alagasco plans and one Laclede plan met the criteria for settlement recognition in the fiscal year ended September 30, 2016, requiring re-measurement of the obligation under those plans using updated census data and assumptions for discount rate and mortality. Lump-sum payments recognized as settlements during fiscal year 2016, 2015, and 2014 were $16.6 (attributable to Alagasco), $71.1, and $22.1, respectively.

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains or losses not yet includible in pension cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas’ eastern Missouri qualified pension plan is based on an annual allowance of $15.5 effective January 1, 2011. The recovery in rates for MGE’s qualified pension plan is based on an annual allowance of $10 effective February 20, 2010. The difference between these amounts and pension expense as calculated pursuant to the above and that otherwise would be included in the statements of income and statements of comprehensive income is deferred as a regulatory asset or regulatory liability.

The following table shows the reconciliation of the beginning and ending balances of the pension benefit obligation at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Benefit obligation, beginning of year	$	652.3		$	692.4		$	497.6		$	543.6		$	154.7		$	148.8
Service cost	15.3			17.3			10.0			11.5			5.3			5.8
Interest cost	28.0			29.5			21.7			23.3			6.3			6.2
Actuarial loss (gain)	85.8			(12.8		)	59.2			(20.7		)	26.6			7.9
Plan amendments	5.1			—			5.1			—			—			—
EnergySouth acquisition	60.4			—			—			—			—			—
Settlement loss	1.1			16.5			—			14.5			1.1			2.0
Special termination benefits	1.6			—			1.6			—			—			—
Settlement benefits paid	(16.6		)	(71.1		)	—			(58.2		)	(16.6		)	(12.9		)
Regular benefits paid	(38.3		)	(19.5		)	(35.2		)	(16.4		)	(3.1		)	(3.1		)
Benefit obligation, end of year	$	794.7		$	652.3		$	560.0		$	497.6		$	174.3		$	154.7
Accumulated benefit obligation, end of year	724.5			$	591.4		517.7			$	456.9		149.8			$	134.5

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Fair value of plan assets, beginning of year	$	448.9		$	506.6		$	339.9		$	387.4		$	109.0		$	119.2
Actual return on plan assets	75.1			(7.2		)	64.4			(3.0		)	10.7			(4.2		)
Employer contributions	26.6			40.1			26.6			30.1			—			10.0
EnergySouth acquisition	44.8			—			—			—			—			—
Settlement benefits paid	(16.6		)	(71.1		)	—			(58.2		)	(16.6		)	(12.9		)
Regular benefits paid	(38.3		)	(19.5		)	(35.2		)	(16.4		)	(3.1		)	(3.1		)
Fair value of plan assets, end of year	$	540.5		$	448.9		$	395.7		$	339.9		$	100.0		$	109.0
Funded status of plans, end of year	$	(254.2	)	$	(203.4	)	$	(164.3	)	$	(157.7	)	$	(74.3	)	$	(45.7	)

The following table sets forth the amounts recognized in the balance sheets at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Current liabilities	$	(0.6	)	$	(0.5	)	$	(0.6	)	$	(0.5	)	$	—		$	—
Noncurrent liabilities	(253.6		)	(202.9		)	(163.7		)	(157.2		)	(74.3		)	(45.7		)
Total	$	(254.2	)	$	(203.4	)	$	(164.3	)	$	(157.7	)	$	(74.3	)	$	(45.7	)

Pre-tax amounts recognized in accumulated other comprehensive loss not yet recognized as components of net periodic pension cost consist of:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Net actuarial loss	$	179.4		$	143.9		$	135.5		$	121.9		$	43.9		$	22.0
Prior service costs	8.2			3.5			8.2			3.5			—			—
Subtotal	187.6			147.4			143.7			125.4			43.9			22.0
Adjustments for amounts included in regulatory assets	(184.8		)	(144.9		)	(140.9		)	(122.9		)	(43.9		)	(22.0		)
Total	$	2.8		$	2.5		$	2.8		$	2.5		$	—		$	—

At September 30, 2016, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive loss into net periodic pension cost during fiscal year 2017:

	Spire			Laclede Gas			Alagasco
Amortization of net actuarial loss	$	13.5		$	11.6		$	1.9
Amortization of prior service cost	1.0			1.0			—
Subtotal	14.5			12.6			1.9
Regulatory adjustment	(14.2		)	(12.3		)	(1.9		)
Total	$	0.3		$	0.3		$	—

The assumptions used to calculate net periodic pension costs for Laclede Gas are as follows:

	2016	2015	2014
Weighted average discount rate - Laclede Gas division plans	4.40%	4.30%	4.70%
Weighted average discount rate - MGE division plans	4.50%	4.45%	5.00%
Weighted average rate of future compensation increase *	3.00%	3.00%	3.00%
Expected long-term rate of return on plan assets *	7.75%	7.75%	7.75%

* Assumptions for weighted average rate of future compensation increase and expected long-term rate of return on plan assets are the same for both Laclede Gas and MGE plans.

The assumptions used to calculate net periodic pension costs for Alagasco are as follows:

	2016	2015	2014*
Weighted average discount rate	4.25% /4.30%	4.15% /4.25%	4.00% / 4.05%
Weighted average rate of future compensation increase	3.00%	2.92%	2.92%
Expected long-term rate of return on plan assets	7.50%	7.00% / 7.25%	7.00% / 7.25%

* Nine-month transition period ended September 30

The weighted average discount rate is based on long-term, high quality bond indices at the measurement date. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns. The overall expected rate of return for the portfolio was developed based on the target allocation for each class.

The assumptions used to calculate the benefit obligations are as follows:

	2016	2015
Weighted average discount rate - Laclede Gas division	3.50%	4.40%
Weighted average discount rate - MGE division	3.50%	4.50%
Weighted average discount rate - Alagasco	3.45%/3.50%	4.25%/4.30%
Weighted average rate of future compensation increase - Laclede Gas, Alagasco and MGE	3.00%	3.00%

Following are the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for plans that have a projected benefit obligation and an accumulated benefit obligation in excess of plan assets:

	Spire				Laclede Gas				Alagasco
	2016		2015		2016		2015		2016		2015
Projected benefit obligation	$	794.8	$	652.3	$	560.0	$	497.6	$	174.3	$	154.7
Accumulated benefit obligation	724.5		591.4		517.7		456.9		149.8		134.5
Fair value of plan assets	540.5		448.9		395.7		339.9		100.0		109.0

Following are the targeted and actual plan assets by category as of September 30 of each year for Laclede Gas and Alagasco:

Laclede Gas	2016 Target		2016 Actual		2015 Target		2015 Actual
Equity markets	56.2	%	56.9	%	52.0	%	48.4	%
Debt securities	43.8	%	43.1	%	48.0	%	50.1	%
Other*	—	%	—	%	—	%	1.5	%
Total	100.0	%	100.0	%	100.0	%	100.0	%

* Other investments in 2016 and 2015 consisted of cash equivalents.

Alagasco	2016 Target		2016 Actual		2015 Target		2015 Actual
Equity markets	60.0	%	59.2	%	60.0	%	52.9	%
Debt securities	29.0	%	28.8	%	29.0	%	27.9	%
Other*	11.0	%	12.0	%	11.0	%	19.2	%
Total	100.0	%	100.0	%	100.0	%	100.0	%

* Other investments in 2016 included cash, real estate, commodities, natural resources and TIPS. In 2015, this included cash and cash equivalents, hedge funds, real estate, and all asset funds, which can invest in equities or fixed income.

Laclede Gas’ investment policies are designed to maximize, to the extent possible, the funded status of the plan over time, and minimize volatility of funding and costs. The policy seeks to maximize investment returns consistent with these objectives and Laclede Gas’ tolerance for risk. The duration of plan liabilities and the impact of potential changes in asset values on the funded status are fundamental considerations in the selection of plan assets. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with the policy. The policy seeks to avoid significant concentrations of risk by investing in a diversified portfolio of assets. Investments in corporate, US government and agencies, and, to a lesser extent, international debt securities seek to provide duration matching with plan liabilities, and typically have investment grade ratings and reflect allocations across various entities and industries. There are also exposures to additional asset types in the target portfolio: commodities, real estate and inflation-indexed securities. During 2015, the target portfolio was rebalanced to include a higher weighting for the growth (equity) component and a lower weighting to the liability-driven (debt) component. The investment policy permits the use of derivative instruments, which may be used to achieve the desired market exposure of an index, adjust portfolio duration, or rebalance the total portfolio to the target asset allocation. The Growth Strategy utilizes a combination of derivative instruments and debt securities to achieve diversified exposure to equity and other markets while generating returns from the fixed-income investments and providing further duration matching with the liabilities. Performance and compliance with the guidelines is regularly monitored. The policy calls for increased allocations to debt securities as the funded status improves.

Alagasco employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions. Alagasco has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by Alagasco to manage separate pools of assets. Funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment managers are performing satisfactorily. Alagasco seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the pension plans do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

Following are expected pension benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter, for Spire, Laclede Gas, and Alagasco:

	2017		2018		2019		2020		2021		2022- 2026
Spire	$	61.3	$	56.2	$	57.1	$	56.6	$	56.8	$	286.3
Laclede Gas	48.2		43.3		43.5		42.2		40.4		196.6
Alagasco	10.9		10.6		11.2		11.9		13.7		74.5

The funding policy of Laclede Gas and Alagasco is to contribute an amount not less than the minimum required by government funding standards, nor more than the maximum deductible amount for federal income tax purposes. Laclede Gas contributions to the pension plans in fiscal year 2017 are anticipated to be $29.0 into the qualified trusts, and $0.6 into the non-qualified plans. Alagasco has no required contributions to the qualified pension plans during 2017. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. During fiscal 2017, Alagasco may make additional discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions.

Postretirement Benefits

The Utilities provide certain life insurance benefits at retirement. Laclede Gas plans provide for medical insurance after early retirement until age 65. For retirements prior to January 1, 2015, the MGE plans provided medical insurance after retirement until death. For retirements after January 1, 2015, the MGE plans provide medical insurance after early retirement until age 65. Under the Alagasco plans, medical insurance is currently available upon retirement until death for certain retirees depending on the type of employee and the date the employee was originally hired.

Net periodic postretirement benefit costs consist of the following components:

	Spire									Laclede Gas									Alagasco
	2016			2015			2014			2016			2015			2014			2016			2015			2014*
Service cost – benefits earned during the period	$	10.9		$	12.8		$	11.3		$	10.6		$	12.3		$	11.2		$	0.3		$	0.5		$	0.4
Interest cost on accumulated postretirement benefit obligation	10.2			11.2			8.9			8.1			8.6			8.7			2.1			2.6			1.9
Expected return on plan assets	(13.5		)	(13.2		)	(7.3		)	(8.5		)	(8.1		)	(6.8		)	(5.0		)	(5.1		)	(3.6		)
Amortization of prior other comprehensive loss	—			—			(0.2		)	—			—			—			—			—			—
Amortization of prior service cost	0.3			0.8			—			0.3			0.8			—			—			—			—
Amortization of actuarial loss (gain)	3.6			5.1			6.0			3.8			5.1			6.0			(0.2		)	—			(1.0		)
Special termination benefits	2.6			—			—			2.6			—			—			—			—			—
Subtotal	14.1			16.7			18.7			16.9			18.7			19.1			(2.8		)	(2.0		)	(2.3		)
Regulatory adjustment	(6.6		)	(11.0		)	(9.6		)	(4.8		)	(9.2		)	(9.6		)	(1.8		)	(1.8		)	(0.2		)
Net postretirement benefit cost	$	7.5		$	5.7		$	9.1		$	12.1		$	9.5		$	9.5		$	(4.6	)	$	(3.8	)	$	(2.5	)
													* Nine months ended September 30

Other changes in plan assets and postretirement benefit obligations recognized in OCI include the following:

	Spire									Laclede Gas									Alagasco
	2016			2015			2014			2016			2015			2014			2016			2015			2014*
Current year actuarial loss (gain)	$	0.8		$	(8.5	)	$	(3.1	)	$	1.4		$	(2.4	)	$	(4.2	)	$	(0.6	)	$	(6.1	)	$	1.1
Amortization of actuarial (loss) gain	(3.6		)	(5.1		)	(6.0		)	(3.8		)	(5.1		)	(6.0		)	0.2			—			—
Amortization of prior service (cost) credit	(0.3		)	(0.8		)	2.5			(0.3		)	(0.8		)	2.5			—			—			—
Current year prior service credit	(1.8		)	(4.9		)	—			—			(4.9		)	—			(1.8		)	—			—
Subtotal	(4.9		)	(19.3		)	(6.6		)	(2.7		)	(13.2		)	(7.7		)	(2.2		)	(6.1		)	1.1
Regulatory adjustment	4.9			19.3			6.6			2.7			13.2			7.7			2.2			6.1			(1.1		)
Total recognized in OCI	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
													* Nine months ended September 30

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains and losses not yet includible in postretirement benefit cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the accumulated postretirement benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas’ postretirement benefit plans is based on an annual allowance of $9.5 effective January 1, 2011. The difference between these amounts and postretirement benefit cost based on the above and that otherwise would be included in the statements of income and statements of comprehensive income is deferred as a regulatory asset or regulatory liability.

The following table sets forth the reconciliation of the beginning and ending balances of the postretirement benefit obligation at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Benefit obligation, beginning of year	$	239.2		$	258.5		$	191.9		$	197.9		$	47.3		$	60.6
Service cost	10.9			12.8			10.6			12.3			0.3			0.5
Interest cost	10.2			11.2			8.1			8.6			2.1			2.6
Actuarial loss (gain)	7.1			(23.7		)	6.7			(10.9		)	0.4			(12.8		)
Plan amendments	(1.8		)	(4.9		)	—			(4.9		)	(1.8		)	—
EnergySouth acquisition	5.9			—			—			—			—			—
Special termination benefits	2.6			—			2.6			—			—			—
Retiree drug subsidy program	0.2			0.4			—			—			0.2			0.4
Gross benefits paid	(15.1		)	(15.1		)	(12.0		)	(11.1		)	(3.1		)	(4.0		)
Benefit obligation, end of year	$	259.2		$	239.2		$	207.9		$	191.9		$	45.4		$	47.3

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Fair value of plan assets at beginning of year	$	223.3		$	222.5		$	143.6		$	137.2		$	79.7		$	85.3
Actual return on plan assets	19.9			(2.0		)	13.8			(0.4		)	6.2			(1.6		)
Employer contributions	14.3			17.9			14.3			17.9			—			—
EnergySouth acquisition	4.0			—			—			—			—			—
Gross benefits paid	(15.1		)	(15.1		)	(12.0		)	(11.1		)	(3.1		)	(4.0		)
Fair value of plan assets, end of year	$	246.4		$	223.3		$	159.7		$	143.6		$	82.8		$	79.7
Funded status of plans, end of year	$	(12.8	)	$	(15.9	)	$	(48.2	)	$	(48.3	)	$	37.4		$	32.4

The following table sets forth the amounts recognized in the balance sheets at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016		2015
Current assets	$	0.3		$	—		$	0.3		$	—		$	—	$	—
Noncurrent assets	37.4			35.5			—			3.1			37.4		32.4
Current liabilities	(0.4		)	(0.3		)	(0.4		)	(0.3		)	—		—
Noncurrent liabilities	(50.1		)	(51.1		)	(48.1		)	(51.1		)	—		—
Total	$	(12.8	)	$	(15.9	)	$	(48.2	)	$	(48.3	)	$	37.4	$	32.4

Pre-tax amounts recognized in accumulated other comprehensive loss not yet recognized as components of net periodic postretirement benefit cost consist of:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Net actuarial loss	$	38.0		$	40.8		$	43.4		$	45.8		$	(5.4	)	$	(5.0	)
Prior service credit	(5.2		)	(3.1		)	(3.4		)	(3.1		)	(1.8		)	—
Subtotal	32.8			37.7			40.0			42.7			(7.2		)	(5.0		)
Adjustments for amounts included in regulatory assets	(32.8		)	(37.7		)	(40.0		)	(42.7		)	7.2			5.0
Total	$	—		$	—		$	—		$	—		$	—		$	—

At September 30, 2016, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive loss into net periodic postretirement benefit cost during fiscal year 2017:

	Spire			Laclede Gas			Alagasco
Amortization of net actuarial loss (gain)	$	2.4		$	2.5		$	(0.1	)
Amortization of prior service cost	0.1			0.3			(0.2		)
Subtotal	2.5			2.8			(0.3		)
Regulatory adjustment	(2.5		)	(2.8		)	0.3
Total	$	—		$	—		$	—

The assumptions used to calculate net periodic postretirement benefit costs for Laclede Gas are as follows:

	2016		2015		2014
Weighted average discount rate Laclede Gas division plans	4.00	%	4.15	%	4.60	%
Weighted average discount rate MGE division plans	4.30	%	4.40	%	4.95	%
Weighted average rate of future compensation increase - Laclede Gas plans	3.00	%	3.00	%	3.00	%
Expected long-term rate of return on plan assets - Laclede Gas division plans	6.00% / 7.75%		6.25% / 7.75%		6.25% / 7.75%
Expected long-term rate of return on plan assets - MGE division plans	4.75	%	5.00	%	3.75% / 5.75%

The assumptions used to calculate net periodic postretirement benefit costs for Alagasco are as follows:

	2016		2015		2014
Weighted average discount rate	4.50	%	4.40	%	4.25	%
Weighted average rate of future compensation increase	n/a		n/a		2.92	%
Expected long-term rate of return on plan assets	4.50% / 7.25%		4.75% / 7.50%		4.75% / 7.25%

The weighted average discount rate is based on long-term, high quality bond indices at the measurement date. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns. The overall expected rate of return for the portfolio was developed based on the target allocation for each class.

The assumptions used to calculate the accumulated postretirement benefit obligations for Laclede Gas are as follows:

	2016		2015
Weighted average discount rate - Laclede Gas division plans	3.15	%	4.00	%
Weighted average discount rate - MGE division plans	3.45	%	4.30	%
Weighted average rate of future compensation increase	3.00	%	3.00	%

The assumptions used to calculate the accumulated postretirement benefit obligations for Alagasco are as follows:

	2016		2015
Weighted average discount rate	3.60	%	4.50	%
Weighted average rate of future compensation increase	n/a		n/a

The assumed medical cost trend rates at September 30 are as follows:

	2016		2015
Medical cost trend assumed for next year - Laclede Gas	7.50	%	7.00	%
Medical cost trend assumed for next year - Alagasco	7.50	%	7.00	%
Rate to which the medical cost trend rate is assumed to decline (the ultimate medical cost trend rate)	5.00	%	5.00	%
Year the rate reaches the ultimate trend	2023		2020

The following table presents the effects of an assumed 1% change in the assumed medical cost trend rate:

	Spire					Laclede Gas					Alagasco
	1% Increase		1% Decrease			1% Increase		1% Decrease			1% Increase		1% Decrease
Net periodic postretirement benefit cost	$	1.5	$	(1.4	)	$	1.5	$	(1.4	)	$	—	$	—
Accumulated postretirement benefit obligation	11.0		(10.2		)	9.0		(8.4		)	1.3		(1.2		)

Following are the targeted and actual plan assets by category as of September 30 of each year for Laclede Gas and Alagasco:

Laclede Gas	Target		2016 Actual		2015 Actual
Equity securities	60.0	%	59.1	%	59.6	%
Debt securities	40.0	%	39.4	%	39.7	%
Other (cash and cash equivalents)	—	%	1.5	%	0.7	%
Total	100.0	%	100.0	%	100.0	%

Alagasco	Target		2016 Actual		2015 Actual
Equity securities	60.0	%	60.5	%	59.7	%
Debt securities	40.0	%	39.5	%	40.3	%
Total	100.0	%	100.0	%	100.0	%

Missouri state law provides for the recovery in rates of costs accrued pursuant to GAAP provided that such costs are funded through an independent, external funding mechanism. Laclede Gas established Voluntary Employees’ Beneficiary Association and Rabbi Trusts as its external funding mechanisms. Laclede Gas’ investment policy seeks to maximize investment returns consistent with Laclede Gas’ tolerance for risk. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with policy. Performance and compliance with the guidelines is regularly monitored. Laclede Gas’ current investment policy targets an asset allocation of 60% to equity securities and 40% to debt securities, excluding cash held in short-term debt securities for the purpose of making benefit payments. Laclede Gas currently invests in a mutual fund which is rebalanced on an ongoing basis to the target allocation. The mutual fund is diversified across US stock and bond markets.

Alagasco established Voluntary Employees’ Beneficiary Association accounts as its external funding mechanisms for post-retirement benefit costs. Alagasco’s investment policy seeks to maximize investment returns consistent with its tolerance for risk. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with policy. Performance and compliance with the guidelines is regularly monitored. Alagasco’s current investment policy targets an asset allocation of 60% to equity securities and 40% to debt securities. Alagasco currently invests in several mutual funds which are rebalanced periodically to the target allocation. The mutual funds are diversified across US and international stock markets and the US bond market.

Following are expected postretirement benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter for Spire, Laclede Gas, and Alagasco:

	2017		2018		2019		2020		2021		2022- 2026
Spire	$	15.4	$	16.7	$	17.9	$	19.1	$	20.1	$	108.6
Laclede Gas	12.3		13.7		14.8		15.8		16.8		92.5
Alagasco	2.9		2.8		2.8		2.9		2.9		14.1

Laclede Gas’ funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. Contributions to the postretirement plans in fiscal year 2017 are anticipated to be $10.3 to the qualified trusts and $0.4 paid directly to participants from Laclede Gas funds.

Alagasco’s funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. In fiscal 2017, it is not anticipated that contributions will be made to the postretirement plans.

Other Plans

Laclede Gas and Alagasco sponsor 401(k) plans that cover substantially all employees. The plans allow employees to contribute a portion of their base pay in accordance with specific guidelines. Laclede Gas provides a match of such contributions within specific limits. The cost of the defined contribution plans of Laclede Gas amounted to $8.2, $8.0, and $6.7 for fiscal years 2016, 2015, and 2014, respectively. Alagasco also provides a match of employee contributions within specific limits. The cost of the defined contribution plans of Alagasco amounted to $2.3, $3.0, and $4.7 for fiscal years 2016 and 2015, and the nine months ended September 30, 2014, respectively.

Fair Value Measurements of Pension and Other Postretirement Plan Assets

Spire

The table below categorizes the fair value measurements of the Spire pension plan assets:

	Quoted Prices in Active Markets (Level 1)			Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	51.2		$	—	$	—	$	51.2
Stock/bond mutual fund	99.3			26.7		0.1		126.1
Debt Securities
US bond mutual funds	23.0			126.0		—		149.0
US government	42.1			3.0		—		45.1
US corporate	137.4			—		—		137.4
US municipal	6.3			—		—		6.3
International	25.3			—		—		25.3
Derivatives and margin (payable)	(1.0		)	1.1		—		0.1
Total	$	383.6		$	156.8	$	0.1	$	540.5
As of September 30, 2015
Cash and cash equivalents	$	43.4		$	0.2	$	—	$	43.6
Stock/bond mutual fund	46.4			74.6		9.6		130.6
Debt Securities
US bond mutual funds	—			9.3		—		9.3
US government	58.7			—		—		58.7
US corporate	123.7			42.9		—		166.6
US municipal	—			5.9		—		5.9
International	—			31.3		—		31.3
Derivative instruments	—			2.9		—		2.9
Total	$	272.2		$	167.1	$	9.6	$	448.9

The table below categorizes the fair value measurements of Spire’s postretirement plan assets:

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	4.8	$	—	$	—	$	4.8
US stock/bond mutual fund	157.9		68.5		—		226.4
International fund	0.9		14.3		—		15.2
Total	$	163.6	$	82.8	$	—	$	246.4
As of September 30, 2015
Cash and cash equivalents	$	1.6	$	—	$	—	$	1.6
US stock/bond mutual fund	115.5		92.8		—		208.3
International fund	—		13.4		—		13.4
Total	$	117.1	$	106.2	$	—	$	223.3

Cash and cash equivalents include money market mutual funds valued based on quoted market prices. Fair values of derivative instruments are calculated by investment managers who use valuation models that incorporate observable market inputs. Debt securities are valued based on broker/dealer quotations or by using observable market inputs. The stock and bond mutual funds are valued at the quoted market price of the identical securities.

Laclede Gas

The table below categorizes the fair value measurements of Laclede Gas’ pension plan assets:

	Quoted Prices in Active Markets (Level 1)			Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	46.5		$	—	$	—	$	46.5
Stock/bond mutual fund	—			14.8		0.1		14.9
Debt Securities
US bond mutual funds	—			120.2		—		120.2
US government	42.1			3.0		—		45.1
US corporate	137.4			—		—		137.4
US municipal	6.3			—		—		6.3
International	25.2			—		—		25.2
Derivatives and margin (payable)	(1.0		)	1.1		—		0.1
Total	$	256.5		$	139.1	$	0.1	$	395.7
As of September 30, 2015
Cash and cash equivalents	$	31.8		$	—	$	—	$	31.8
Stock/bond mutual funds	—			67.6		0.1		67.7
Debt Securities
US government	37.7			—		—		37.7
US corporate	123.7			42.9		—		166.6
US municipal	—			5.9		—		5.9
International	—			27.3		—		27.3
Derivative instruments	—			2.9		—		2.9
Total	$	193.2		$	146.6	$	0.1	$	339.9

The table below categorizes the fair value measurements of Laclede Gas’ postretirement plan assets:

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	4.6	$	—	$	—	$	4.6
US stock/bond mutual funds	155.1		—		—		155.1
Total	$	159.7	$	—	$	—	$	159.7
As of September 30, 2015
Cash and cash equivalents	$	1.6	$	—	$	—	$	1.6
US stock/bond mutual funds	115.5		26.5		—		142.0
Total	$	117.1	$	26.5	$	—	$	143.6

Cash and cash equivalents include money market mutual funds valued based on quoted market prices. Fair values of derivative instruments are calculated by investment managers who use valuation models that incorporate observable market inputs. Debt securities are valued based on broker/dealer quotations or by using observable market inputs. The stock and bond mutual funds are valued at the quoted market price of the identical securities.

Alagasco

The table below categorizes the fair value measurements of Alagasco’s pension plan assets:

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	0.4	$	—	$	—	$	0.4
Stock/bond mutual funds	59.0		11.9		—		70.9
Debt Securities
US bond mutual funds	23.0		5.7		—		28.7
Total	$	82.4	$	17.6	$	—	$	100.0
As of September 30, 2015
Cash and cash equivalents	$	11.6	$	0.2	$	—	$	11.8
Stock/bond mutual fund	46.4		7.0		9.5		62.9
Debt Securities
US bond mutual funds	—		9.3		—		9.3
US government	—		21.0		—		21.0
International	—		4.0		—		4.0
Derivative instruments (b)	—		—		—		—
Total	$	58.0	$	41.5	$	9.5	$	109.0

The table below categorizes the fair value measurements of Alagasco’s postretirement plan assets:

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
US stock/bond mutual fund	$	—	$	68.5	$	—	$	68.5
International fund	—		14.3		—		14.3
Total	$	—	$	82.8	$	—	$	82.8
As of September 30, 2015
US stock/bond mutual fund	—		66.3		—		66.3
International fund	—		13.4		—		13.4
Total	$	—	$	79.7	$	—	$	79.7

Cash and cash equivalents include money market mutual funds valued based on quoted market prices. Fair values of derivative instruments are calculated by investment managers who use valuation models that incorporate observable market inputs. Debt securities are valued based on broker/dealer quotations or by using observable market inputs. The stock and bond mutual funds are valued at the quoted market price of the identical securities.

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INFORMATION BY OPERATING SEGMENT

12 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

INFORMATION BY OPERATING SEGMENT

INFORMATION BY OPERATING SEGMENT

Spire

The Company has two reportable segments: Gas Utility and Gas Marketing. The Gas Utility segment is the aggregation of the regulated operations of the Utilities. The Gas Marketing segment includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas and related activities, and LER Storage Services, Inc., which utilizes natural gas storage contracts for providing natural gas sales. Other includes:

• unallocated corporate items, including certain debt and associated interest costs,

• Laclede Pipeline Company, a subsidiary of Spire which operates a propane pipeline under Federal Energy Regulatory Commission (FERC) jurisdiction,

• Spire STL Pipeline, a subsidiary of Spire planning construction of a 70-mile FERC-regulated pipeline to deliver natural gas into eastern Missouri, and

• Spire’s subsidiaries that are engaged in compression of natural gas and risk management, among other activities. All subsidiaries are wholly owned.

Accounting policies are described in Note 1, Summary of Significant Accounting Policies. Intersegment transactions include sales of natural gas from LER to Laclede Gas, sales of natural gas from Laclede Gas to LER, risk management services provided by Laclede Insurance Risk Services, Inc. to Laclede Gas, propane transportation services provided by Laclede Pipeline Company to Laclede Gas, and propane storage services provided by Laclede Gas to Laclede Pipeline Company.

Management evaluates the performance of the operating segments based on the computation of net economic earnings. Net economic earnings exclude from reported net income the after-tax impacts of net unrealized gains and losses and other timing differences associated with energy-related transactions. Net economic earnings also exclude the after-tax impacts related to acquisition, divestiture, and restructuring activities.

	Gas Utility		Gas Marketing			Other				Eliminations			Consolidated
2016
Revenues from external customers	$	1,457.2	$	78.5		$	1.6			$	—		$	1,537.3
Intersegment revenues	2.2		—			3.2				(5.4		)	—
Total Operating Revenues	1,459.4		78.5			4.8				(5.4		)	1,537.3
Operating Expenses
Gas Utility
Natural and propane gas	539.7		—			—				(47.5		)	492.2
Other operation and maintenance	379.3		—			—				(1.8		)	377.5
Depreciation and amortization	136.9		—			—				—			136.9
Taxes, other than income taxes	125.2		—			—				—			125.2
Total Gas Utility Operating Expenses	1,181.1		—			—				(49.3		)	1,131.8
Gas Marketing and Other	—		66.7		(a)	12.6			(b)	43.9			123.2
Total Operating Expenses	1,181.1		66.7			12.6				(5.4		)	1,255.0
Operating Income (Loss)	278.3		11.8			(7.8		)		—			282.3
Net Economic Earnings (Loss)	160.3		6.4			(17.6		)		—			149.1
Capital Expenditures	291.7		—			1.6				—			293.3

	Gas Utility		Gas Marketing			Other				Eliminations			Consolidated
2015
Revenues from external customers	$	1,891.8	$	82.9		$	1.7			$	—		$	1,976.4
Intersegment revenues	4.0		70.5			2.0				(76.5		)	—
Total Operating Revenues	1,895.8		153.4			3.7				(76.5		)	1,976.4
Operating Expenses
Gas Utility
Natural and propane gas	957.6		—			—				(75.2		)	882.4
Other operation and maintenance	391.6		—			—				(1.0		)	390.6
Depreciation and amortization	129.9		—			—				—			129.9
Taxes, other than income taxes	142.1		—			—				—			142.1
Total Gas Utility Operating Expenses	1,621.2		—			—				(76.2		)	1,545.0
Gas Marketing and Other	—		146.6		(a)	12.6			(b)	(0.3		)	158.9
Total Operating Expenses	1,621.2		146.6			12.6				(76.5		)	1,703.9
Operating Income (Loss)	274.6		6.8			(8.9		)		—			272.5
Net Economic Earnings (Loss)	150.4		4.2			(16.3		)		—			138.3
Capital Expenditures	284.4		—			5.4				—			289.8

	Gas Utility		Gas Marketing			Other				Eliminations			Consolidated
2014
Revenues from external customers	$	1,462.6	$	162.6		$	2.0			$	—		$	1,627.2
Intersegment revenues	5.2		84.0			1.8				(91.0		)	—
Total Operating Revenues	1,467.8		246.6			3.8				(91.0		)	1,627.2
Operating Expenses
Gas Utility
Natural and propane gas	821.8		—			—				(90.1		)	731.7
Other operation and maintenance	288.7		—			—				(0.9		)	287.8
Depreciation and amortization	82.4		—			—				—			82.4
Taxes, other than income taxes	112.0		—			—				—			112.0
Total Gas Utility Operating Expenses	1,304.9		—			—				(91.0		)	1,213.9
Gas Marketing and Other	—		226.4		(a)	20.5			(b)	—			246.9
Total Operating Expenses	1,304.9		226.4			20.5				(91.0		)	1,460.8
Operating Income (Loss)	162.9		20.2			(16.7		)		—			166.4
Net Economic Earnings (Loss)	92.8		10.2			(2.9		)		—			100.1
Capital Expenditures	168.6		—			2.4				—			171.0

(a) Depreciation and amortization for Gas Marketing are included in Gas Marketing Expenses on the Consolidated Statements of Income ($0.1 for 2016, $0.3 for 2015, and $0.4 for 2014).

(b) Depreciation, amortization, and accretion for Other are included in the Other Operating Expenses on the Consolidated Statements of Income ($0.5 for 2016, $0.6 for 2015, and $0.5 for 2014).

Total Assets at End of Year	2016			2015			2014
Gas Utility	$	5,191.9		$	4,686.2		$	4,520.0
Gas Marketing	205.0			160.6			156.7
Other	1,842.4			1,560.2			1,575.7
Eliminations	(1,161.9		)	(1,116.8		)	(1,178.4		)
Total Assets	$	6,077.4		$	5,290.2		$	5,074.0

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings	2016			2015			2014
Net Income (GAAP)	$	144.2		$	136.9		$	84.6
Unrealized gain on energy-related derivatives	(0.1		)	(2.8		)	(1.6		)
Lower of cost or market inventory adjustments	0.2			0.4			(1.1		)
Realized (gain) loss on economic hedges prior      to the sale of the physical commodity	(1.6		)	2.4			(0.4		)
Acquisition, divestiture and restructuring activities	9.2			9.8			29.5
Gain on sale of property	—			(7.6		)	—
Income tax effect of adjustments	(2.8		)	(0.8		)	(10.9		)
Net Economic Earnings	$	149.1		$	138.3		$	100.1

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REGULATORY MATTERS

12 Months Ended

Sep. 30, 2016

Regulated Operations [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

The Utilities account for regulated operations in accordance with ASC Topic 980, “Regulated Operations.” This Topic sets forth the application of GAAP for those companies whose rates are established by or are subject to approval by an independent third-party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).

The following regulatory assets and regulatory liabilities were reflected in the Balance Sheets as of September 30, 2016 and 2015. Unamortized Purchased Gas Adjustments are also included below, which are reported separately in the current assets and liabilities sections of each balance sheet.

	Spire				Laclede Gas				Alagasco
	2016		2015		2016		2015		2016		2015
Regulatory Assets:
Current:
Pension and postretirement benefit costs	$	27.0	$	22.0	$	20.2	$	15.5	$	6.8	$	6.5
Unamortized purchased gas adjustments	49.7		12.9		43.1		12.9		5.6		—
Other	17.2		5.6		3.7		0.7		8.1		4.9
Total Current Regulatory Assets	93.9		40.5		67.0		29.1		20.5		11.4
Noncurrent:
Future income taxes due from customers	151.3		134.5		151.3		134.5		—		—
Pension and postretirement benefit costs	487.9		448.7		375.7		368.0		98.9		80.7
Cost of removal	130.6		78.9		—		—		130.6		78.9
Purchased gas costs	12.6		24.1		12.6		24.1		—		—
Energy efficiency	25.5		22.3		25.5		22.3		—		—
Other	30.1		29.1		24.7		24.7		1.2		4.0
Total Noncurrent Regulatory Assets	838.0		737.6		589.8		573.6		230.7		163.6
Total Regulatory Assets	$	931.9	$	778.1	$	656.8	$	602.7	$	251.2	$	175.0
Regulatory Liabilities:
Current:
RSE adjustment	$	7.5	$	12.2	$	—	$	—	$	5.0	$	12.2
Unbilled service margin	5.9		6.4		—		—		5.9		6.4
Refundable negative salvage	9.3		10.8		—		—		9.3		10.8
Unamortized purchased gas adjustments	1.7		28.2		—		—		—		28.2
Other	6.2		3.0		1.3		0.6		2.5		2.4
Total Current Regulatory Liabilities	30.6		60.6		1.3		0.6		22.7		60.0
Noncurrent:
Postretirement liabilities	28.9		28.9		—		—		28.9		28.9
Refundable negative salvage	9.4		16.2		—		—		9.4		16.2
Accrued cost of removal	74.8		58.7		55.1		58.7		—		—
Other	17.6		15.5		12.2		11.9		3.4		3.6
Total Noncurrent Regulatory Liabilities	130.7		119.3		67.3		70.6		41.7		48.7
Total Regulatory Liabilities	$	161.3	$	179.9	$	68.6	$	71.2	$	64.4	$	108.7

Regulatory assets are expected to be recovered in rates charged to customers.

A portion of the Company’s regulatory assets are not earning a return and are shown in the schedule below:

	Spire				Laclede Gas
	2016		2015		2016		2015
Future income taxes due from customers	$	151.3	$	134.5	$	151.3	$	134.5
Pension and postretirement benefit costs	240.6		223.7		240.6		223.7
Compensated absences	—		—		—		—
Other	12.9		14.2		12.9		14.2
Total Regulatory Assets Not Earning a Return	$	404.8	$	372.4	$	404.8	$	372.4

All of Alagasco’s regulatory assets currently earn a return.

These regulatory assets are expected to be recovered from customers in future rates. Excluding deferred income taxes and purchased gas adjustment items, as of September 30, 2016 and 2015, approximately $404.8 and $372.4, respectively, of regulatory assets were not earning a rate of return. The Company expects these items to be recovered over a period not to exceed 15 years consistent with precedent set by the MoPSC. The portion of the regulatory asset related to pensions and other postemployment benefits that relates to unfunded differences between the projected benefit obligation and plan assets also does not earn a rate of return.

Laclede Gas

On November 12, 2015, the MoPSC approved an incremental Infrastructure System Replacement Surcharge (ISRS) amount of $4.4 for Laclede Gas’ eastern Missouri service territory and $1.9 for MGE, effective December 1, 2015, bringing total annualized ISRS revenue to $19.6 for Laclede Gas’ eastern Missouri service territory and $6.7 for MGE’s service territory. On January 15, 2016, the Missouri Office of the Public Counsel (OPC) filed an appeal to Missouri’s Western District Court of Appeals of the MoPSC’s decision permitting Laclede Gas to update its ISRS applications during the pendency of the case. On September 27, 2016, the Western District affirmed the report and order of the MoPSC.

On May 19, 2016, the MoPSC approved an incremental ISRS amount of $5.4 for Laclede Gas’ eastern Missouri service territory and $3.6 for MGE, effective May 31, 2016, bringing total annualized ISRS revenue to $25.0 for Laclede Gas’ eastern Missouri service territory and $10.3 for MGE’s service territory. On June 30, 2016, the OPC again filed an appeal to Missouri’s Western District Court of Appeals of the MoPSC’s decision permitting Laclede Gas to update its ISRS applications during the pendency of the case. Laclede Gas believes the MoPSC’s decision was lawful and reasonable, and believes the updating process will again be upheld by the Western District and intends to vigorously oppose the appeal.

On September 30, 2016 Laclede Gas filed to increase its ISRS revenues by $5.0 for Laclede Gas’ eastern Missouri service territory and $3.4 for MGE, related to ISRS investments from March 2016 through October 2016. The MoPSC suspended the tariff until January 28, 2017 and directed the MoPSC Staff (Staff) to file a recommendation no later than November 29, 2016.

Laclede Gas previously had authority from the MoPSC to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in capital, and enter into capital lease agreements, all for a total of up to $518.0. This authority was scheduled to expire June 30, 2015. On April 15, 2015, Laclede Gas applied to the MoPSC for a new financing authorization in the amount of $550.0, and on June 24, 2015, the MoPSC granted an extension of the current authorization until the pending application was resolved. On February 10, 2016, the MoPSC issued an order, by a 3-2 vote, authorizing Laclede financing authority for $300.0 for financings placed any time before September 30, 2018. Laclede Gas filed an application for rehearing, which was denied on March 9, 2016. On March 31, 2016, Laclede Gas filed an appeal with the Western District Court of Appeals concerning this matter. On July 20, 2016, Laclede Gas filed its initial brief before the Court. The MoPSC filed its reply brief on September 19, 2016. Laclede Gas filed its final brief on October 4, 2016. Oral arguments are scheduled for November 17, 2016. Laclede Gas issued no securities under this authorization since the decision and $300.0 remained available for issuance as of November 11, 2016.

Alagasco

Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s current RSE order has a term extending beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control, the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco’s allowed range of return on average common equity is 10.5% to 10.95% with an adjusting point of 10.8%. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4% of prior-year revenues. There was no RSE reduction for the January 31, 2016 quarterly point of test. Related to the April 30, 2016 quarterly point of test, Alagasco recorded a $5.8 RSE reduction to operating revenues, which the APSC directed, by order dated June 20, 2016, be applied to the Gas Supply Adjustment (GSA) balance. The RSE reduction for the July 31, 2016 quarterly point of test was $4.8. As of September 30, 2016, Alagasco recorded a $2.7 RSE reduction to operating revenues to bring the expected rate of return on average common equity at the end of the year to within the allowed range of return. The quarterly point of test reductions from rate year 2016 went into effect October 1, 2016 for $4.8 and will go into effect December 1, 2016 for $2.7. On October 26, 2016, as part of their annual update for RSE, Alagasco filed a $1.3 reduction for rate year 2017, which is subject to review by APSC Staff and becomes effective December 1, 2016 unless otherwise ordered by the APSC.

The inflation-based Cost Control Mechanism (CCM), established by the APSC, allows for annual increases to operations and maintenance (O&M) expense. The CCM range is Alagasco’s 2007 actual rate year O&M expense (Base Year) inflation-adjusted using the June Consumer Price Index For All Urban Consumers each rate year plus or minus 1.75% (Index Range). If rate year O&M expense falls within the Index Range, no adjustment is required. If rate year O&M expense exceeds the Index Range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent that rate year O&M is less than the Index Range, Alagasco benefits by one-half of the difference through future rate adjustments. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. A CCM benefit to the company for such cost saving of $7.8 related to 2016 will be reflected in rates effective December 1, 2016. The CCM benefit was $4.7 for 2015.

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Commitments

The Company and the Utilities have entered into contracts with various counterparties, expiring on dates through2031, for the storage, transportation, and supply of natural gas. Minimum payments required by the Company under the contracts in place at September 30, 2016 are estimated at $1,647.8. Minimum payments required for Laclede Gas and Alagasco under the contracts are estimated at $1,227.6 and $352.7, respectively. Additional contracts are generally entered into prior to or during the heating season of November through April. The Missouri Utilities recover their costs from customers in accordance with their PGA clause and Alagasco recovers its cost through its GSA rider.

Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $352.7 through August 2020. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 93 Bcf through August 2020.

Laclede Pipeline Company (Pipeline), a wholly owned subsidiary of Spire, is providing liquid propane transportation service to Laclede Gas pursuant to an approved FERC tariff and a contractual arrangement between Pipeline and Laclede Gas. In accordance with the terms of that agreement, Laclede Gas is obligated to pay Pipeline approximately $1.0 annually, at current rates. The agreement renews at the end of each contract year, unless terminated by either party upon provision of at least six months’ notice.

Leases and Guarantees

Aggregate rental expense and annual minimum rental commitments under all leases having an initial or remaining non-cancelable term of more than one year are shown below:

	Aggregate Rental Expense						Minimum Rental Commitments
	2016		2015		2014		2017		2018		2019		2020		2021		Later		Total
Spire	$	11.9	$	14.1	$	6.7	$	10.5	$	7.5	$	7.3	$	6.2	$	6.0	$	53.4	$	90.9
Laclede Gas	4.3		7.6		6.3		2.5		0.9		0.9		0.3		0.1		—		4.7
Alagasco	3.7		4.0		2.0		3.9		2.5		2.5		2.1		2.1		4.9		18.0

The lease agreement covering the primary office space of Spire and its Missouri Utilities extends through February 2035. Laclede Gas has entered into various operating lease agreements for the rental of vehicles and power operated equipment. The lease agreement covering the primary office space of Alagasco extends through February 2018. Alagasco has an operating lease for additional office space that extends to January 31, 2024. Alagasco has subleased all of this office space to Energen pursuant to a sublease that expires on December 31, 2019 with an option to extend through January 31, 2024. Amounts in the table above have not been reduced for sublease rentals. For Alagasco and Spire, sublease rentals were $2.1, $2.1, and $0.2 for fiscal years 2016, 2015, and 2014, and minimum future rentals to be received in fiscal years 2017, 2018, 2019, and 2020 are $2.1, $2.1, $2.1, and $0.5, respectively. Laclede Gas, Alagasco and LER have other relatively minor rental arrangements that provide for minimum rental payments.

A consolidated subsidiary is a general partner in an unconsolidated partnership that invests in real estate partnerships. The subsidiary and third parties are jointly and severally liable for the payment of mortgage loans in the aggregate outstanding amount of approximately $1.4 incurred in connection with various real estate ventures. Spire has no reason to believe that the other principal liable parties will not be able to meet their proportionate share of these obligations. Spire further believes that the asset values of the real estate properties are sufficient to support these mortgage loans.

Contingencies

The Company and Utilities account for environmental liabilities and other contingencies in accordance with accounting standards under the loss contingency guidance of ASC Topic 450, “Contingencies,” when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated.

The Company and the Utilities own and operate natural gas distribution, transmission, and storage facilities, the operations of which are subject to various environmental laws, regulations, and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company’s or Utilities’ financial position and results of operations. As environmental laws, regulations, and their interpretations change, the Company or the Utilities may incur additional environmental liabilities that may result in additional costs.

In addition to matters noted below, the Company, Laclede Gas, and Alagasco are involved in other litigation, claims, and investigations arising in the normal course of business. Management, after discussion with counsel, believes that the final outcome will not have a material effect on the consolidated statements of income, balance sheets, and statements of cash flows of the Company, Laclede Gas, or Alagasco. However, there is uncertainty in the valuation of pending claims and prediction of litigation results.

In the natural gas industry, many gas distribution companies have incurred environmental liabilities associated with sites they or their predecessor companies formerly owned or operated where manufactured gas operations took place. The Utilities each have former manufactured gas plant (MGP) operations in their respective service territories.

Laclede Gas

Laclede Gas has identified three former MGP sites in eastern Missouri where costs have been incurred and claims have been asserted: one in Shrewsbury, Missouri and two in the City of St. Louis, Missouri. Laclede Gas has enrolled the two sites in the City of St. Louis in the Missouri Department of Natural Resources Brownfields/Voluntary Cleanup Program (BVCP). In Laclede Gas’ western service area, MGE has enrolled all of its owned former MGP sites in the BVCP.

With regard to the former MGP site located in Shrewsbury, Missouri, Laclede Gas and state and federal environmental regulators agreed upon certain remedial actions to a portion of the site in a 1999 Administrative Order on Consent (AOC), which actions have been completed. On September 22, 2008, Environmental Protection Agency (EPA) Region VII issued a letter of Termination and Satisfaction terminating the AOC. However, if after this termination of the AOC, regulators require additional remedial actions, or additional claims are asserted, Laclede Gas may incur additional costs.

In conjunction with redevelopment of one of the sites located in the City of St. Louis, Laclede Gas and another former owner of the site entered into an agreement (Remediation Agreement) with the City development agencies, the developer, and an environmental consultant that obligates one of the City agencies and the environmental consultant to remediate the site and obtain a No Further Action letter from the Missouri Department of Natural Resources (MDNR). The Remediation Agreement also provides for a release of Laclede Gas and the other former site owner from certain liabilities related to the past and current environmental condition of the site and requires the developer and the environmental consultant to maintain certain insurance coverage, including remediation cost containment, premises pollution liability, and professional liability. The operative provisions of the Remediation Agreement were triggered on December 20, 2010, on which date Laclede Gas and the other former site owner, as full consideration under the Remediation Agreement, paid a small percentage of the cost of remediation of the site. The amount paid by Laclede Gas did not materially impact the financial condition, results of operations, or cash flows of the Company.

Laclede Gas has not owned the other site located in the City of St. Louis for many years. In a letter dated June 29, 2011, the Attorney General for the state of Missouri informed Laclede Gas that the MDNR had completed an investigation of the site. The Attorney General requested that Laclede Gas participate in the follow up investigations of the site. In a letter dated January 10, 2012, Laclede Gas stated that it would participate in future environmental response activities at the site in conjunction with other potentially responsible parties (PRPs) that are willing to contribute to such efforts in a meaningful and equitable fashion. Accordingly, Laclede Gas entered into a cost sharing agreement for remedial investigation with other PRPs. Pending MDNR approval which has not occurred as of the date of filing, the remedial investigation of the site will begin. 

Laclede Gas has notified its insurers that it seeks reimbursement for costs incurred in the past and future potential liabilities associated with the MGP sites. While some of the insurers have denied coverage and reserved their rights, Laclede Gas continues to discuss potential reimbursements with them.

On March 10, 2015, Laclede Gas received a Section 104(e) information request from EPA Region VII regarding the former Thompson Chemical/Superior Solvents site in St. Louis, Missouri. In turn, Laclede Gas issued a Freedom of Information Act (FOIA) request to the EPA on April 3, 2015, in an effort to identify the basis of the inquiry. The FOIA response from the EPA was received on July 15, 2015 and a response was provided to the EPA on August 15, 2015.

MGE has seven owned MGP sites enrolled in the BVCP, including Joplin MGP #1, St. Joseph MGP #1, Kansas City Coal Gas Station B, Kansas City Station A Railroad area, Kansas City Coal Gas Station A North, Kansas City Coal Gas Station A South, and Independence MGP #2. Source removal has been conducted at all of the owned sites since 2003 with the exception of Joplin. On September 15, 2016, a request was made with the MDNR for a restrictive covenant use limitation with respect to Joplin. Remediation efforts at the seven sites are at various stages of completion, ranging from groundwater monitoring and sampling following source removal activities to the aforementioned request in respect to Joplin. As part of its participation in the BVCP, MGE communicates regularly with the MDNR with respect to its remediation efforts and monitoring activities at these sites. On May 11, 2015, MDNR approved the next phase of investigation at the Kansas City Station A North and Railroad area.

To date, costs incurred for all Missouri Utilities’ MGP sites for investigation, remediation and monitoring these sites have not been material. However, the amount of costs relative to future remedial actions at these and other sites is unknown and may be material. The actual future costs that Laclede Gas may incur could be materially higher or lower depending upon several factors, including whether remediation actions will be required, final selection and regulatory approval of any remedial actions, changing technologies and government regulations, the ultimate ability of other potential responsible parties to pay, the successful completion of remediation efforts required by the Remediation Agreement described above, and any insurance recoveries.

In 2013, Laclede Gas retained an outside consultant to conduct probabilistic cost modeling of 19 former MGP sites owned or operated by Laclede Gas in eastern Missouri or MGE in western Missouri. The purpose of this analysis was to develop an estimated range of probabilistic future liability for each site. That analysis, completed in August 2014, provided a range of demonstrated possible future expenditures to investigate, monitor and remediate all 19 MGP sites. Laclede Gas has recorded its best estimate of the probable expenditures that relate to these matters. The amount is not material.

Costs associated with environmental remediation activities are accrued when such costs are probable and reasonably estimable. To the extent such costs (less any amounts received from insurance proceeds or as contributions from other PRP’s), are incurred prior to a rate case, Laclede Gas would request from the MoPSC authority to defer such costs and collect them in the next rate case. Laclede Gas and the Company do not expect potential liabilities that may arise from remediating these sites to have a material impact on their future financial condition or results of operations.

Alagasco

Alagasco is in the chain of title of nine former MGP sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. As of September 30, 2016, Alagasco does not foresee a probable or reasonably estimable loss associated with these nine sites. Alagasco and the Company do not expect potential liabilities that may arise from remediating these sites to have a material impact on their future financial conditions or results of operations.

In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of the Comprehensive Environment Response, Compensation, and Liability Act (CERCLA) relating to the 35th Avenue Superfund Site located in North Birmingham, Jefferson County, Alabama. Alagasco was identified as a PRP under CERCLA for the cleanup of the site or costs the EPA incurs in cleaning up the site. At this point, Alagasco has not been provided information that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and vigorously denies its inclusion as a PRP.

On December 17, 2013, an incident occurred at a Housing Authority apartment complex in Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. Alagasco cooperated with the National Transportation Safety Board (NTSB) which investigated the incident. The NTSB report of findings was issued on March 30, 2016 and no safety recommendations, fines, or penalties were contained therein. Alagasco has been named as a defendant in several lawsuits arising from the incident, and additional lawsuits and claims may be filed against Alagasco.

Mobile Gas

Mobile Gas is in the chain of title of one former MGP site which it still owns in Mobile, Alabama. On September 15, 2010, Mobile Gas filed an application to enroll the site into the Alabama Department of Environmental Management’s (ADEM) Voluntary Cleanup Program (VCP). This application was accepted by ADEM on November 16, 2010. Investigation and testing have been completed. As of September 30, 2016, Mobile Gas has an approved remediation plan from ADEM which is currently in the process of being executed. Mobile Gas and the Company do not expect potential liabilities that may arise from remediating this site to have a material impact on their future financial conditions or results of operations.

Since April 2012, a total of 14 lawsuits have been filed against Mobile Gas in Mobile County Circuit Court alleging that in the first half of 2008, Mobile Gas spilled tert-butyl mercaptan, an odorant added to natural gas for safety reasons, in Eight Mile, Alabama. Eleven of the lawsuits have been settled. The remaining three lawsuits, which include approximately 270 individual plaintiffs, allege nuisance, fraud and negligence causes of actions, and seek unspecified compensatory and punitive damages. A claim has been made against the insurance carriers for Mobile Gas requesting reimbursement for costs accrued in respect to this spill. Mobile Gas and the Company do not expect potential liabilities that may arise from these lawsuits to have a material impact on their future financial conditions or results of operations.

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INTERIM FINANCIAL INFORMATION (UNAUDITED)

12 Months Ended

Sep. 30, 2016

Quarterly Financial Information Disclosure [Abstract]

INTERIM FINANCIAL INFORMATION (UNAUDITED)

INTERIM FINANCIAL INFORMATION (UNAUDITED)

Spire

In the opinion of Spire, the quarterly information presented below for fiscal years 2016 and 2015 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in consolidated operations reported on a quarterly basis primarily reflect the seasonal nature of the business of the Utilities.

Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2016
Total Operating Revenues	$	399.4	$	609.3	$	249.3	$	279.3
Operating Income (Loss)	87.0		167.7		35.3		(7.7		)
Net Income (Loss)	46.9		100.8		10.7		(14.2		)
Basic Earnings (Loss) Per Share of Common Stock	$	1.08	$	2.32	$	0.24	$	(0.31	)
Diluted Earnings (Loss) Per Share of Common Stock	$	1.08	$	2.31	$	0.24	$	(0.31	)
Fiscal Year 2015
Total Operating Revenues	$	619.6	$	877.4	$	275.2	$	204.2
Operating Income (Loss)	87.3		157.7		36.0		(8.5		)
Net Income (Loss)	47.1		94.4		14.1		(18.7		)
Basic Earnings (Loss) Per Share of Common Stock	$	1.09	$	2.18	$	0.32	$	(0.43	)
Diluted Earnings (Loss) Per Share of Common Stock	$	1.09	$	2.18	$	0.32	$	(0.43	)

Laclede Gas

In the opinion of Laclede Gas, the quarterly information presented below for fiscal years 2016 and 2015 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in operations reported on a quarterly basis primarily reflect their seasonal nature.

Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2016
Total Operating Revenues	$	317.2	$	446.7	$	179.3	$	144.3
Operating Income	65.1		87.0		29.4		5.4
Net Income (Loss)	39.4		54.3		13.9		(1.7		)
Fiscal Year 2015
Total Operating Revenues	$	462.4	$	615.7	$	187.5	$	151.0
Operating Income	64.8		80.6		34.5		5.5
Net Income (Loss)	39.0		49.9		20.0		(3.6		)

Alagasco

In the opinion of Alagasco, the quarterly information presented below for fiscal years 2016 and 2015 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in operations reported on a quarterly basis primarily reflect their seasonal nature.

Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2016
Total Operating Revenues	$	82.3	$	166.0	$	74.0	$	46.2
Operating Income (Loss)	18.9		80.4		9.3		(17.1		)
Net Income (Loss)	9.9		48.1		4.0		(8.8		)
Fiscal Year 2015
Total Operating Revenues	$	120.0	$	233.3	$	73.7	$	52.2
Operating Income (Loss)	20.4		77.4		3.9		(12.5		)
Net Income (Loss)	10.6		46.3		0.7		(9.6		)

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

BASIS OF PRESENTATION

BASIS OF PRESENTATION –These notes are an integral part of the accompanying audited financial statements of Spire Inc. (Spire or the Company), as well as Laclede Gas Company (Laclede Gas or the Missouri Utilities) and Alabama Gas Corporation (Alagasco). Laclede Gas, which includes the operations of Missouri Gas Energy (MGE), and Alagasco are wholly owned subsidiaries of the Company. Laclede Gas, Alagasco and the subsidiaries of EnergySouth, Inc. (EnergySouth) are collectively referred to as the Utilities. The subsidiaries of EnergySouth are Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas and Oil Company (Willmut Gas). The accompanying audited financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

The consolidated financial position, results of operations, and cash flows of Spire are primarily derived from the financial position, results of operations, and cash flows of the Utilities. In compliance with GAAP, transactions between Laclede Gas and Alagasco and their affiliates, as well as intercompany balances on their balance sheets, have not been eliminated from their separate financial statements. The Company’s September 12, 2016 acquisition of EnergySouth and the August 31, 2014 acquisition of Alagasco are included in the results of operations since their acquisition dates and impact the comparability of the financial statement periods presented for the Company. For a further discussion of the acquisitions, see Note 2, Acquisitions. The Utilities are regulated natural gas distribution utilities. Due to the seasonal nature of the Utilities, the earnings of Spire, Laclede Gas and Alagasco are typically concentrated during the heating season of November through April each fiscal year.

Effective September 2, 2014, Alagasco amended its bylaws to change Alagasco’s fiscal year from beginning January 1 and ending on December 31, to beginning October 1 and ending September 30. As a result, the financial statements covering the nine-month period from January 1, 2014 through September 30, 2014 (the “transition period”) were included in Alagasco’s transition report on Form 10-K/T for such period and are presented in the financial statements and notes herein.

USE OF ESTIMATES

USE OF ESTIMATES – The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

SYSTEM OF ACCOUNTS

SYSTEM OF ACCOUNTS – The accounts of the Utilities are maintained in accordance with the Uniform System of Accounts prescribed by the applicable state public service commissions, which systems substantially conform to that prescribed by the Federal Energy Regulatory Commission (FERC).

UTILITY PLANT, DEPRECIATION AND AMORTIZATION

UTILITY PLANT, DEPRECIATION AND AMORTIZATION – Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overheads, and an allowance for funds used during construction. The costs of units of property retired, replaced, or renewed are removed from utility plant and are charged to accumulated depreciation. Maintenance and repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expenses.

For Laclede Gas, utility plant is depreciated on a straight-line basis at rates based on estimated service lives of the various classes of property. In fiscal years 2016, 2015 and 2014, annual depreciation and amortization expense averaged 3.0% of the original cost of depreciable and amortizable property.

Laclede Gas’ capital expenditures were $197.8, $198.6 and $163.0 for fiscal years 2016, 2015, and 2014, respectively. Additionally, Laclede Gas had recorded accruals for capital expenditures totaling $14.8 at September 30, 2016, $9.6 at September 30, 2015, and $3.0 at September 30, 2014.

For Alagasco, depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of utility property at rates approved by the Alabama Public Service Commission (APSC).

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS – Spire, Laclede Gas, and Alagasco record legal obligations associated with the retirement of long-lived assets in the period in which the obligations are incurred, if sufficient information exists to reasonably estimate the fair value of the obligations. Obligations are recorded as both a cost of the related long-lived asset and as a corresponding liability. Subsequently, the asset retirement costs are depreciated over the life of the asset and the asset retirement obligations are accreted to the expected settlement amounts. The Company, Laclede Gas and Alagasco record asset retirement obligations associated with certain safety requirements to purge and seal gas distribution mains upon retirement, the plugging and abandonment of storage wells and other storage facilities, specific service line obligations, and certain removal and disposal obligations related to components of Laclede Gas’, Alagasco’s and Mobile Gas’ distribution systems and general plant. Asset retirement obligations recorded by Spire’s other subsidiaries are not material. As authorized by the Missouri Public Service Commission (MoPSC) and APSC, Laclede Gas, Alagasco and Mobile Gas accrue future asset removal costs associated with their property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities or assets. When those utilities retire depreciable utility plant and equipment, they charge the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities or assets. The difference between removal costs recognized in depreciation rates and the accretion expense and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes. Accordingly, these differences are deferred as regulatory liabilities or assets. In the rate setting process, the regulatory liability or asset is excluded from the rate base upon which those utilities have the opportunity to earn their allowed rates of return. The costs associated with asset retirement obligations of Laclede Gas, Alagasco and Mobile Gas are either currently being recovered in rates or are probable of recovery in future rates.

REGULATED OPERATIONS

REGULATED OPERATIONS – The Utilities account for their regulated operations in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.” This Topic sets forth the application of GAAP for those companies whose rates are established by or are subject to approval by an independent third-party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. In addition, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities). Management believes that the current regulatory environment supports the continued use of these regulatory accounting principles and that all regulatory assets and regulatory liabilities are recoverable or refundable through the regulatory process. See additional discussion on regulated operations in Note 15, Regulatory Matters.

As discussed below for Laclede Gas and Alagasco, the Purchased Gas Adjustment (PGA) clauses and Gas Supply Adjustment (GSA) riders allow the Utilities to pass through to customers the cost of purchased gas supplies. Regulatory assets and liabilities related to the PGA clauses and the GSA rider are both labeled Unamortized Purchased Gas Adjustments herein.

Laclede Gas

As authorized by the MoPSC, the PGA clause allows Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. To better match customer billings with market natural gas prices, Laclede Gas is allowed to file to modify, on a periodic basis, the level of gas costs in its PGA. Certain provisions of the PGA clause are included below:

• Laclede Gas has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. The MoPSC clarified that costs, cost reductions, and carrying costs associated with the Utility’s use of natural gas derivative instruments are gas costs recoverable through the PGA mechanism.

• The tariffs allow Laclede Gas flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months.

• Laclede Gas is authorized to apply carrying costs to all over- or under-recoveries of gas costs, including costs and cost reductions associated with the use of derivative instruments, including cash payments for margin deposits. Laclede Gas’ eastern Missouri service territory is also authorized to recover gas inventory carrying costs through its PGA rates to recover costs it incurs to finance its investment in gas supplies that are purchased during the storage injection season for sale during the heating season.

• The MoPSC approved a plan applicable to Laclede Gas’ gas supply commodity costs under which it retains a portion of cost savings associated with the acquisition of natural gas below an established benchmark level. This gas supply cost management program allows Laclede Gas to retain 10% of cost savings, up to a maximum of $3.0 annually. Laclede Gas did not record any income under the plan during the three fiscal years reported. Income recorded under the plan, if any, is included in Gas Utility Operating Revenues on the Consolidated Statements of Income and under Operating Revenues on Laclede Gas’ Statements of Income.

Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA clause are reflected as a deferred charge or credit at the end of the fiscal year. These costs include costs and cost reductions associated with the use of derivative instruments and gas inventory carrying costs, amounts due to or from customers related to operation of the gas supply cost management program, refunds received from the Company’s suppliers in connection with gas supply, transportation, and storage services, and carrying costs on such over- or under-recoveries. At that time, the balance is classified as a current asset or current liability and recovered from, or credited to, customers over an annual period commencing in November. The balance in the current account is amortized as amounts are reflected in customer billings.

The PGA clause also provides for the treatment of income from off-system sales and capacity release revenues. Pre-tax income from off-system sales and capacity release revenues is shared with customers, with an estimated amount assumed in PGA rates. The difference between the actual amount allocated to customers for each fiscal year and the estimated amount assumed in PGA rates is recovered from, or credited to, customers over an annual period commencing in the subsequent November. The customer share of such income is determined in accordance with the following tables, shown for each service territory for which the PGA clauses were approved by the MoPSC.

	Customer Share	Company Share
Eastern Missouri
First $2.0*	100%	—%
Next $2.0	80%	20%
Next $2.0	75%	25%
Amounts exceeding $6.0	70%	30%
* Customer share reverts to 85% and company share reverts to 15% in 2017.
Western Missouri
First $1.2	85%	15%
Next $1.2	80%	20%
Next $1.2	75%	25%
Amounts exceeding $3.6	70%	30%

Alagasco

Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA rider, which is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather-related conditions that may affect customer usage are not included in the temperature adjustment.

NATURAL GAS AND PROPANE GAS

NATURAL GAS AND PROPANE GAS – For Laclede Gas’ eastern Missouri utility, inventory of natural gas in storage is priced on a last in, first out (LIFO) basis and inventory of propane gas in storage is priced on a first in, first out (FIFO) basis. For the rest of the Gas Utility segment, inventory of natural gas in storage is priced on the weighted average cost basis. The replacement cost of Laclede Gas’ natural gas for current use in eastern Missouri at September 30, 2016 and September 30, 2015 was less than the LIFO cost by $11.4 and $20.4, respectively. The carrying value of Laclede Gas’ inventory is not adjusted to the lower of cost or market prices because, pursuant to the Missouri Utilities’ PGA clauses, actual gas costs are recovered in customer rates. Natural gas and propane gas storage inventory in Spire’s other operating segments is recorded at the lower of average cost or market.

BUSINESS COMBINATIONS

BUSINESS COMBINATIONS – The EnergySouth and Alagasco acquisitions are accounted for by Spire using business combination accounting. Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value.

GOODWILL

GOODWILL – Goodwill is measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Spire and Laclede Gas evaluate goodwill for impairment as of July 1st of each year, or more frequently if events and circumstances indicate that goodwill might be impaired. At July 1, 2016, 2015 and 2014, Spire and Laclede Gas each applied a quantitative goodwill evaluation model to their reporting units and concluded goodwill was not impaired because the fair value exceeded the carrying amount.

IMPAIRMENT OF LONG-LIVED ASSETS

IMPAIRMENT OF LONG-LIVED ASSETS – Long-lived assets classified as held and used are evaluated for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, the Company recognizes an impairment charge equal to the amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which the Company determines an asset meets held-for-sale criteria, an impairment charge is recorded to the extent the book value exceeds its fair value less cost to sell.

REVENUE RECOGNITION

REVENUE RECOGNITION – The Utilities read meters and bill customers on monthly cycles. The Missouri Utilities record their gas utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues for Laclede Gas at September 30, 2016 and 2015 were $26.1 and $27.6, respectively.

Alagasco records natural gas distribution revenues in accordance with the tariff established by the APSC. The amount of accrued unbilled revenues, which are not recorded as revenues until billed, for Alagasco at September 30, 2016 and 2015 were $5.9 and $6.4, respectively. All related costs and margins are also deferred.

The subsidiaries of EnergySouth record natural gas revenues in accordance with tariffs established by the APSC and MSPSC. Unbilled revenues are accrued and related costs and margins are also deferred.

Spire’s other subsidiaries, including LER, record revenues when earned, either when the product is delivered or when services are performed.

In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. Certain of its derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815, “Derivatives and Hedging.” Those contracts are accounted for as executory contracts and recorded on an accrual basis. Revenues and expenses from such contracts are recorded using a gross presentation. Contracts not designated as normal purchases or normal sales are recorded as derivatives with changes in fair value recognized in earnings in the periods prior to physical delivery. For additional information on derivative instruments, refer to Note 10, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions are classified as trading activities for financial reporting purposes. Under GAAP, revenues and expenses associated with trading activities are presented on a net basis in Gas Marketing operating revenues (or expenses, if negative) in the Consolidated Statements of Income. This net presentation has no effect on operating income or net income.

INCOME TAXES

INCOME TAXES – Spire and its subsidiaries account for income taxes under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and the respective tax basis and for tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effects on deferred tax assets and liabilities of a change in enacted tax rates is recognized in income or loss for a non-regulated company, and in a regulatory asset or regulatory liability for a regulated company. A valuation allowance is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized.

The Company accounts for uncertain tax positions in accordance with authoritative guidance. The authoritative guidance addresses the determination of whether tax benefits claimed, or expected to be claimed, on a tax return should be recorded in the financial statements. Spire may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the position will be sustained upon examination by the taxing authority, based on the technical merits of the position. Tax-related interest and penalties, if any, are classified as a liability on the balance sheets.

CASH AND CASH EQUIVALENTS

CASH AND CASH EQUIVALENTS – All highly liquid debt instruments purchased with original maturities of three months or less are considered to be cash equivalents. Such instruments are carried at cost, which approximates market value. Outstanding checks on the Company’s and Utilities’ bank accounts in excess of funds on deposit create book overdrafts (which are funded at the time checks are presented for payment) and are classified as Other in the Current Liabilities section of the balance sheets. Changes in book overdrafts are reflected as Operating Activities in the statements of cash flows.

NATURAL GAS RECEIVABLE

ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS – Trade accounts receivable are recorded at the amounts due from customers, including unbilled amounts. Estimates of the collectability of trade accounts receivable are based on historical trends, age of receivables, economic conditions, credit risk of specific customers, and other factors. Accounts receivable are written off against the allowance for doubtful accounts when they are deemed to be uncollectible. Spire’s provision for uncollectible accounts includes the amortization of previously deferred uncollectible expenses for Laclede Gas and Alagasco, as approved by the MoPSC and the APSC.

NATURAL GAS RECEIVABLE – LER enters into natural gas transactions with natural gas pipeline companies known as park and loan arrangements. Under the terms of the arrangements, LER purchases natural gas from a third party and delivers that natural gas to the pipeline company for the right to receive the same quantity of natural gas from the pipeline company at the same location in a future period. These arrangements are accounted for as non-monetary transactions under GAAP and are recorded at the carrying amount. As such, natural gas receivables are reflected on the Consolidated Balance Sheets at cost, which includes related pipeline fees associated with the transactions. In the period that the natural gas is returned to LER, concurrent with the sale of the natural gas to a third party, the related natural gas receivable is expensed in the Consolidated Statements of Income. In conjunction with these transactions, LER usually enters into New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE) natural gas futures, options, and swap contracts or fixed price sales agreements to protect against market changes in future sales prices.

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE – GAAP requires dual presentation of basic and diluted earnings per share (EPS). EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareholders. Certain of the Company’s stock-based compensation awards pay non-forfeitable dividends to the participants during the vesting period and, as such, are deemed participating securities. Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding that are increased for additional shares that would be outstanding if potentially dilutive non-participating securities were converted to common shares, pursuant to the treasury stock method. Shares attributable to equity units, non-participating stock options and time-vested restricted stock/units are excluded from the calculation of diluted earnings per share if the effect would be antidilutive. Shares attributable to non-participating performance-contingent restricted stock awards are only included in the calculation of diluted earnings per share to the extent the underlying performance and/or market conditions are satisfied (a) prior to the end of the reporting period or (b) would be satisfied if the end of the reporting period were the end of the related contingency period and the result would be dilutive.

GROSS RECEIPTS AND SALES TAXES

GROSS RECEIPTS AND SALES TAXES – Gross receipts taxes associated with the Company’s natural gas utility services are imposed on the Company, Laclede Gas, and Alagasco and billed to its customers. The revenue and expense amounts are recorded gross in the “Operating Revenues” and “Taxes, other than income taxes” lines, respectively, in the statements of income.

The following table presents gross receipts taxes recorded:

	2016		2015		2014
Spire	$	75.5	$	97.3	$	77.5
Laclede Gas	57.4		74.5		76.3
Alagasco	17.9		22.6		20.6

Sales taxes imposed on applicable Alagasco and Laclede Gas sales are billed to customers. These amounts are not recorded in the statements of income but are recorded as tax collections payable and included in the Other line of the Current Liabilities section of the balance sheets.

TRANSACTIONS WITH AFFILIATES

TRANSACTIONS WITH AFFILIATES –Transactions between affiliates of the Company have been eliminated from the consolidated financial statements of Spire.

GROUP MEDICAL AND WORKERS' COMPENSATION RESERVES

GROUP MEDICAL AND WORKERS’ COMPENSATION RESERVES – The Company self-insures its group medical and workers’ compensation costs and carries stop-loss coverage in relation to medical claims and workers’ compensation claims. Reserves for amounts incurred but not reported are established based on historical cost levels and lags between occurrences and reporting.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS – Certain assets and liabilities are recognized or disclosed at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.

The levels of the hierarchy are described below:

• Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities.

• Level 2 – Pricing inputs other than quoted prices included within Level 1, which are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data.

• Level 3 – Pricing that is based upon inputs that are generally unobservable that are based on the best information available and reflect management’s assumptions about how market participants would price the asset or liability.

Assessment of the significance of a particular input to the fair value measurements may require judgment and may affect the valuation of the asset or liability and its placement within the fair value hierarchy.

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION – The Company measures stock-based compensation awards at fair value at the date of grant and recognizes the compensation cost of the awards over the requisite service period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates.

NEW ACCOUNTING STANDARDS

NEW ACCOUNTING PRONOUNCEMENTS – In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers. The core principle of the standard is when an entity transfers goods or services to customers it will recognize revenue in an amount that reflects the consideration the entity expects to be entitled to for those goods or services. ASU No. 2014-09 also requires disclosures that will enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which made the guidance in ASU No. 2014-09 effective for fiscal years beginning after December 15, 2017 and interim periods within those years, but companies may choose to adopt it one year earlier. In 2016, the FASB issued related ASU Nos. 2016-08, 2016-10, 2016-11 and 2016-12, which further modified the standards for accounting for revenue. The Company, Laclede Gas and Alagasco are currently assessing the available transition methods and the potential impacts of the updates, which must be adopted by the first quarter of fiscal year 2019.

In April 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. Currently, debt issuance costs are recorded as a deferred charge (asset), while debt discount and debt premium costs are recorded as a liability adjustment. This amendment will require debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU No. 2015-15 clarified that ASU No. 2015-03 does not address the presentation of debt issuance costs related to line-of-credit arrangements, and the Company intends to continue to report such costs as deferred charges. The new guidance is effective for the Company, Laclede Gas and Alagasco beginning in the first quarter of fiscal 2017. The application of this standard will be retrospective, wherein each balance sheet presented will be adjusted to reflect the impacts of applying the new guidance. If this ASU had been adopted as of September 30, 2016, the amounts reclassified from other deferred charges to reduce long-term debt at September 30, 2016 and 2015, respectively, would have been $13.2 and $13.0 for Spire, $4.2 and $4.8 for Laclede Gas, and $2.6 and $2.4 for Alagasco.

In November 2015, the FASB issued ASU No. 2015-17, Income Taxes: Balance Sheet classification of Deferred Taxes, to require that deferred tax liabilities and assets be classified entirely as noncurrent. This was part of the FASB’s simplification initiative intended to reduce cost and complexity in financial reporting while improving or maintaining the usefulness of the information reported to investors. The Company, Laclede Gas and Alagasco adopted this ASU in the fourth quarter of fiscal 2016. Prior periods were not retrospectively adjusted. The adoption of this accounting standard was not material to the financial statements.

In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall: Recognition and Measurement of Financial Assets and Financial Liabilities, which provides revised guidance concerning certain matters involving the recognition, measurement, and disclosure of financial instruments. It is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Company, Laclede Gas and Alagasco are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of fiscal year 2019.

In February 2016, the FASB issued ASU No. 2016-02, Leases. The new standard requires lessees to recognize a right-of-use asset and lease liability for almost all lease contracts based on the present value of lease payments. There is an exemption for short-term leases. The ASU provides new guidelines for identifying and classifying a lease, and classification affects the pattern and income statement line item for the related expense. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company, Laclede Gas and Alagasco are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of fiscal year 2020.

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The standard is intended to simplify several areas of accounting for share-based compensation arrangements, including the income tax impact, classification on the statement of cash flows and forfeitures. The ASU is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Company, Laclede Gas and Alagasco are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of fiscal year 2018.

On June 16, 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments. The standard introduces new guidance for the accounting for credit losses on instruments within its scope, including trade receivables. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, but may be adopted up to two years earlier. The Company, Laclede Gas and Alagasco are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of fiscal year 2021.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Asset retirement obligations

The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30, as reported in the balance sheets.

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Asset retirement obligations, beginning of year	$	159.2		$	99.2		$	72.4		$	71.2		$	86.6		$	27.7
Liabilities incurred during the period	4.1			2.3			1.2			0.6			2.9			1.7
Liabilities settled during the period	(9.5		)	(2.0		)	(1.9		)	(1.9		)	(6.8		)	(0.1		)
Accretion	13.2			4.5			3.5			3.4			9.7			1.1
Revisions in estimated cash flows	27.5			55.2			—			(0.9		)	27.7			56.2
Addition of EnergySouth asset retirement obligations	11.9			—			—			—			—			—
Asset retirement obligations, end of year	$	206.4		$	159.2		$	75.2		$	72.4		$	120.1		$	86.6

Off-system sales

Pre-tax income from off-system sales and capacity release revenues is shared with customers, with an estimated amount assumed in PGA rates. The difference between the actual amount allocated to customers for each fiscal year and the estimated amount assumed in PGA rates is recovered from, or credited to, customers over an annual period commencing in the subsequent November. The customer share of such income is determined in accordance with the following tables, shown for each service territory for which the PGA clauses were approved by the MoPSC.

	Customer Share	Company Share
Eastern Missouri
First $2.0*	100%	—%
Next $2.0	80%	20%
Next $2.0	75%	25%
Amounts exceeding $6.0	70%	30%
* Customer share reverts to 85% and company share reverts to 15% in 2017.
Western Missouri
First $1.2	85%	15%
Next $1.2	80%	20%
Next $1.2	75%	25%
Amounts exceeding $3.6	70%	30%

Changes in the carrying amount of goodwill by reportable segment

The changes in the carrying amount of goodwill by reportable segment were as follows:

	Gas Utility			Gas Marketing		Other		Total
Balance as of September 30, 2013	$	247.1		$	—	$	—	$	247.1
Adjustments to finalize the 2013 acquisition of MGE	(36.9		)	—		—		(36.9		)
Acquisition of Alagasco	—			—		727.6		727.6
Balance as of September 30, 2014	210.2			—		727.6		937.8
Adjustments to finalize the acquisition of Alagasco	—			—		8.2		8.2
Balance as of September 30, 2015	210.2			—		735.8		946.0
Acquisition of EnergySouth	—			—		218.9		218.9
Balance as of September 30, 2016	$	210.2		$	—	$	954.7	$	1,164.9

Schedule of gross receipts taxes

The following table presents gross receipts taxes recorded:

	2016		2015		2014
Spire	$	75.5	$	97.3	$	77.5
Laclede Gas	57.4		74.5		76.3
Alagasco	17.9		22.6		20.6

Schedule of inter-company transactions

Laclede Gas had the following transactions with affiliates:

	2016		2015		2014
Purchases of natural gas from LER	$	46.3	$	74.1	$	89.1
Sales of natural gas to LER	1.9		4.0		5.1
Services received from Laclede Insurance Risk Services, Inc.	1.8		1.0		0.6

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ACQUISITIONS (Tables)

12 Months Ended

Sep. 30, 2016

Business Combinations [Abstract]

Schedule of consideration paid and amounts of assets acquired and liabilities assumed

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed at the acquisition dates. Measurement period adjustments were immaterial.

	Alagasco			EnergySouth
Recognized amounts of identifiable assets acquired and liabilities assumed:
Utility plant	$	892.7		$	199.5
Cash	12.1			2.0
Other current assets	99.4			17.5
Deferred tax assets	282.0			—
Other assets	143.4			79.8
Long-term debt	(249.8		)	(67.0		)
Current portion of long-term debt	(15.0		)	—
Other current liabilities	(173.4		)	(42.7		)
Deferred tax liabilities	—			(35.5		)
Other liabilities	(130.4		)	(52.8		)
Total identifiable net assets	861.0			100.8
Goodwill	735.8			218.9
Deferred tax elimination (Spire)	(271.3		)	—
Consideration (cash)	$	1,325.5		$	319.7

Schedule of Pro Forma Information

The results of operations of each of the acquisitions are included in the Spire statements of income from the date of acquisition, as shown in the following table.

	Alagasco							EnergySouth
	2016		2015		2014			2016
Total Operating Revenues	$	368.5	$	479.2	$	19.7		$	3.3
Net Income (Loss)	53.2		48.0		(2.9		)	(0.2		)
Earnings (Loss) Per Share	$	1.20	$	1.11	$	(0.08	)	$	—

The following unaudited pro forma financial information presents Spire’s combined results of operations as though the EnergySouth acquisition had occurred as of the beginning of fiscal year 2015 and the Alagasco acquisition had occurred as of the beginning of fiscal year 2013. The unaudited pro forma financial information is not necessarily indicative of either future results of operations or results that would have been achieved if the acquisitions had occurred as of those earlier dates. It does not reflect the costs of any integration activities. It includes estimates and assumptions which management believes are reasonable.

	2016		2015		2014
Total Operating Revenues	$	1,632.4	$	2,081.6	$	2,187.1
Net Income	153.9		143.6		133.5
Basic Earnings Per Share	$	3.48	$	3.32	$	3.11
Diluted Earnings Per Share	3.46		3.31		3.10

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STOCK-BASED COMPENSATION (Tables)

12 Months Ended

Sep. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Restricted stock and restricted stock unit activity

Fiscal year 2016 activity of restricted stock and restricted stock units subject to performance and/or market conditions is presented below:

	Shares/ Units		Weighted Average Grant Date Fair Value Per Share
Nonvested at September 30, 2015	397,270		$	36.28
Granted (maximum shares that can be earned)	199,140		$	45.95
Vested	(62,593	)	$	35.29
Forfeited	(23,234	)	$	30.96
Nonvested at September 30, 2016	510,583		$	40.37

Time-vested restricted stock and stock unit activity for fiscal year 2016 is presented below:

	Shares/ Units		Weighted Average Grant Date Fair Value Per Share
Nonvested at September 30, 2015	129,304		$	44.89
Granted	48,730		$	60.65
Vested	(44,645	)	$	47.30
Forfeited	(610	)	$	53.12
Nonvested at September 30, 2016	132,779		$	49.83

Stock option awards activity

No stock options were granted during fiscal years 2016, 2015, and 2014. Stock option activity for fiscal year 2016 is presented below:

	Stock Options		Weighted Average Exercise Price Per Share
Outstanding at September 30, 2015	28,500		$	33.65
Exercised	(27,750	)	$	33.66
Forfeited	(750	)	$	33.45
Outstanding at September 30, 2016	—		$	—

Significant assumptions used in the Monte Carlo simulations

The significant assumptions used in the Monte Carlo simulations are as follows:

	2016	2015	2014
Risk free interest rate	1.14%	0.83%	0.53%
Expected dividend yield of stock	—	—	—
Expected volatility of stock	15.0%	14.0%	18.0%
Vesting period	2.8 years	2.8 years	2.8 years

Compensation cost recognized for share-based compensation arrangements

The amounts of compensation cost recognized for share-based compensation arrangements are presented below:

	2016			2015			2014
Total equity compensation cost	$	6.7		$	6.7		$	5.8
Compensation cost capitalized	(2.2		)	(1.8		)	(1.8		)
Compensation cost recognized in net income	$	4.5		$	4.9		$	4.0
Income tax benefit recognized in net income	(1.7		)	(1.9		)	(1.5		)
Compensation cost recognized in net income, net of income tax	$	2.8		$	3.0		$	2.5

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EARNINGS PER COMMON SHARE (Tables)

12 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Earnings Per Common Share

	2016		2015		2014
Basic EPS:
Net Income	$	144.2	$	136.9	$	84.6
Less: Income allocated to participating securities	0.5		0.5		0.3
Net Income Available to Common Shareholders	$	143.7	$	136.4	$	84.3
Weighted Average Shares Outstanding (millions)	44.1		43.2		35.8
Earnings Per Share of Common Stock	$	3.26	$	3.16	$	2.36
Diluted EPS:
Net Income	$	144.2	$	136.9	$	84.6
Less: Income allocated to participating securities	0.5		0.5		0.3
Net Income Available to Common Shareholders	$	143.7	$	136.4	$	84.3
Weighted Average Shares Outstanding (millions)	44.1		43.2		35.8
Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units (millions)	0.2		0.1		0.1
Weighted Average Diluted Shares (millions)	44.3		43.3		35.9
Earnings Per Share of Common Stock	$	3.24	$	3.16	$	2.35
Outstanding Shares (in millions) Excluded from the Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to performance and/or market conditions	0.3		0.3		0.3

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STOCKHOLDERS' EQUITY (Tables)

12 Months Ended

Sep. 30, 2016

Stockholders' Equity Note [Abstract]

Schedule of stock purchase obligation

The purchase price to be paid under the stock purchase contracts is fifty dollars per Corporate Unit and the number of shares to be purchased will be determined as follows:

If the applicable market value per share of Spire common stock is:	Number of shares to be purchased per purchase contract is:
Equal to or greater than $57.8125	0.8649
Less than $57.8125, but greater than $46.25	$50 ÷ applicable market value
Less than or equal to $46.25	1.0811

Schedule of Company's equity units

Selected information about the Company’s equity units is presented below:

Issuance Date	Units Issued (Millions)	Total Net Proceeds	Total Long-term Debt	RSN Annual Interest Rate	Stock Purchase Contract Annual Rate	Stock Purchase Contract Liability
6/11/2014	2.875	$139.4	$143.8	2.00%	4.75%	$19.7

Schedule of accumulated other comprehensive income (loss)

The components of accumulated other comprehensive income (loss), net of income taxes, recognized in the balance sheets at September 30 were as follows:

	Net Unrealized Gains (Losses) on Cash Flow Hedges			Defined Benefit Pension and Other Postretirement Benefit Plans			Net Unrealized Losses on Available for Sale Securities			Total
Spire
Balance at September 30, 2014	$	0.2		$	(1.9	)	$	—		$	(1.7	)
Other comprehensive (loss) income	(0.6		)	0.4			(0.1		)	(0.3		)
Balance at September 30, 2015	(0.4		)	(1.5		)	(0.1		)	(2.0		)
Other comprehensive (loss) income	(1.9		)	(0.3		)	—			(2.2		)
Balance at September 30, 2016	$	(2.3	)	$	(1.8	)	$	(0.1	)	$	(4.2	)
Laclede Gas
Balance at September 30, 2014	$	—		$	(1.9	)	$	—		$	(1.9	)
Other comprehensive (loss) income	(0.2		)	0.4			—			0.2
Balance at September 30, 2015	(0.2		)	(1.5		)	—			(1.7		)
Other comprehensive income (loss)	0.3			(0.3		)	(0.1		)	(0.1		)
Balance at September 30, 2016	$	0.1		$	(1.8	)	$	(0.1	)	$	(1.8	)

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LONG-TERM DEBT (Tables)

12 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Schedule of maturities of long-term debt by fiscal year

Maturities of long-term debt for Spire, Laclede Gas and Alagasco for the five fiscal years subsequent to September 30, 2016 are as follows:

	Spire		Laclede Gas		Alagasco
2017	$	250.0	$	—	$	—
2018	100.0		100.0		—
2019	180.0		50.0		—
2020	40.0		—		40.0
2021	55.0		—		—

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NOTES PAYABLE AND CREDIT AGREEMENTS (Tables)

12 Months Ended

Sep. 30, 2016

Short-term Debt [Line Items]

Short-term borrowings

Information about Spire’s short-term borrowings (excluding intercompany borrowings) during the twelve months ended September 30, and as of September 30, is presented below for 2016 and 2015:

	Laclede Gas Commercial Paper Borrowings	Spire Bank Line Borrowings*	Alagasco Bank Line Borrowings	Total Short-Term Borrowings
Year Ended September 30, 2016
Weighted average borrowings outstanding	$201.0	$42.7	$30.2	$273.9
Weighted average interest rate	0.7%	1.6%	1.4%	0.9%
Range of borrowings outstanding	$43.0 - $307.2	$0.0 - $82.0	$0.0 - $82.0	$73.1 - $427.2
As of September 30, 2016
Borrowings outstanding at end of period	$243.7	$73.0	$82.0	$398.7
Weighted average interest rate	0.8%	1.8%	1.5%	1.1%
Year Ended September 30, 2015
Weighted average borrowings outstanding	$212.7	$65.6	$22.3	$300.6
Weighted average interest rate	0.4%	1.4%	1.1%	0.7%
Range of borrowings outstanding	$ 102.1 - $341.0	$32.5 - $80.0	$0.0 - $69.5	$180.1 - $488.5
As of September 30, 2015
Borrowings outstanding at end of period	$233.0	$74.0	$31.0	$338.0
Weighted average interest rate	0.5%	1.5%	1.2%	0.8%

* Spire Inc., excluding its wholly owned subsidiaries.

Laclede Gas

Short-term Debt [Line Items]

Short-term borrowings

Information about Laclede Gas’ short-term borrowings during the twelve months ended September 30, and as of September 30, is presented below for 2016 and 2015:

	Commercial Paper Borrowings	Borrowings from Spire	Total Short-Term Borrowings
Year Ended September 30, 2016
Weighted average borrowings outstanding	$201.0	$14.7	$215.7
Weighted average interest rate	0.7%	0.8%	0.7%
Range of borrowings outstanding	$43.0 - $307.2	$0.0 - $114.2	$127.8 - $ 307.2
As of September 30, 2016
Borrowings outstanding at end of period	$243.7	$—	$243.7
Weighted average interest rate	0.8%	—%	0.8%
Year Ended September 30, 2015
Weighted average borrowings outstanding	$212.7	$0.3	$213.0
Weighted average interest rate	0.4%	0.5%	0.4%
Range of borrowings outstanding	$102.1 - $341.0	$0.0 - $10.4	$104.2 - $ 341.0
As of September 30, 2015
Borrowings outstanding at end of period	$233.0	$—	$233.0
Weighted average interest rate	0.5%	—%	0.5%

Alagasco

Short-term Debt [Line Items]

Short-term borrowings

Information about Alagasco’s short-term borrowings during the twelve months ended September 30, and as of September 30, is presented below for 2016 and 2015:

	Bank Line Borrowings	Borrowings from Spire	Total Short-Term Borrowings
Year Ended September 30, 2016
Weighted average borrowings outstanding	$30.2	$12.4	$42.6
Weighted average interest rate	1.4%	1.4%	1.4%
Range of borrowings outstanding	$0.0 - $82	$0.0 - $61.9	$19.0 - $82.0
As of September 30, 2016
Borrowings outstanding at end of period	$82.0	$—	$82.0
Weighted average interest rate	1.5%	—%	1.5%
Year Ended September 30, 2015
Weighted average borrowings outstanding	$22.3	$—	$22.3
Weighted average interest rate	1.1%	—%	1.1%
Range of borrowings outstanding	$0.0 - $69.5	0	$0.0- $69.5
As of September 30, 2015
Borrowings outstanding at end of period	$31.0	$—	$31.0
Weighted average interest rate	1.2%	—%	1.2%

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FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Sep. 30, 2016

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis for the Company are as follows:

					Classification of Estimated Fair Value
	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of September 30, 2016
Cash and cash equivalents	$	5.2	$	5.2	$	5.2	$	—	$	—
Short-term debt	398.7		398.7		—		398.7		—
Long-term debt, including current portion	2,083.7		2,257.1		—		2,257.1		—
As of September 30, 2015
Cash and cash equivalents	$	13.8	$	13.8	$	13.8	$	—	$	—
Short-term debt	338.0		338.0		—		338.0		—
Long-term debt, including current portion	1,851.5		1,944.2		—		1,944.2		—

Laclede Gas

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis for Laclede Gas are as follows:

					Classification of Estimated Fair Value
	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of September 30, 2016
Cash and cash equivalents	$	2.1	$	2.1	$	2.1	$	—	$	—
Short-term debt	243.7		243.7		—		243.7		—
Long-term debt	808.3		900.4		—		900.4		—
As of September 30, 2015
Cash and cash equivalents	$	1.7	$	1.7	$	1.7	$	—	$	—
Short-term debt	233.0		233.0		—		233.0		—
Long-term debt	808.1		880.2		—		880.2		—

Alagasco

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair value of financial instruments

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis for Alagasco are as follows:

					Classification of Estimated Fair Value
	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of September 30, 2016
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—
Short-term debt	82.0		82.0		—		82.0		—
Long-term debt	250.0		275.5		—		275.5		—
As of September 30, 2015
Cash and cash equivalents	$	7.2	$	7.2	$	7.2	$	—	$	—
Short-term debt	31.0		31.0		—		31.0		—
Long-term debt, including current portion	250.0		263.2		—		263.2		—

XML

FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Sep. 30, 2016

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Measurements, Measured on Recurring Basis

The information presented below categorizes the assets and liabilities in the balance sheets that are accounted for at fair value on a recurring basis in periods subsequent to initial recognition.

The mutual funds included in Level 1 are valued based on exchange-quoted market prices of individual securities. The mutual funds included in Level 2 are valued based on the closing net asset value per unit.

Derivative instruments included in Level 1 are valued using quoted market prices on the NYMEX. Derivative instruments classified as Level 2 include physical commodity derivatives that are valued using Over-the-Counter Bulletin Board (OTCBB), broker, or dealer quotation services whose prices are derived principally from, or are corroborated by, observable market inputs. Also included in Level 2 are certain derivative instruments that have values that are similar to, and correlate with, quoted prices for exchange-traded instruments in active markets. Derivative instruments included in Level 3 are valued using generally unobservable inputs that are based upon the best information available and reflect management’s assumptions about how market participants would price the asset or liability. There were no material Level 3 balances as of September 30, 2016 or 2015. The Company’s and the Utilities’ policy is to recognize transfers between the levels of the fair value hierarchy, if any, as of the beginning of the interim reporting period in which circumstances change or events occur to cause the transfer.

The mutual funds are included in the “Other investments” line of the balance sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the balance sheets when a legally enforceable netting agreement exist between the Company or Laclede Gas and the counterparty to the derivative contract. For additional information on derivative instruments, see Note 10, Derivative Instruments and Hedging Activities.

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of September 30, 2016
ASSETS
Gas Utility
US stock/bond mutual funds	$	16.8	$	4.1	$	—	$	—		$	20.9
NYMEX/ICE natural gas contracts	5.3		—		—		(0.4		)	4.9
Gasoline and heating oil contracts	0.4		—		—		(0.3		)	0.1
Subtotal	22.5		4.1		—		(0.7		)	25.9
Gas Marketing
NYMEX/ICE natural gas contracts	0.4		3.4		—		(3.4		)	0.4
Natural gas commodity contracts	—		8.7		0.2		(0.9		)	8.0
Total	$	22.9	$	16.2	$	0.2	$	(5.0	)	$	34.3
LIABILITIES
Gas Utility
NYMEX/ICE natural gas contracts	$	1.6	$	—	$	—	$	(1.6	)	$	—
OTCBB natural gas contracts	—		0.2		—		—			0.2
Subtotal	1.6		0.2		—		(1.6		)	0.2
Gas Marketing
NYMEX/ICE natural gas contracts	3.5		1.6		—		(5.1		)	—
Natural gas commodity contracts	—		2.6		—		(0.9		)	1.7
Other
Interest rate swaps	—		3.0		—		—			3.0
Total	$	5.1	$	7.4	$	—	$	(7.6	)	$	4.9
As of September 30, 2015
ASSETS
Gas Utility
US stock/bond mutual funds	$	15.5	$	4.0	$	—	$	—		$	19.5
NYMEX/ICE natural gas contracts	1.3		—		—		(1.3		)	—
Subtotal	16.8		4.0		—		(1.3		)	19.5
Gas Marketing
NYMEX natural gas contracts	6.3		4.3		—		(6.6		)	4.0
Natural gas commodity contracts	—		1.5		0.2		(0.5		)	1.2
Total	$	23.1	$	9.8	$	0.2	$	(8.4	)	$	24.7
LIABILITIES
Gas Utility
NYMEX/ICE natural gas contracts	$	16.4	$	—	$	—	$	(16.4	)	$	—
OTCBB natural gas contracts	—		5.9		—		—			5.9
NYMEX gasoline and heating oil contracts	0.3		—		—		(0.3		)	—
Subtotal	16.7		5.9		—		(16.7		)	5.9
Gas Marketing
NYMEX/ICE natural gas contracts	1.2		3.9		—		(5.1		)	—
Natural gas commodity contracts	—		2.2		—		(0.5		)	1.7
Total	$	17.9	$	12.0	$	—	$	(22.3	)	$	7.6

Laclede Gas

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Measurements, Measured on Recurring Basis

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of September 30, 2016
ASSETS
US stock/bond mutual funds	$	16.8	$	4.1	$	—	$	—		$	20.9
NYMEX/ICE natural gas contracts	5.3		—		—		(0.4		)	4.9
Gasoline and heating oil contracts	0.3		—		—		(0.3		)	—
Total	$	22.4	$	4.1	$	—	$	(0.7	)	$	25.8
LIABILITIES
NYMEX/ICE natural gas contracts	$	1.6	$	—	$	—	$	(1.6	)	$	—
OTCBB natural gas contracts	—		0.2		—		—			0.2
Total	$	1.6	$	0.2	$	—	$	(1.6	)	$	0.2
As of September 30, 2015
ASSETS
US stock/bond mutual funds	$	15.5	$	4.0	$	—	$	—		$	19.5
NYMEX/ICE natural gas contracts	1.3		—		—		(1.3		)	—
Total	$	16.8	$	4.0	$	—	$	(1.3	)	$	19.5
LIABILITIES
NYMEX/ICE natural gas contracts	$	16.4	$	—	$	—	$	(16.4	)	$	—
OTCBB natural gas contracts	—		5.9		—		—			5.9
NYMEX gasoline and heating oil contracts	0.3		—		—		(0.3		)	—
Total	$	16.7	$	5.9	$	—	$	(16.7	)	$	5.9

XML

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

12 Months Ended

Sep. 30, 2016

Derivative [Line Items]

Derivative Instruments and Hedging Activities

Open NYMEX/ICE and OTCBB natural gas futures and swap positions at September 30, 2016 were as follows:

	Gas Utility			Gas Marketing
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
NYMEX/ICE Open short futures positions
Fiscal 2017	—	$	—	12.20	$	2.86
Fiscal 2018	—	—		1.27	2.95
NYMEX/ICE Open long futures/swap positions
Fiscal 2017	18.43	2.95		4.62	3.12
Fiscal 2018	0.33	2.83		0.45	3.02
Fiscal 2019	—	—		0.04	2.89
ICE Open long basis swap positions
Fiscal 2017	—	—		16.62	0.34
Fiscal 2018	—	—		2.01	0.43
Fiscal 2019	—	—		0.08	0.40
ICE Open short basis swap positions
Fiscal 2017	—	—		11.88	0.19
Fiscal 2018	—	—		0.93	0.27
Fiscal 2019	—	—		2.27	0.13
OTC Open long futures/swap positions
Fiscal 2017	0.32	3.64		—	—

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income

Effect of Derivative Instruments on the Consolidated Statements of Income and Consolidated Statements of Comprehensive Income
	Location of Gain (Loss)
	Recorded in Income	2016			2015			2014
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
Gas Marketing natural gas contracts		$	(0.6	)	$	(4.3	)	$	(4.6	)
Gas Utility gasoline and heating oil contracts		—			(1.2		)	0.1
Interest Rate Swaps		(3.4		)	—			—
Total		$	(4.0	)	$	(5.5	)	$	(4.5	)
Effective portion of gain (loss) reclassified from AOCI to income:
Natural gas contracts	Gas Marketing Operating Revenues	$	4.3		$	1.7		$	4.2
	Gas Marketing Operating Expenses	(4.9		)	(5.2		)	(1.5		)
Subtotal		(0.6		)	(3.5		)	2.7
Gasoline and heating oil contracts	Gas Utility Other Operating Expenses	(0.5		)	(0.9		)	(0.2		)
Total		$	(1.1	)	$	(4.4	)	$	2.5
Ineffective portion of gain (loss) on derivatives recognized in income:
Natural gas contracts	Gas Marketing Operating Revenues	$	0.1		$	—		$	(0.1	)
	Gas Marketing Operating Expenses	0.1			(0.5		)	0.1
Subtotal		0.2			(0.5		)	—
Gasoline and heating oil contracts	Gas Utility Other Operating Expenses	0.1			0.1			(0.2		)
Total		$	0.3		$	(0.4	)	$	(0.2	)
Derivatives Not Designated as Hedging Instruments*
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	12.3		$	(1.3	)	$	(8.7	)
NYMEX / ICE natural gas contracts	Gas Marketing Operating Revenues	(1.7		)	(9.6		)	3.0
Gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	—			(0.2		)	—
Total		$	10.6		$	(11.1	)	$	(5.7	)

* Gains and losses on Laclede Gas’ natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Missouri Utilities’ PGA clauses and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the statements of income. Such amounts are recognized in the statements of income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA clause and reflected in customer billings.

Fair Value of Derivative Instruments in the Consolidated Balance Sheet

Fair Value of Derivative Instruments in the Consolidated Balance Sheet
	Asset Derivatives*			Liability Derivatives*
September 30, 2016	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Gas Utility:
Gasoline and heating oil contracts	Derivative Instrument Assets	$	0.3	Derivative Instrument Assets	$	—
Gas Marketing:
Natural gas contracts	Derivative Instrument Assets	2.5		Derivative Instrument Assets	0.8
	Deferred Charges – Other	0.4		Deferred Charges – Other	0.1
Other: Interest swaps	Derivative Instrument Assets	—		Derivative Instrument Assets	3.0
Subtotal		3.2			3.9
Derivatives not designated as hedging instruments
Gas Utility:
Natural gas contracts	Accounts Receivable – Other	5.4		Accounts Receivable – Other	1.6
	Derivative Instrument Assets	—		Derivative Instrument Assets	0.2
Gas Marketing:
NYMEX / ICE natural gas contracts	Derivative Instrument Assets	0.8		Derivative Instrument Assets	4.1
	Deferred Charges – Other	—		Deferred Charges – Other	0.1
Natural gas commodity	Derivative Instrument Assets	6.5		Derivative Instrument Assets	0.2
	Other Deferred Charges	2.1		Other Deferred Charges	0.3
	Current Liabilities – Other	0.2		Current Liabilities – Other	2.0
	Deferred Credits – Other	0.2		Deferred Credits – Other	0.1
Subtotal		15.2			8.6
Total derivatives		$	18.4		$	12.5
September 30, 2015
Derivatives designated as hedging instruments
Gas Utility:
Gasoline and heating oil contracts	Accounts Receivable – Other	$	—	Accounts Receivable – Other	$	0.3
Gas Marketing:
Natural gas contracts	Derivative Instrument Assets	4.1		Derivative Instrument Assets	3.2
	Deferred Charges – Other	1.1		Deferred Charges – Other	0.5
Subtotal		5.2			4.0
Derivatives not designated as hedging instruments
Gas Utility:
Natural gas contracts	Accounts Receivable – Other	1.2		Accounts Receivable – Other	16.4
	Derivative Instrument Assets	—		Derivative Instrument Assets	5.7
	Deferred Charges – Other	—		Deferred Charges – Other	0.2
Gas Marketing:
NYMEX / ICE natural gas contracts	Derivative Instrument Assets	4.7		Derivative Instrument Assets	0.6
	Deferred Charges – Other	0.7		Deferred Charges – Other	0.7
Natural gas commodity	Derivative Instrument Assets	1.4		Derivative Instrument Assets	0.1
	Current Liabilities – Other	0.2		Current Liabilities – Other	1.4
	Deferred Credits – Other	0.1		Deferred Credits – Other	0.7
Subtotal		8.3			25.8
Total derivatives		$	13.5		$	29.8

* The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the balance sheets. As such, the gross balances presented in the table above are not indicative of the Company’s net economic exposure. Refer to Note 9, Fair Value Measurements, for information on the valuation of derivative instruments.

Derivative instrument Reconciliation

Following is a reconciliation of the amounts in the tables above to the amounts presented in the Consolidated Balance Sheets:

	2016			2015
Fair value of asset derivatives presented above	$	18.4		$	13.5
Fair value of cash margin receivables offset with derivatives	2.5			13.9
Netting of assets and liabilities with the same counterparty	(7.6		)	(22.2		)
Total	$	13.3		$	5.2
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	$	11.4		$	4.6
Deferred Charges – Other	1.9			0.6
Total	$	13.3		$	5.2
Fair value of liability derivatives presented above	$	12.5		$	29.8
Netting of assets and liabilities with the same counterparty	(7.6		)	(22.2		)
Total	$	4.9		$	7.6
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Current Liabilities – Other	$	4.8		$	6.8
Deferred Credits – Other	0.1			0.8
Total	$	4.9		$	7.6

Laclede Gas

Derivative [Line Items]

Derivative Instruments and Hedging Activities

Laclede Gas’ derivative instruments consist primarily of NYMEX and OTCBB positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX and OTCBB natural gas futures positions at September 30, 2016 were as follows:

	MMBtu (millions)	Avg. Price Per MMBtu
NYMEX/ICE Open long futures/swap positions
Fiscal 2017	18.43	$	2.95
Fiscal 2018	0.33	2.83
OTC Open long futures/swap positions
Fiscal 2017	0.32	$	3.64

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income

Effect of Derivative Instruments on the Statements of Income and Statements of Comprehensive Income
	Location of Gain (Loss)
	Recorded in Income	2016			2015			2014
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
Gasoline and heating oil contracts		$	—		$	(1.2	)	$	0.1
Effective portion of gain (loss) reclassified from AOCI to income:
Gasoline and heating oil contracts	Gas Utility Other Operating Expenses	$	(0.5	)	$	(0.9	)	$	(0.2	)
Ineffective portion of gain (loss) on derivatives recognized in income:
Gasoline and heating oil contracts	Gas Utility Other Operating Expenses	$	0.1		$	0.1		$	(0.2	)
Derivatives Not Designated as Hedging Instruments*
Gain (loss) recognized in income on derivatives:
Gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	$	—		$	(0.2	)	$	—

* Gains and losses on Laclede Gas’ natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Laclede Gas’ PGA clauses and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the Statements of Income. Such amounts are recognized in the Statements of Income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA clause and reflected in customer billings.

Fair Value of Derivative Instruments in the Consolidated Balance Sheet

Fair Value of Derivative Instruments in the Balance Sheet at September 30, 2016
	Asset Derivatives*				Liability Derivatives*
	Balance Sheet Location	Fair Value			Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Gasoline and heating oil contracts	Derivative Instrument Assets	$	0.3		Derivative Instrument Assets	$	—
Subtotal		0.3				—
Derivatives not designated as hedging instruments
Natural gas contracts	Accounts Receivable – Other	5.4			Accounts Receivable – Other	1.6
OTCBB natural gas contracts	Derivative Instrument Assets	—			Derivative Instrument Assets	0.2
Subtotal		5.4				1.8
Total derivatives		$	5.7			$	1.8
Fair Value of Derivative Instruments in the Balance Sheet at September 30, 2015
	Asset Derivatives				Liability Derivatives*
	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Gasoline and heating oil contracts	Accounts Receivable – Other	$	—		Accounts Receivable – Other	$	0.3
Subtotal		—				0.3
Derivatives not designated as hedging instruments
Natural gas contracts	Accounts Receivable – Other	1.2			Accounts Receivable – Other	16.4
	Derivative Instrument Assets	—			Derivative Instrument Assets	5.7
	Deferred Charges - Other	—			Deferred Charges - Other	0.2
Subtotal		1.2				22.3
Total derivatives		$	1.2			$	22.6

* The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the Balance Sheets. As such, the gross balances presented in the table above are not indicative of Laclede Gas’ net economic exposure. Refer to Note 9, Fair Value Measurements, for information on the valuation of derivative instruments.

Derivative instrument Reconciliation

Following is a reconciliation of the amounts in the tables above to the amounts presented in Laclede Gas’ Balance Sheets:

	2016			2015
Fair value of asset derivatives presented above	$	5.7		$	1.2
Fair value of cash margin receivables offset with derivatives	0.8			15.5
Netting of assets and liabilities with the same counterparty	(1.6		)	(16.7		)
Total	$	4.9		$	—
Derivative Instrument Assets, per Balance Sheets:
Derivative instrument assets	$	4.9		$	—
Total	$	4.9		$	—
Fair value of liability derivatives presented above	$	1.8		$	22.6
Netting of assets and liabilities with the same counterparty	(1.6		)	(16.7		)
Total	$	0.2		$	5.9
Derivative Instrument Liabilities, per Balance Sheets:
Current Liabilities – Other	$	0.2		$	5.7
Deferred Credits – Other	—			0.2
Total	$	0.2		$	5.9

XML

INCOME TAXES (Tables)

12 Months Ended

Sep. 30, 2016

Income Tax Contingency [Line Items]

Net Provision For Income Tax

The Company’s provision for income taxes charged during the fiscal years ended September 30, 2016, 2015, and 2014 are as follows:

	2016			2015			2014
Federal
Current	$	0.1		$	(3.3	)	$	0.3
Deferred	62.0			58.8			30.6
Investment tax credits	(0.2		)	(0.2		)	(0.2		)
State and local
Current	0.6			—			0.6
Deferred	7.0			6.9			1.0
Total income tax expense	$	69.5		$	62.2		$	32.3

Effective income tax rate variation from stated tax rate

The Company’s effective income tax rate varied from the federal statutory income tax rate for each year due to the following:

	2016		2015		2014
Federal income tax statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal income tax benefits	2.8		3.0		1.8
Certain expenses capitalized on books and deducted on tax return	(3.4	)	(3.7	)	(4.9	)
Taxes related to prior years	(0.2	)	(0.6	)	(0.7	)
Other items – net *	(1.7	)	(2.5	)	(3.6	)
Effective income tax rate	32.5	%	31.2	%	27.6	%

* Other consists primarily of property adjustments.

Significant Items in Net Deferred Tax Liability

The Company’s significant items comprising the net deferred tax liability recorded in the Consolidated Balance Sheets as of September 30 are as follows:

	2016		2015
Deferred tax assets:
Reserves not currently deductible	$	21.3	$	14.8
Pension and other postretirement benefits	68.3		62.5
Operating losses	102.3		47.3
Other	—		1.5
Deferred tax assets	191.9		126.1
Less: valuation allowance	0.9		—
Total deferred tax assets	191.0		126.1
Deferred tax liabilities:
Relating to property	623.1		472.1
Regulatory pension and other postretirement benefits	106.8		110.6
Deferred gas costs	20.0		8.1
Other	48.4		11.6
Total deferred tax liabilities	798.3		602.4
Net deferred tax liability	607.3		476.3
Net deferred tax asset – current	—		5.8
Net deferred tax liability – noncurrent	$	607.3	$	482.1

Unrecognized Tax Benefit Reconciliation

The following table presents a reconciliation of the beginning and ending balances of the Company’s unrecognized tax benefits:

	2016			2015			2014
Unrecognized tax benefits, beginning of year	$	7.1		$	4.6		$	2.4
Increases related to tax positions taken in current year	3.4			2.9			2.6
Reductions due to lapse of applicable statute of limitations	(0.5		)	(0.4		)	(0.4		)
Unrecognized tax benefits, end of year	$	10.0		$	7.1		$	4.6

Laclede Gas

Income Tax Contingency [Line Items]

Net Provision For Income Tax

Laclede Gas’ provision for income taxes charged during the fiscal years ended September 30, 2016, 2015, and 2014 are as follows:

	2016			2015			2014
Federal
Current	$	—		$	(2.1	)	$	(0.1	)
Deferred	37.5			40.9			34.3
Investment tax credits	(0.2		)	(0.2		)	(0.2		)
State and local
Current	0.1			(0.1		)	—
Deferred	8.0			4.7			1.5
Total income tax expense	$	45.4		$	43.2		$	35.5

Effective income tax rate variation from stated tax rate

Laclede Gas’ effective income tax rate varied from the federal statutory income tax rate for each year due to the following:

	2016		2015		2014
Federal income tax statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal income tax benefits	2.8		2.8		1.8
Certain expenses capitalized on books and deducted on tax return	(4.8	)	(4.9	)	(4.5	)
Taxes related to prior years	(0.2	)	(0.8	)	(0.7	)
Other items – net *	(2.8	)	(3.0	)	(3.3	)
Effective income tax rate	30.0	%	29.1	%	28.3	%

* Other consists primarily of property adjustments.

Significant Items in Net Deferred Tax Liability

Laclede Gas’ significant items comprising the net deferred tax liability reported in the Balance Sheets as of September 30 are as follows:

	2016		2015
Deferred tax assets:
Reserves not currently deductible	$	14.9	$	15.4
Pension and other postretirement benefits	56.9		62.5
Operating losses	29.9		3.7
Other	—		1.5
Deferred tax assets	101.7		83.1
Less: valuation allowance	0.9		—
Total deferred tax assets	100.8		83.1
Deferred tax liabilities:
Relating to utility property	497.0		425.0
Regulatory pension and other postretirement benefits	106.8		120.2
Deferred gas costs	20.0		8.2
Other	33.9		14.5
Total deferred tax liabilities	657.7		567.9
Net deferred tax liability	556.9		484.8
Net deferred tax asset – current	—		0.4
Net deferred tax liability – noncurrent	$	556.9	$	485.2

Unrecognized Tax Benefit Reconciliation

The following table presents a reconciliation of the beginning and ending balances of Laclede Gas unrecognized tax benefits:

	2016			2015			2014
Unrecognized tax benefits, beginning of year	$	6.9		$	4.2		$	2.0
Increases related to tax positions taken in current year	3.3			2.9			2.5
Reductions due to lapse of applicable statute of limitations	(0.5		)	(0.2		)	(0.3		)
Unrecognized tax benefits, end of year	$	9.7		$	6.9		$	4.2

Alagasco

Income Tax Contingency [Line Items]

Net Provision For Income Tax

Alagasco’s provision for income taxes charged during the fiscal years ended September 30, 2016 and 2015, and the nine months ended September 30, 2014, are as follows:

	Year Ended September 30,			Year Ended September 30,		Nine Months Ended September 30,
	2016			2015		2014
Federal
Current	$	(0.8	)	$	—	$	14.1
Deferred	29.4			25.9		3.5
State and local
Current	—			0.1		1.8
Deferred	3.8			3.3		0.5
Total income tax expense	$	32.4		$	29.3	$	19.9

Effective income tax rate variation from stated tax rate

Alagasco’s effective income tax rate varied from the federal statutory income tax rate for each year due to the following:

	Year Ended September 30,		Year Ended September 30,		Nine Months Ended September 30,
	2016		2015		2014
Federal income tax statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal income tax benefits	2.8		2.8		2.8
Other items – net	0.1		0.1		(0.2	)
Effective income tax rate	37.9	%	37.9	%	37.6	%

Significant Items in Net Deferred Tax Liability

Alagasco’s significant items comprising the net deferred tax asset reported in the Balance Sheets as of September 30 are as follows:

	2016		2015
Deferred tax assets:
Reserves not currently deductible	$	6.3	$	7.0
Pension and other postretirement benefits	11.4		9.6
Goodwill	233.4		251.5
Operating losses	60.2		32.4
Other	—		1.4
Total deferred tax assets	311.3		301.9
Deferred tax liabilities:
Relating to utility property	87.6		45.1
Other	2.3		2.2
Total deferred tax liabilities	89.9		47.3
Net deferred tax asset	221.4		254.6
Net deferred tax asset – current	—		6.2
Net deferred tax asset – noncurrent	$	221.4	$	248.4

Unrecognized Tax Benefit Reconciliation

The following table presents a reconciliation of the beginning and ending balances of Alagasco’s unrecognized tax benefits:

	Year Ended September 30,		Year Ended September 30,		Nine Months Ended September 30,
	2016		2015		2014
Unrecognized tax benefits, beginning of period	$	—	$	—	$	0.3
Reduction for transfer of balance to Energen	—		—		(0.3		)
Unrecognized tax benefits, end of period	$	—	$	—	$	—

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS (Tables)

12 Months Ended

Sep. 30, 2016

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Fair value measurements of plan assets

The table below categorizes the fair value measurements of the Spire pension plan assets:

	Quoted Prices in Active Markets (Level 1)			Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	51.2		$	—	$	—	$	51.2
Stock/bond mutual fund	99.3			26.7		0.1		126.1
Debt Securities
US bond mutual funds	23.0			126.0		—		149.0
US government	42.1			3.0		—		45.1
US corporate	137.4			—		—		137.4
US municipal	6.3			—		—		6.3
International	25.3			—		—		25.3
Derivatives and margin (payable)	(1.0		)	1.1		—		0.1
Total	$	383.6		$	156.8	$	0.1	$	540.5
As of September 30, 2015
Cash and cash equivalents	$	43.4		$	0.2	$	—	$	43.6
Stock/bond mutual fund	46.4			74.6		9.6		130.6
Debt Securities
US bond mutual funds	—			9.3		—		9.3
US government	58.7			—		—		58.7
US corporate	123.7			42.9		—		166.6
US municipal	—			5.9		—		5.9
International	—			31.3		—		31.3
Derivative instruments	—			2.9		—		2.9
Total	$	272.2		$	167.1	$	9.6	$	448.9

The table below categorizes the fair value measurements of Spire’s postretirement plan assets:

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	4.8	$	—	$	—	$	4.8
US stock/bond mutual fund	157.9		68.5		—		226.4
International fund	0.9		14.3		—		15.2
Total	$	163.6	$	82.8	$	—	$	246.4
As of September 30, 2015
Cash and cash equivalents	$	1.6	$	—	$	—	$	1.6
US stock/bond mutual fund	115.5		92.8		—		208.3
International fund	—		13.4		—		13.4
Total	$	117.1	$	106.2	$	—	$	223.3

Pension Plans

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Net periodic cost

The net periodic pension costs include the following components:

	Spire									Laclede Gas									Alagasco
	2016			2015			2014			2016			2015			2014			2016			2015			2014*
Service cost – benefits earned during the period	$	15.3		$	17.3		$	10.2		$	10.0		$	11.5		$	9.7		$	5.3		$	5.8		$	5.1
Interest cost on projected benefit obligation	28.0			29.5			24.5			21.7			23.3			24.0			6.3			6.2			4.1
Expected return on plan assets	(34.9		)	(37.4		)	(27.2		)	(26.7		)	(29.2		)	(26.5		)	(8.2		)	(8.2		)	(5.2		)
Amortization of other comprehensive income	—			—			0.4			—			—			—			—			—			—
Amortization of prior service cost	0.4			0.5			0.5			0.4			0.5			0.5			—			—			0.1
Amortization of actuarial loss	8.0			7.5			7.1			7.9			7.5			7.1			0.1			—			2.2
Loss on lump-sum settlements	3.3			19.6			1.5			—			18.0			1.5			3.3			1.6			10.1
Special termination benefits	1.6			—			—			1.6			—			—			—			—			—
Subtotal	21.7			37.0			17.0			14.9			31.6			16.3			6.8			5.4			16.4
Regulatory adjustment	17.8			(2.1		)	10.4			11.7			(5.2		)	10.4			6.1			3.1			0.4
Net pension cost	$	39.5		$	34.9		$	27.4		$	26.6		$	26.4		$	26.7		$	12.9		$	8.5		$	16.8
													* Nine months ended September 30

Other changes in plan assets and benefit obligations recognized in other comprehensive income

Other changes in plan assets and pension benefit obligations recognized in other comprehensive income or loss (OCI) include the following:

	Spire									Laclede Gas									Alagasco
	2016			2015			2014			2016			2015			2014			2016			2015			2014*
Current year actuarial loss	$	46.8		$	48.3		$	15.7		$	21.6		$	26.0		$	14.2		$	25.2		$	22.3		$	1.5
Amortization of actuarial loss	(8.0		)	(7.5		)	(7.1		)	(7.9		)	(7.5		)	(7.1		)	(0.1		)	—			—
Acceleration of loss recognized due to settlement	(3.3		)	(19.6		)	(1.5		)	—			(18.0		)	(1.5		)	(3.3		)	(1.6		)	—
Amortization of current year service cost	5.0			—			—			5.0			—			—			—			—			—
Amortization of prior service cost	(0.4		)	(0.5		)	(0.5		)	(0.4		)	(0.5		)	(0.5		)	—			—			—
Subtotal	40.1			20.7			6.6			18.3			—			5.1			21.8			20.7			1.5
Regulatory adjustment	(39.8		)	(21.2		)	(6.1		)	(18.0		)	(0.5		)	(4.7		)	(21.8		)	(20.7		)	(1.5		)
Total recognized in OCI	$	0.3		$	(0.5	)	$	0.5		$	0.3		$	(0.5	)	$	0.4		$	—		$	—		$	—
													* Nine months ended September 30

Reconciliation of the beginning and ending balances of benefit obligation

The following table shows the reconciliation of the beginning and ending balances of the pension benefit obligation at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Benefit obligation, beginning of year	$	652.3		$	692.4		$	497.6		$	543.6		$	154.7		$	148.8
Service cost	15.3			17.3			10.0			11.5			5.3			5.8
Interest cost	28.0			29.5			21.7			23.3			6.3			6.2
Actuarial loss (gain)	85.8			(12.8		)	59.2			(20.7		)	26.6			7.9
Plan amendments	5.1			—			5.1			—			—			—
EnergySouth acquisition	60.4			—			—			—			—			—
Settlement loss	1.1			16.5			—			14.5			1.1			2.0
Special termination benefits	1.6			—			1.6			—			—			—
Settlement benefits paid	(16.6		)	(71.1		)	—			(58.2		)	(16.6		)	(12.9		)
Regular benefits paid	(38.3		)	(19.5		)	(35.2		)	(16.4		)	(3.1		)	(3.1		)
Benefit obligation, end of year	$	794.7		$	652.3		$	560.0		$	497.6		$	174.3		$	154.7
Accumulated benefit obligation, end of year	724.5			$	591.4		517.7			$	456.9		149.8			$	134.5

Fair value of plan assets

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Fair value of plan assets, beginning of year	$	448.9		$	506.6		$	339.9		$	387.4		$	109.0		$	119.2
Actual return on plan assets	75.1			(7.2		)	64.4			(3.0		)	10.7			(4.2		)
Employer contributions	26.6			40.1			26.6			30.1			—			10.0
EnergySouth acquisition	44.8			—			—			—			—			—
Settlement benefits paid	(16.6		)	(71.1		)	—			(58.2		)	(16.6		)	(12.9		)
Regular benefits paid	(38.3		)	(19.5		)	(35.2		)	(16.4		)	(3.1		)	(3.1		)
Fair value of plan assets, end of year	$	540.5		$	448.9		$	395.7		$	339.9		$	100.0		$	109.0
Funded status of plans, end of year	$	(254.2	)	$	(203.4	)	$	(164.3	)	$	(157.7	)	$	(74.3	)	$	(45.7	)

Amounts recognized in consolidated balance sheets

The following table sets forth the amounts recognized in the balance sheets at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Current liabilities	$	(0.6	)	$	(0.5	)	$	(0.6	)	$	(0.5	)	$	—		$	—
Noncurrent liabilities	(253.6		)	(202.9		)	(163.7		)	(157.2		)	(74.3		)	(45.7		)
Total	$	(254.2	)	$	(203.4	)	$	(164.3	)	$	(157.7	)	$	(74.3	)	$	(45.7	)

Pre-tax amounts recognized in accumulated other comprehensive loss not yet recognized as components of net periodic pension cost consist of:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Net actuarial loss	$	179.4		$	143.9		$	135.5		$	121.9		$	43.9		$	22.0
Prior service costs	8.2			3.5			8.2			3.5			—			—
Subtotal	187.6			147.4			143.7			125.4			43.9			22.0
Adjustments for amounts included in regulatory assets	(184.8		)	(144.9		)	(140.9		)	(122.9		)	(43.9		)	(22.0		)
Total	$	2.8		$	2.5		$	2.8		$	2.5		$	—		$	—

Pre-tax amounts amortized from accumulated other comprehensive income into net periodic cost

At September 30, 2016, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive loss into net periodic pension cost during fiscal year 2017:

	Spire			Laclede Gas			Alagasco
Amortization of net actuarial loss	$	13.5		$	11.6		$	1.9
Amortization of prior service cost	1.0			1.0			—
Subtotal	14.5			12.6			1.9
Regulatory adjustment	(14.2		)	(12.3		)	(1.9		)
Total	$	0.3		$	0.3		$	—

Assumptions used to calculate net periodic cost and benefit obligations.

The assumptions used to calculate the benefit obligations are as follows:

	2016	2015
Weighted average discount rate - Laclede Gas division	3.50%	4.40%
Weighted average discount rate - MGE division	3.50%	4.50%
Weighted average discount rate - Alagasco	3.45%/3.50%	4.25%/4.30%
Weighted average rate of future compensation increase - Laclede Gas, Alagasco and MGE	3.00%	3.00%

The assumptions used to calculate net periodic pension costs for Laclede Gas are as follows:

	2016	2015	2014
Weighted average discount rate - Laclede Gas division plans	4.40%	4.30%	4.70%
Weighted average discount rate - MGE division plans	4.50%	4.45%	5.00%
Weighted average rate of future compensation increase *	3.00%	3.00%	3.00%
Expected long-term rate of return on plan assets *	7.75%	7.75%	7.75%

* Assumptions for weighted average rate of future compensation increase and expected long-term rate of return on plan assets are the same for both Laclede Gas and MGE plans.

The assumptions used to calculate net periodic pension costs for Alagasco are as follows:

	2016	2015	2014*
Weighted average discount rate	4.25% /4.30%	4.15% /4.25%	4.00% / 4.05%
Weighted average rate of future compensation increase	3.00%	2.92%	2.92%
Expected long-term rate of return on plan assets	7.50%	7.00% / 7.25%	7.00% / 7.25%

* Nine-month transition period ended September 30

Projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for plans that have projected benefit obligation and accumulated benefit obligation in excess of plan assets

Following are the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for plans that have a projected benefit obligation and an accumulated benefit obligation in excess of plan assets:

	Spire				Laclede Gas				Alagasco
	2016		2015		2016		2015		2016		2015
Projected benefit obligation	$	794.8	$	652.3	$	560.0	$	497.6	$	174.3	$	154.7
Accumulated benefit obligation	724.5		591.4		517.7		456.9		149.8		134.5
Fair value of plan assets	540.5		448.9		395.7		339.9		100.0		109.0

Targeted and actual plan assets by category

Following are the targeted and actual plan assets by category as of September 30 of each year for Laclede Gas and Alagasco:

Laclede Gas	2016 Target		2016 Actual		2015 Target		2015 Actual
Equity markets	56.2	%	56.9	%	52.0	%	48.4	%
Debt securities	43.8	%	43.1	%	48.0	%	50.1	%
Other*	—	%	—	%	—	%	1.5	%
Total	100.0	%	100.0	%	100.0	%	100.0	%

* Other investments in 2016 and 2015 consisted of cash equivalents.

Alagasco	2016 Target		2016 Actual		2015 Target		2015 Actual
Equity markets	60.0	%	59.2	%	60.0	%	52.9	%
Debt securities	29.0	%	28.8	%	29.0	%	27.9	%
Other*	11.0	%	12.0	%	11.0	%	19.2	%
Total	100.0	%	100.0	%	100.0	%	100.0	%

* Other investments in 2016 included cash, real estate, commodities, natural resources and TIPS. In 2015, this included cash and cash equivalents, hedge funds, real estate, and all asset funds, which can invest in equities or fixed income.

Expected benefit payments for the succeeding five fiscal years

Following are expected pension benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter, for Spire, Laclede Gas, and Alagasco:

	2017		2018		2019		2020		2021		2022- 2026
Spire	$	61.3	$	56.2	$	57.1	$	56.6	$	56.8	$	286.3
Laclede Gas	48.2		43.3		43.5		42.2		40.4		196.6
Alagasco	10.9		10.6		11.2		11.9		13.7		74.5

Postretirement Plans

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Net periodic cost

Net periodic postretirement benefit costs consist of the following components:

	Spire									Laclede Gas									Alagasco
	2016			2015			2014			2016			2015			2014			2016			2015			2014*
Service cost – benefits earned during the period	$	10.9		$	12.8		$	11.3		$	10.6		$	12.3		$	11.2		$	0.3		$	0.5		$	0.4
Interest cost on accumulated postretirement benefit obligation	10.2			11.2			8.9			8.1			8.6			8.7			2.1			2.6			1.9
Expected return on plan assets	(13.5		)	(13.2		)	(7.3		)	(8.5		)	(8.1		)	(6.8		)	(5.0		)	(5.1		)	(3.6		)
Amortization of prior other comprehensive loss	—			—			(0.2		)	—			—			—			—			—			—
Amortization of prior service cost	0.3			0.8			—			0.3			0.8			—			—			—			—
Amortization of actuarial loss (gain)	3.6			5.1			6.0			3.8			5.1			6.0			(0.2		)	—			(1.0		)
Special termination benefits	2.6			—			—			2.6			—			—			—			—			—
Subtotal	14.1			16.7			18.7			16.9			18.7			19.1			(2.8		)	(2.0		)	(2.3		)
Regulatory adjustment	(6.6		)	(11.0		)	(9.6		)	(4.8		)	(9.2		)	(9.6		)	(1.8		)	(1.8		)	(0.2		)
Net postretirement benefit cost	$	7.5		$	5.7		$	9.1		$	12.1		$	9.5		$	9.5		$	(4.6	)	$	(3.8	)	$	(2.5	)
													* Nine months ended September 30

Other changes in plan assets and benefit obligations recognized in other comprehensive income

Other changes in plan assets and postretirement benefit obligations recognized in OCI include the following:

	Spire									Laclede Gas									Alagasco
	2016			2015			2014			2016			2015			2014			2016			2015			2014*
Current year actuarial loss (gain)	$	0.8		$	(8.5	)	$	(3.1	)	$	1.4		$	(2.4	)	$	(4.2	)	$	(0.6	)	$	(6.1	)	$	1.1
Amortization of actuarial (loss) gain	(3.6		)	(5.1		)	(6.0		)	(3.8		)	(5.1		)	(6.0		)	0.2			—			—
Amortization of prior service (cost) credit	(0.3		)	(0.8		)	2.5			(0.3		)	(0.8		)	2.5			—			—			—
Current year prior service credit	(1.8		)	(4.9		)	—			—			(4.9		)	—			(1.8		)	—			—
Subtotal	(4.9		)	(19.3		)	(6.6		)	(2.7		)	(13.2		)	(7.7		)	(2.2		)	(6.1		)	1.1
Regulatory adjustment	4.9			19.3			6.6			2.7			13.2			7.7			2.2			6.1			(1.1		)
Total recognized in OCI	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
													* Nine months ended September 30

Reconciliation of the beginning and ending balances of benefit obligation

The following table sets forth the reconciliation of the beginning and ending balances of the postretirement benefit obligation at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Benefit obligation, beginning of year	$	239.2		$	258.5		$	191.9		$	197.9		$	47.3		$	60.6
Service cost	10.9			12.8			10.6			12.3			0.3			0.5
Interest cost	10.2			11.2			8.1			8.6			2.1			2.6
Actuarial loss (gain)	7.1			(23.7		)	6.7			(10.9		)	0.4			(12.8		)
Plan amendments	(1.8		)	(4.9		)	—			(4.9		)	(1.8		)	—
EnergySouth acquisition	5.9			—			—			—			—			—
Special termination benefits	2.6			—			2.6			—			—			—
Retiree drug subsidy program	0.2			0.4			—			—			0.2			0.4
Gross benefits paid	(15.1		)	(15.1		)	(12.0		)	(11.1		)	(3.1		)	(4.0		)
Benefit obligation, end of year	$	259.2		$	239.2		$	207.9		$	191.9		$	45.4		$	47.3

Fair value of plan assets

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Fair value of plan assets at beginning of year	$	223.3		$	222.5		$	143.6		$	137.2		$	79.7		$	85.3
Actual return on plan assets	19.9			(2.0		)	13.8			(0.4		)	6.2			(1.6		)
Employer contributions	14.3			17.9			14.3			17.9			—			—
EnergySouth acquisition	4.0			—			—			—			—			—
Gross benefits paid	(15.1		)	(15.1		)	(12.0		)	(11.1		)	(3.1		)	(4.0		)
Fair value of plan assets, end of year	$	246.4		$	223.3		$	159.7		$	143.6		$	82.8		$	79.7
Funded status of plans, end of year	$	(12.8	)	$	(15.9	)	$	(48.2	)	$	(48.3	)	$	37.4		$	32.4

Amounts recognized in consolidated balance sheets

The following table sets forth the amounts recognized in the balance sheets at September 30:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016		2015
Current assets	$	0.3		$	—		$	0.3		$	—		$	—	$	—
Noncurrent assets	37.4			35.5			—			3.1			37.4		32.4
Current liabilities	(0.4		)	(0.3		)	(0.4		)	(0.3		)	—		—
Noncurrent liabilities	(50.1		)	(51.1		)	(48.1		)	(51.1		)	—		—
Total	$	(12.8	)	$	(15.9	)	$	(48.2	)	$	(48.3	)	$	37.4	$	32.4

Pre-tax amounts recognized in accumulated other comprehensive loss not yet recognized as components of net periodic postretirement benefit cost consist of:

	Spire						Laclede Gas						Alagasco
	2016			2015			2016			2015			2016			2015
Net actuarial loss	$	38.0		$	40.8		$	43.4		$	45.8		$	(5.4	)	$	(5.0	)
Prior service credit	(5.2		)	(3.1		)	(3.4		)	(3.1		)	(1.8		)	—
Subtotal	32.8			37.7			40.0			42.7			(7.2		)	(5.0		)
Adjustments for amounts included in regulatory assets	(32.8		)	(37.7		)	(40.0		)	(42.7		)	7.2			5.0
Total	$	—		$	—		$	—		$	—		$	—		$	—

Pre-tax amounts amortized from accumulated other comprehensive income into net periodic cost

At September 30, 2016, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive loss into net periodic postretirement benefit cost during fiscal year 2017:

	Spire			Laclede Gas			Alagasco
Amortization of net actuarial loss (gain)	$	2.4		$	2.5		$	(0.1	)
Amortization of prior service cost	0.1			0.3			(0.2		)
Subtotal	2.5			2.8			(0.3		)
Regulatory adjustment	(2.5		)	(2.8		)	0.3
Total	$	—		$	—		$	—

Assumptions used to calculate net periodic cost and benefit obligations.

The assumptions used to calculate the accumulated postretirement benefit obligations for Laclede Gas are as follows:

	2016		2015
Weighted average discount rate - Laclede Gas division plans	3.15	%	4.00	%
Weighted average discount rate - MGE division plans	3.45	%	4.30	%
Weighted average rate of future compensation increase	3.00	%	3.00	%

The assumptions used to calculate the accumulated postretirement benefit obligations for Alagasco are as follows:

	2016		2015
Weighted average discount rate	3.60	%	4.50	%
Weighted average rate of future compensation increase	n/a		n/a

The assumptions used to calculate net periodic postretirement benefit costs for Laclede Gas are as follows:

	2016		2015		2014
Weighted average discount rate Laclede Gas division plans	4.00	%	4.15	%	4.60	%
Weighted average discount rate MGE division plans	4.30	%	4.40	%	4.95	%
Weighted average rate of future compensation increase - Laclede Gas plans	3.00	%	3.00	%	3.00	%
Expected long-term rate of return on plan assets - Laclede Gas division plans	6.00% / 7.75%		6.25% / 7.75%		6.25% / 7.75%
Expected long-term rate of return on plan assets - MGE division plans	4.75	%	5.00	%	3.75% / 5.75%

The assumptions used to calculate net periodic postretirement benefit costs for Alagasco are as follows:

	2016		2015		2014
Weighted average discount rate	4.50	%	4.40	%	4.25	%
Weighted average rate of future compensation increase	n/a		n/a		2.92	%
Expected long-term rate of return on plan assets	4.50% / 7.25%		4.75% / 7.50%		4.75% / 7.25%

Targeted and actual plan assets by category

Following are the targeted and actual plan assets by category as of September 30 of each year for Laclede Gas and Alagasco:

Laclede Gas	Target		2016 Actual		2015 Actual
Equity securities	60.0	%	59.1	%	59.6	%
Debt securities	40.0	%	39.4	%	39.7	%
Other (cash and cash equivalents)	—	%	1.5	%	0.7	%
Total	100.0	%	100.0	%	100.0	%

Alagasco	Target		2016 Actual		2015 Actual
Equity securities	60.0	%	60.5	%	59.7	%
Debt securities	40.0	%	39.5	%	40.3	%
Total	100.0	%	100.0	%	100.0	%

Expected benefit payments for the succeeding five fiscal years

Following are expected postretirement benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter for Spire, Laclede Gas, and Alagasco:

	2017		2018		2019		2020		2021		2022- 2026
Spire	$	15.4	$	16.7	$	17.9	$	19.1	$	20.1	$	108.6
Laclede Gas	12.3		13.7		14.8		15.8		16.8		92.5
Alagasco	2.9		2.8		2.8		2.9		2.9		14.1

Assumed medical cost trend rates and effect of an assumed 1% changed in assumed medical cost trend.

The assumed medical cost trend rates at September 30 are as follows:

	2016		2015
Medical cost trend assumed for next year - Laclede Gas	7.50	%	7.00	%
Medical cost trend assumed for next year - Alagasco	7.50	%	7.00	%
Rate to which the medical cost trend rate is assumed to decline (the ultimate medical cost trend rate)	5.00	%	5.00	%
Year the rate reaches the ultimate trend	2023		2020

The following table presents the effects of an assumed 1% change in the assumed medical cost trend rate:

	Spire					Laclede Gas					Alagasco
	1% Increase		1% Decrease			1% Increase		1% Decrease			1% Increase		1% Decrease
Net periodic postretirement benefit cost	$	1.5	$	(1.4	)	$	1.5	$	(1.4	)	$	—	$	—
Accumulated postretirement benefit obligation	11.0		(10.2		)	9.0		(8.4		)	1.3		(1.2		)

Laclede Gas

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Fair value measurements of plan assets

The table below categorizes the fair value measurements of Laclede Gas’ pension plan assets:

	Quoted Prices in Active Markets (Level 1)			Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	46.5		$	—	$	—	$	46.5
Stock/bond mutual fund	—			14.8		0.1		14.9
Debt Securities
US bond mutual funds	—			120.2		—		120.2
US government	42.1			3.0		—		45.1
US corporate	137.4			—		—		137.4
US municipal	6.3			—		—		6.3
International	25.2			—		—		25.2
Derivatives and margin (payable)	(1.0		)	1.1		—		0.1
Total	$	256.5		$	139.1	$	0.1	$	395.7
As of September 30, 2015
Cash and cash equivalents	$	31.8		$	—	$	—	$	31.8
Stock/bond mutual funds	—			67.6		0.1		67.7
Debt Securities
US government	37.7			—		—		37.7
US corporate	123.7			42.9		—		166.6
US municipal	—			5.9		—		5.9
International	—			27.3		—		27.3
Derivative instruments	—			2.9		—		2.9
Total	$	193.2		$	146.6	$	0.1	$	339.9

The table below categorizes the fair value measurements of Laclede Gas’ postretirement plan assets:

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	4.6	$	—	$	—	$	4.6
US stock/bond mutual funds	155.1		—		—		155.1
Total	$	159.7	$	—	$	—	$	159.7
As of September 30, 2015
Cash and cash equivalents	$	1.6	$	—	$	—	$	1.6
US stock/bond mutual funds	115.5		26.5		—		142.0
Total	$	117.1	$	26.5	$	—	$	143.6

Alagasco

The table below categorizes the fair value measurements of Alagasco’s pension plan assets:

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
Cash and cash equivalents	$	0.4	$	—	$	—	$	0.4
Stock/bond mutual funds	59.0		11.9		—		70.9
Debt Securities
US bond mutual funds	23.0		5.7		—		28.7
Total	$	82.4	$	17.6	$	—	$	100.0
As of September 30, 2015
Cash and cash equivalents	$	11.6	$	0.2	$	—	$	11.8
Stock/bond mutual fund	46.4		7.0		9.5		62.9
Debt Securities
US bond mutual funds	—		9.3		—		9.3
US government	—		21.0		—		21.0
International	—		4.0		—		4.0
Derivative instruments (b)	—		—		—		—
Total	$	58.0	$	41.5	$	9.5	$	109.0

The table below categorizes the fair value measurements of Alagasco’s postretirement plan assets:

	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2016
US stock/bond mutual fund	$	—	$	68.5	$	—	$	68.5
International fund	—		14.3		—		14.3
Total	$	—	$	82.8	$	—	$	82.8
As of September 30, 2015
US stock/bond mutual fund	—		66.3		—		66.3
International fund	—		13.4		—		13.4
Total	$	—	$	79.7	$	—	$	79.7

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INFORMATION BY OPERATING SEGMENT (Tables)

12 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Schedule of operating segment information

	Gas Utility		Gas Marketing			Other				Eliminations			Consolidated
2016
Revenues from external customers	$	1,457.2	$	78.5		$	1.6			$	—		$	1,537.3
Intersegment revenues	2.2		—			3.2				(5.4		)	—
Total Operating Revenues	1,459.4		78.5			4.8				(5.4		)	1,537.3
Operating Expenses
Gas Utility
Natural and propane gas	539.7		—			—				(47.5		)	492.2
Other operation and maintenance	379.3		—			—				(1.8		)	377.5
Depreciation and amortization	136.9		—			—				—			136.9
Taxes, other than income taxes	125.2		—			—				—			125.2
Total Gas Utility Operating Expenses	1,181.1		—			—				(49.3		)	1,131.8
Gas Marketing and Other	—		66.7		(a)	12.6			(b)	43.9			123.2
Total Operating Expenses	1,181.1		66.7			12.6				(5.4		)	1,255.0
Operating Income (Loss)	278.3		11.8			(7.8		)		—			282.3
Net Economic Earnings (Loss)	160.3		6.4			(17.6		)		—			149.1
Capital Expenditures	291.7		—			1.6				—			293.3

	Gas Utility		Gas Marketing			Other				Eliminations			Consolidated
2015
Revenues from external customers	$	1,891.8	$	82.9		$	1.7			$	—		$	1,976.4
Intersegment revenues	4.0		70.5			2.0				(76.5		)	—
Total Operating Revenues	1,895.8		153.4			3.7				(76.5		)	1,976.4
Operating Expenses
Gas Utility
Natural and propane gas	957.6		—			—				(75.2		)	882.4
Other operation and maintenance	391.6		—			—				(1.0		)	390.6
Depreciation and amortization	129.9		—			—				—			129.9
Taxes, other than income taxes	142.1		—			—				—			142.1
Total Gas Utility Operating Expenses	1,621.2		—			—				(76.2		)	1,545.0
Gas Marketing and Other	—		146.6		(a)	12.6			(b)	(0.3		)	158.9
Total Operating Expenses	1,621.2		146.6			12.6				(76.5		)	1,703.9
Operating Income (Loss)	274.6		6.8			(8.9		)		—			272.5
Net Economic Earnings (Loss)	150.4		4.2			(16.3		)		—			138.3
Capital Expenditures	284.4		—			5.4				—			289.8

	Gas Utility		Gas Marketing			Other				Eliminations			Consolidated
2014
Revenues from external customers	$	1,462.6	$	162.6		$	2.0			$	—		$	1,627.2
Intersegment revenues	5.2		84.0			1.8				(91.0		)	—
Total Operating Revenues	1,467.8		246.6			3.8				(91.0		)	1,627.2
Operating Expenses
Gas Utility
Natural and propane gas	821.8		—			—				(90.1		)	731.7
Other operation and maintenance	288.7		—			—				(0.9		)	287.8
Depreciation and amortization	82.4		—			—				—			82.4
Taxes, other than income taxes	112.0		—			—				—			112.0
Total Gas Utility Operating Expenses	1,304.9		—			—				(91.0		)	1,213.9
Gas Marketing and Other	—		226.4		(a)	20.5			(b)	—			246.9
Total Operating Expenses	1,304.9		226.4			20.5				(91.0		)	1,460.8
Operating Income (Loss)	162.9		20.2			(16.7		)		—			166.4
Net Economic Earnings (Loss)	92.8		10.2			(2.9		)		—			100.1
Capital Expenditures	168.6		—			2.4				—			171.0

(a) Depreciation and amortization for Gas Marketing are included in Gas Marketing Expenses on the Consolidated Statements of Income ($0.1 for 2016, $0.3 for 2015, and $0.4 for 2014).

(b) Depreciation, amortization, and accretion for Other are included in the Other Operating Expenses on the Consolidated Statements of Income ($0.5 for 2016, $0.6 for 2015, and $0.5 for 2014).

Total Assets at End of Year	2016			2015			2014
Gas Utility	$	5,191.9		$	4,686.2		$	4,520.0
Gas Marketing	205.0			160.6			156.7
Other	1,842.4			1,560.2			1,575.7
Eliminations	(1,161.9		)	(1,116.8		)	(1,178.4		)
Total Assets	$	6,077.4		$	5,290.2		$	5,074.0

Schedule of the reconciliation of consolidated net economic earnings to consolidated net income

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings	2016			2015			2014
Net Income (GAAP)	$	144.2		$	136.9		$	84.6
Unrealized gain on energy-related derivatives	(0.1		)	(2.8		)	(1.6		)
Lower of cost or market inventory adjustments	0.2			0.4			(1.1		)
Realized (gain) loss on economic hedges prior      to the sale of the physical commodity	(1.6		)	2.4			(0.4		)
Acquisition, divestiture and restructuring activities	9.2			9.8			29.5
Gain on sale of property	—			(7.6		)	—
Income tax effect of adjustments	(2.8		)	(0.8		)	(10.9		)
Net Economic Earnings	$	149.1		$	138.3		$	100.1

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REGULATORY MATTERS (Tables)

12 Months Ended

Sep. 30, 2016

Regulated Operations [Abstract]

Schedule of regulatory assets

The following regulatory assets and regulatory liabilities were reflected in the Balance Sheets as of September 30, 2016 and 2015. Unamortized Purchased Gas Adjustments are also included below, which are reported separately in the current assets and liabilities sections of each balance sheet.

	Spire				Laclede Gas				Alagasco
	2016		2015		2016		2015		2016		2015
Regulatory Assets:
Current:
Pension and postretirement benefit costs	$	27.0	$	22.0	$	20.2	$	15.5	$	6.8	$	6.5
Unamortized purchased gas adjustments	49.7		12.9		43.1		12.9		5.6		—
Other	17.2		5.6		3.7		0.7		8.1		4.9
Total Current Regulatory Assets	93.9		40.5		67.0		29.1		20.5		11.4
Noncurrent:
Future income taxes due from customers	151.3		134.5		151.3		134.5		—		—
Pension and postretirement benefit costs	487.9		448.7		375.7		368.0		98.9		80.7
Cost of removal	130.6		78.9		—		—		130.6		78.9
Purchased gas costs	12.6		24.1		12.6		24.1		—		—
Energy efficiency	25.5		22.3		25.5		22.3		—		—
Other	30.1		29.1		24.7		24.7		1.2		4.0
Total Noncurrent Regulatory Assets	838.0		737.6		589.8		573.6		230.7		163.6
Total Regulatory Assets	$	931.9	$	778.1	$	656.8	$	602.7	$	251.2	$	175.0
Regulatory Liabilities:
Current:
RSE adjustment	$	7.5	$	12.2	$	—	$	—	$	5.0	$	12.2
Unbilled service margin	5.9		6.4		—		—		5.9		6.4
Refundable negative salvage	9.3		10.8		—		—		9.3		10.8
Unamortized purchased gas adjustments	1.7		28.2		—		—		—		28.2
Other	6.2		3.0		1.3		0.6		2.5		2.4
Total Current Regulatory Liabilities	30.6		60.6		1.3		0.6		22.7		60.0
Noncurrent:
Postretirement liabilities	28.9		28.9		—		—		28.9		28.9
Refundable negative salvage	9.4		16.2		—		—		9.4		16.2
Accrued cost of removal	74.8		58.7		55.1		58.7		—		—
Other	17.6		15.5		12.2		11.9		3.4		3.6
Total Noncurrent Regulatory Liabilities	130.7		119.3		67.3		70.6		41.7		48.7
Total Regulatory Liabilities	$	161.3	$	179.9	$	68.6	$	71.2	$	64.4	$	108.7

A portion of the Company’s regulatory assets are not earning a return and are shown in the schedule below:

	Spire				Laclede Gas
	2016		2015		2016		2015
Future income taxes due from customers	$	151.3	$	134.5	$	151.3	$	134.5
Pension and postretirement benefit costs	240.6		223.7		240.6		223.7
Compensated absences	—		—		—		—
Other	12.9		14.2		12.9		14.2
Total Regulatory Assets Not Earning a Return	$	404.8	$	372.4	$	404.8	$	372.4

Schedule of regulatory liabilities

The following regulatory assets and regulatory liabilities were reflected in the Balance Sheets as of September 30, 2016 and 2015. Unamortized Purchased Gas Adjustments are also included below, which are reported separately in the current assets and liabilities sections of each balance sheet.

	Spire				Laclede Gas				Alagasco
	2016		2015		2016		2015		2016		2015
Regulatory Assets:
Current:
Pension and postretirement benefit costs	$	27.0	$	22.0	$	20.2	$	15.5	$	6.8	$	6.5
Unamortized purchased gas adjustments	49.7		12.9		43.1		12.9		5.6		—
Other	17.2		5.6		3.7		0.7		8.1		4.9
Total Current Regulatory Assets	93.9		40.5		67.0		29.1		20.5		11.4
Noncurrent:
Future income taxes due from customers	151.3		134.5		151.3		134.5		—		—
Pension and postretirement benefit costs	487.9		448.7		375.7		368.0		98.9		80.7
Cost of removal	130.6		78.9		—		—		130.6		78.9
Purchased gas costs	12.6		24.1		12.6		24.1		—		—
Energy efficiency	25.5		22.3		25.5		22.3		—		—
Other	30.1		29.1		24.7		24.7		1.2		4.0
Total Noncurrent Regulatory Assets	838.0		737.6		589.8		573.6		230.7		163.6
Total Regulatory Assets	$	931.9	$	778.1	$	656.8	$	602.7	$	251.2	$	175.0
Regulatory Liabilities:
Current:
RSE adjustment	$	7.5	$	12.2	$	—	$	—	$	5.0	$	12.2
Unbilled service margin	5.9		6.4		—		—		5.9		6.4
Refundable negative salvage	9.3		10.8		—		—		9.3		10.8
Unamortized purchased gas adjustments	1.7		28.2		—		—		—		28.2
Other	6.2		3.0		1.3		0.6		2.5		2.4
Total Current Regulatory Liabilities	30.6		60.6		1.3		0.6		22.7		60.0
Noncurrent:
Postretirement liabilities	28.9		28.9		—		—		28.9		28.9
Refundable negative salvage	9.4		16.2		—		—		9.4		16.2
Accrued cost of removal	74.8		58.7		55.1		58.7		—		—
Other	17.6		15.5		12.2		11.9		3.4		3.6
Total Noncurrent Regulatory Liabilities	130.7		119.3		67.3		70.6		41.7		48.7
Total Regulatory Liabilities	$	161.3	$	179.9	$	68.6	$	71.2	$	64.4	$	108.7

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Aggregate Rental Expense and Annual Minimum Rental Commitments

Aggregate rental expense and annual minimum rental commitments under all leases having an initial or remaining non-cancelable term of more than one year are shown below:

	Aggregate Rental Expense						Minimum Rental Commitments
	2016		2015		2014		2017		2018		2019		2020		2021		Later		Total
Spire	$	11.9	$	14.1	$	6.7	$	10.5	$	7.5	$	7.3	$	6.2	$	6.0	$	53.4	$	90.9
Laclede Gas	4.3		7.6		6.3		2.5		0.9		0.9		0.3		0.1		—		4.7
Alagasco	3.7		4.0		2.0		3.9		2.5		2.5		2.1		2.1		4.9		18.0

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INTERIM FINANCIAL INFORMATION (UNAUDITED) (Tables)

12 Months Ended

Sep. 30, 2016

Quarterly Financial Information [Line Items]

Schedule of Quarterly Financial Information

Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2016
Total Operating Revenues	$	399.4	$	609.3	$	249.3	$	279.3
Operating Income (Loss)	87.0		167.7		35.3		(7.7		)
Net Income (Loss)	46.9		100.8		10.7		(14.2		)
Basic Earnings (Loss) Per Share of Common Stock	$	1.08	$	2.32	$	0.24	$	(0.31	)
Diluted Earnings (Loss) Per Share of Common Stock	$	1.08	$	2.31	$	0.24	$	(0.31	)
Fiscal Year 2015
Total Operating Revenues	$	619.6	$	877.4	$	275.2	$	204.2
Operating Income (Loss)	87.3		157.7		36.0		(8.5		)
Net Income (Loss)	47.1		94.4		14.1		(18.7		)
Basic Earnings (Loss) Per Share of Common Stock	$	1.09	$	2.18	$	0.32	$	(0.43	)
Diluted Earnings (Loss) Per Share of Common Stock	$	1.09	$	2.18	$	0.32	$	(0.43	)

Laclede Gas

Quarterly Financial Information [Line Items]

Schedule of Quarterly Financial Information

Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2016
Total Operating Revenues	$	317.2	$	446.7	$	179.3	$	144.3
Operating Income	65.1		87.0		29.4		5.4
Net Income (Loss)	39.4		54.3		13.9		(1.7		)
Fiscal Year 2015
Total Operating Revenues	$	462.4	$	615.7	$	187.5	$	151.0
Operating Income	64.8		80.6		34.5		5.5
Net Income (Loss)	39.0		49.9		20.0		(3.6		)

Alagasco

Quarterly Financial Information [Line Items]

Schedule of Quarterly Financial Information

Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2016
Total Operating Revenues	$	82.3	$	166.0	$	74.0	$	46.2
Operating Income (Loss)	18.9		80.4		9.3		(17.1		)
Net Income (Loss)	9.9		48.1		4.0		(8.8		)
Fiscal Year 2015
Total Operating Revenues	$	120.0	$	233.3	$	73.7	$	52.2
Operating Income (Loss)	20.4		77.4		3.9		(12.5		)
Net Income (Loss)	10.6		46.3		0.7		(9.6		)

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details)		9 Months Ended	12 Months Ended
	Jun. 01, 2010	Sep. 30, 2014 USD ($)	Sep. 30, 2016 USD ($) operating_segment change	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)
Related Party Transaction [Line Items]
Number of operating segments | operating_segment			2
Utility Plant, Depreciation and Amortization [Abstract]
Capital expenditures			$ 293,300,000	$ 289,800,000	$ 171,000,000
Amount by which the replacement cost exceeds (less than) the cost basis value of stored gas inventories			$ 11,400,000	20,400,000
Number of months of the original maturity of debt instruments purchased			3 months
Finance receivable, net			$ 11,800,000	11,200,000
Retrospective Effect is ASU had been Adopted | ASU 2015-03 | New Accounting Pronouncement, Early Adoption, Effect | Other Deferred Charges
Utility Plant, Depreciation and Amortization [Abstract]
Deferred finance costs			(13,200,000)	(13,000,000)
Retrospective Effect is ASU had been Adopted | ASU 2015-03 | New Accounting Pronouncement, Early Adoption, Effect | Long-Term Debt
Utility Plant, Depreciation and Amortization [Abstract]
Deferred finance costs			$ 13,200,000	$ 13,000,000
Laclede Gas
Utility Plant, Depreciation and Amortization [Abstract]
Average annual depreciation and amortization expense percentage		3.00%	3.00%	3.00%	3.00%
Capital expenditures			$ 197,800,000	$ 198,600,000	$ 163,000,000
Accruals for capital expenditures			$ 14,800,000	9,600,000	3,000,000
Number of PGA discretionary changes | change			3
Months between PGA discretionary changes			2 months
Cost savings retention percentage			10.00%
Maximum amount of cost savings allowable			$ 3,000,000.0
Accrued unbilled revenues			26,100,000	27,600,000
Laclede Gas | Retrospective Effect is ASU had been Adopted | ASU 2015-03 | New Accounting Pronouncement, Early Adoption, Effect | Other Deferred Charges
Utility Plant, Depreciation and Amortization [Abstract]
Deferred finance costs			(4,200,000)	(4,800,000)
Laclede Gas | Retrospective Effect is ASU had been Adopted | ASU 2015-03 | New Accounting Pronouncement, Early Adoption, Effect | Long-Term Debt
Utility Plant, Depreciation and Amortization [Abstract]
Deferred finance costs			4,200,000	4,800,000
Alagasco
Utility Plant, Depreciation and Amortization [Abstract]
Capital expenditures		$ 46,200,000	93,400,000	85,800,000	$ 46,200,000
Accruals for capital expenditures		$ 5,000,000	$ 6,800,000	3,100,000
Composite depreciation rate	3.10%		3.10%
Current refundable negative salvage costs to customers			$ 9,300,000
Noncurrent refundable negative salvage costs to customers			$ 18,700,000
Noncurrent refundable negative salvage costs period			3 years
Accrued unbilled revenues			$ 5,900,000	6,400,000
Threshold period past due for collection			90 days
Threshold period past due for write-off of financing receivable			12 months
Write off on an allowance for credit losses			$ 400,000	400,000
Alagasco | Retrospective Effect is ASU had been Adopted | ASU 2015-03 | New Accounting Pronouncement, Early Adoption, Effect | Other Deferred Charges
Utility Plant, Depreciation and Amortization [Abstract]
Deferred finance costs			(2,600,000)	(2,400,000)
Alagasco | Retrospective Effect is ASU had been Adopted | ASU 2015-03 | New Accounting Pronouncement, Early Adoption, Effect | Long-Term Debt
Utility Plant, Depreciation and Amortization [Abstract]
Deferred finance costs			2,600,000	2,400,000
Alagasco | Financing Receivables, Equal to Greater than 90 Days Past Due
Utility Plant, Depreciation and Amortization [Abstract]
Finance receivable 90 days past due			$ 400,000	$ 400,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Asset retirement obligations [Roll forward]
Asset retirement obligations, beginning of year	$ 159.2	$ 99.2
Liabilities incurred during the period	4.1	2.3
Liabilities settled during the period	(9.5)	(2.0)
Accretion	13.2	4.5
Revisions in estimated cash flows	27.5	55.2
Asset retirement obligations, end of year	206.4	159.2
Laclede Gas
Asset retirement obligations [Roll forward]
Asset retirement obligations, beginning of year	72.4	71.2
Liabilities incurred during the period	1.2	0.6
Liabilities settled during the period	(1.9)	(1.9)
Accretion	3.5	3.4
Revisions in estimated cash flows	0.0	(0.9)
Asset retirement obligations, end of year	75.2	72.4
Alagasco
Asset retirement obligations [Roll forward]
Asset retirement obligations, beginning of year	86.6	27.7
Liabilities incurred during the period	2.9	1.7
Liabilities settled during the period	(6.8)	(0.1)
Accretion	9.7	1.1
Revisions in estimated cash flows	27.7	56.2
Asset retirement obligations, end of year	120.1	86.6
EnergySouth
Asset retirement obligations [Roll forward]
Addition of EnergySouth asset retirement obligations	11.9	0.0
EnergySouth | Laclede Gas
Asset retirement obligations [Roll forward]
Addition of EnergySouth asset retirement obligations	0.0	0.0
EnergySouth | Alagasco
Asset retirement obligations [Roll forward]
Addition of EnergySouth asset retirement obligations	$ 0.0	$ 0.0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Off System Sales (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2017
Eastern Missouri | First $2.0
Off System Sales [Line Items]
Pre-tax Income	$ 2.0
Customer Share	100.00%
Company Share	0.00%
Eastern Missouri | First $2.0 | Scenario, Forecast
Off System Sales [Line Items]
Customer Share		85.00%
Company Share		15.00%
Eastern Missouri | Next $2.0
Off System Sales [Line Items]
Pre-tax Income	$ 2.0
Customer Share	80.00%
Company Share	20.00%
Eastern Missouri | Next $2.0
Off System Sales [Line Items]
Pre-tax Income	$ 2.0
Customer Share	75.00%
Company Share	25.00%
Eastern Missouri | Amounts exceeding $6.0
Off System Sales [Line Items]
Pre-tax Income	$ 6.0
Customer Share	70.00%
Company Share	30.00%
Western Missouri | First $1.2
Off System Sales [Line Items]
Pre-tax Income	$ 1.2
Customer Share	85.00%
Company Share	15.00%
Western Missouri | Next $1.2
Off System Sales [Line Items]
Pre-tax Income	$ 1.2
Customer Share	80.00%
Company Share	20.00%
Western Missouri | Next $1.2
Off System Sales [Line Items]
Pre-tax Income	$ 1.2
Customer Share	75.00%
Company Share	25.00%
Western Missouri | Amounts exceeding $3.6
Off System Sales [Line Items]
Pre-tax Income	$ 3.6
Customer Share	70.00%
Company Share	30.00%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Changes in Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Goodwill [Roll Forward]
Beginning balance	$ 946.0	$ 937.8	$ 247.1
Adjustments to finalize acquisition		8.2	(36.9)
Acquisition	218.9		727.6
Ending balance	1,164.9	946.0	937.8
Operating Segments | Gas Utility
Goodwill [Roll Forward]
Beginning balance	210.2	210.2	247.1
Adjustments to finalize acquisition		0.0	(36.9)
Acquisition	0.0		0.0
Ending balance	210.2	210.2	210.2
Operating Segments | Gas Marketing
Goodwill [Roll Forward]
Beginning balance	0.0	0.0	0.0
Adjustments to finalize acquisition		0.0	0.0
Acquisition	0.0		0.0
Ending balance	0.0	0.0	0.0
Other
Goodwill [Roll Forward]
Beginning balance	735.8	727.6	0.0
Adjustments to finalize acquisition		8.2	0.0
Acquisition	218.9		727.6
Ending balance	$ 954.7	$ 735.8	$ 727.6

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Gross Receipts and Sales Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Schedule of Gross Receipts Taxes [Line Items]
Gross Receipts taxes recorded in regulated gas distribution operating revenues	$ 75.5	$ 97.3	$ 77.5
Laclede Gas
Schedule of Gross Receipts Taxes [Line Items]
Gross Receipts taxes recorded in regulated gas distribution operating revenues	57.4	74.5	76.3
Alagasco
Schedule of Gross Receipts Taxes [Line Items]
Gross Receipts taxes recorded in regulated gas distribution operating revenues	$ 17.9	$ 22.6	$ 20.6

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Transactions with Affiliates (Details) - Affiliated Entity - Regulated Operation - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Laclede Gas | Laclede Energy Resources
Related Party Transaction [Line Items]
Revenue from related parties	$ 1.9	$ 4.0	$ 5.1
Laclede Energy Resources | Laclede Gas
Related Party Transaction [Line Items]
Revenue from related parties	46.3	74.1	89.1
Laclede Risk Services | Laclede Gas
Related Party Transaction [Line Items]
Revenue from related parties	$ 1.8	$ 1.0	$ 0.6

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ACQUISITIONS - Narrative (Details) - USD ($) $ in Millions				12 Months Ended
	Sep. 12, 2016	Jan. 06, 2015	Aug. 31, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Business Acquisition [Line Items]
Payments to acquire businesses, net of cash acquired				$ (317.7)	$ 0.0	$ 0.0
Goodwill				$ 1,164.9	$ 946.0	$ 937.8	$ 247.1
Alagasco
Business Acquisition [Line Items]
Percentage of voting interest acquired			100.00%
Payments to acquire businesses, net of cash acquired		$ (1,313.4)	$ (1,305.2)
Payments for final reconciliation of acquisition		$ (8.2)
Goodwill			735.8
Goodwill, expected to be tax deductible			$ 717.6
EnergySouth
Business Acquisition [Line Items]
Percentage of voting interest acquired	100.00%
Payments to acquire businesses, net of cash acquired	$ (317.7)
Goodwill	$ 218.9

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ACQUISITIONS - Summary of Consideration Paid, Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 12, 2016	Sep. 30, 2015	Sep. 30, 2014	Aug. 31, 2014	Sep. 30, 2013
Business Acquisition [Line Items]
Goodwill	$ 1,164.9		$ 946.0	$ 937.8		$ 247.1
Alagasco
Business Acquisition [Line Items]
Utility plant					$ 892.7
Cash					12.1
Other current assets					99.4
Deferred tax assets					282.0
Other assets					143.4
Long-term debt					(249.8)
Current portion of long-term debt					(15.0)
Other current liabilities					(173.4)
Deferred tax liabilities					0.0
Other liabilities					(130.4)
Total identifiable net assets					861.0
Goodwill					735.8
Deferred tax elimination (Spire)					(271.3)
Consideration (cash)					$ 1,325.5
EnergySouth
Business Acquisition [Line Items]
Utility plant		$ 199.5
Cash		2.0
Other current assets		17.5
Deferred tax assets		0.0
Other assets		79.8
Long-term debt		(67.0)
Current portion of long-term debt		0.0
Other current liabilities		(42.7)
Deferred tax liabilities		(35.5)
Other liabilities		(52.8)
Total identifiable net assets		100.8
Goodwill		218.9
Deferred tax elimination (Spire)		0.0
Consideration (cash)		$ 319.7

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ACQUISITIONS - Pro Forma Information, Revenues and Earnings (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Alagasco and EnergySouth
Business Acquisition [Line Items]
Total Operating Revenues	$ 1,632.4	$ 2,081.6	$ 2,187.1
Net Income	$ 153.9	$ 143.6	$ 133.5
Basic earnings (loss) per share (in dollars per share)	$ 3.48	$ 3.32	$ 3.11
Diluted earnings (loss) per share (in dollars per share)	$ 3.46	$ 3.31	$ 3.10
Alagasco
Business Acquisition [Line Items]
Pro forma, Total Operating Revenues	$ 368.5	$ 479.2	$ 19.7
Pro forma, Net Income (Loss)	$ 53.2	$ 48.0	$ (2.9)
Pro forma, Earnings (Loss) Per Share (in dollars per share)	$ 1.20	$ 1.11	$ (0.08)
EnergySouth
Business Acquisition [Line Items]
Pro forma, Total Operating Revenues	$ 3.3
Pro forma, Net Income (Loss)	$ (0.2)
Pro forma, Earnings (Loss) Per Share (in dollars per share)	$ 0.00

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STOCK-BASED COMPENSATION - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period, minimum	3 years
Number of shares of common stock that may be issued (in shares)	1,000,000
Stock Option Awards [Abstract]
Closing price of common stock (in dollars per share)	$ 63.74
Total unrecognized compensation costs	$ 9.2
Weighted average period for recognition of unrecognized compensation costs	1 year 9 months 18 days
Restricted Stock Awards
Restricted Stock Awards [Abstract]
Vested (in shares)	107,238	128,135	88,533
Vested restricted stock withheld for tax withholding obligations (in shares)	30,712	31,688	23,776
Vested restricted stock withheld for tax withholding obligations, weighted average price (in dollars per share)	$ 57.29	$ 50.65	$ 45.96
Fair value, restricted stock	$ 6.3	$ 6.4	$ 4.1
Actual tax benefit realized	$ 2.4	$ 2.4	$ 1.6
Restricted Stock Awards | Performance Vesting
Restricted Stock Awards [Abstract]
Granted (in shares)	199,140
Granted, weighted average grant date fair value (in dollars per share)	$ 45.95
Vested (in shares)	62,593
Restricted Stock Awards | Performance Vesting | Executive Officers and Key Employees
Restricted Stock Awards [Abstract]
Granted, weighted average grant date fair value (in dollars per share)		$ 36.69	$ 37.21
Restricted Stock Awards | Time Vesting
Restricted Stock Awards [Abstract]
Granted (in shares)	48,730
Granted, weighted average grant date fair value (in dollars per share)	$ 60.65
Vested (in shares)	44,645
Restricted Stock Awards | Time Vesting | Executive Officers and Key Employees
Restricted Stock Awards [Abstract]
Granted (in shares)	35,210
Granted, weighted average grant date fair value (in dollars per share)	$ 59.40	50.90	45.66
Restricted Stock Awards | Time Vesting | Non Employee Directors
Restricted Stock Awards [Abstract]
Granted (in shares)	13,520
Granted, weighted average grant date fair value (in dollars per share)	$ 63.93	$ 54.66	$ 46.02
Stock Option Awards
Stock Option Awards [Abstract]
Cash received from the exercise of stock options	$ 0.7	$ 1.5	$ 1.7
Intrinsic value of exercised	$ 0.7	$ 0.9	$ 0.9

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STOCK-BASED COMPENSATION - Restricted Stock and Restricted Stock Unit Activity (Details) - Restricted Stock Awards - $ / shares	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Shares/ Units
Vested (in shares)	(107,238)	(128,135)	(88,533)
Performance Vesting
Shares/ Units
Nonvested at beginning of period (in shares)	397,270
Granted (in shares)	199,140
Vested (in shares)	(62,593)
Forfeited (in shares)	(23,234)
Nonvested at end of period (in shares)	510,583	397,270
Weighted Average Grant Date Fair Value Per Share
Nonvested at beginning of period (in dollars per share)	$ 36.28
Granted (in dollars per share)	45.95
Vested (in dollars per share)	35.29
Forfeited (in dollars per share)	30.96
Nonvested at end of period (in dollars per share)	$ 40.37	$ 36.28
Time Vesting
Shares/ Units
Nonvested at beginning of period (in shares)	129,304
Granted (in shares)	48,730
Vested (in shares)	(44,645)
Forfeited (in shares)	(610)
Nonvested at end of period (in shares)	132,779	129,304
Weighted Average Grant Date Fair Value Per Share
Nonvested at beginning of period (in dollars per share)	$ 44.89
Granted (in dollars per share)	60.65
Vested (in dollars per share)	47.30
Forfeited (in dollars per share)	53.12
Nonvested at end of period (in dollars per share)	$ 49.83	$ 44.89

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STOCK-BASED COMPENSATION - Stock Option Awards Activity (Details) - Stock Option Awards	12 Months Ended
	Sep. 30, 2016 $ / shares shares
Stock Options
Outstanding at beginning of period (in shares) | shares	28,500
Exercised (in shares) | shares	(27,750)
Forfeited (in shares) | shares	(750)
Outstanding at end of period (in shares) | shares	0
Weighted Average Exercise Price Per Share
Outstanding at beginning of period (in dollars per share) | $ / shares	$ 33.65
Exercised (in dollars per share) | $ / shares	33.66
Forfeited (in dollars per share) | $ / shares	33.45
Outstanding at end of period (in dollars per share) | $ / shares	$ 0.00

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STOCK-BASED COMPENSATION - Fair Value Measurement Assumptions (Details)	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Risk free interest rate	1.14%	0.83%	0.53%
Expected dividend yield of stock	0.00%	0.00%	0.00%
Expected volatility of stock	15.00%	14.00%	18.00%
Vesting period	2 years 9 months 18 days	2 years 9 months 18 days	2 years 9 months 18 days

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STOCK-BASED COMPENSATION - Compensation Costs Recognized (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Total equity compensation cost	$ 6.7	$ 6.7	$ 5.8
Compensation cost capitalized	(2.2)	(1.8)	(1.8)
Compensation cost recognized in net income	4.5	4.9	4.0
Income tax benefit recognized in net income	(1.7)	(1.9)	(1.5)
Compensation cost recognized in net income, net of income tax	$ 2.8	$ 3.0	$ 2.5

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EARNINGS PER COMMON SHARE (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		1 Months Ended	3 Months Ended								12 Months Ended
	Jun. 11, 2014	Jun. 30, 2014	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Basic EPS:
Net income			$ (14.2)	$ 10.7	$ 100.8	$ 46.9	$ (18.7)	$ 14.1	$ 94.4	$ 47.1	$ 144.2	$ 136.9	$ 84.6
Less: Income allocated to participating securities											0.5	0.5	0.3
Net Income Available to Common Shareholders											$ 143.7	$ 136.4	$ 84.3
Weighted Average Shares Outstanding, Basic (in Shares)											44.1	43.2	35.8
Earnings Per Share of Common Stock (in dollars per share)			$ (0.31)	$ 0.24	$ 2.32	$ 1.08	$ (0.43)	$ 0.32	$ 2.18	$ 1.09	$ 3.26	$ 3.16	$ 2.36
Diluted EPS:
Net income			$ (14.2)	$ 10.7	$ 100.8	$ 46.9	$ (18.7)	$ 14.1	$ 94.4	$ 47.1	$ 144.2	$ 136.9	$ 84.6
Less: Income allocated to participating securities											0.5	0.5	0.3
Net Income Available to Common Shareholders											$ 143.7	$ 136.4	$ 84.3
Weighted Average Shares Outstanding, Basic (in Shares)											44.1	43.2	35.8
Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units (in shares)											0.2	0.1	0.1
Weighted Average Diluted Shares (in shares)											44.3	43.3	35.9
Earnings Per Share of Common Stock (in dollars per share)			$ (0.31)	$ 0.24	$ 2.31	$ 1.08	$ (0.43)	$ 0.32	$ 2.18	$ 1.09	$ 3.24	$ 3.16	$ 2.35
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Equity units, contract annual rate	4.75%	2.00%
Restricted stock and stock units subject to performance and/or market conditions
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Outstanding shares excluded from calculation of diluted EPS (in shares)											0.3	0.3	0.3

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STOCKHOLDERS' EQUITY - Narrative (Details) $ / shares in Units, Equity_Security in Thousands			1 Months Ended		12 Months Ended
	May 17, 2016 USD ($) shares	Jun. 11, 2014 USD ($) Equity_Security	Apr. 30, 2017 shares	Jun. 30, 2014 USD ($) shares $ / shares	Sep. 30, 2016 USD ($) $ / shares shares	Sep. 30, 2015 USD ($) $ / shares shares	Sep. 30, 2014 USD ($) shares	Nov. 11, 2016 shares	Feb. 10, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 20, 2014 shares
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Number of equity units issued (in shares)		2,875		2,875,000
Proceeds from convertible debt | $		$ 143,800,000
Stated value per Corporate Unit (in dollars per share) | $ / shares				$ 50
Common stock, par value (in dollars per share) | $ / shares				$ 1.00	$ 1	$ 1
Percentage of beneficial ownership interest in Subordinated Notes				5.00%
Stated principal amount of Subordinated Notes | $				$ 1,000
Interest rate on Subordinated borrowing				2.00%
Issuance of stock (in shares)	2,185,000
Shares reserved for issuance under the stock purchase contracts (in shares)					4,200,000
SEC effective shelf registration Form S-3 sale and issuance authorization under the dividend reinvestment and stock purchase program (in shares)					168,698						168,698
SEC effective shelf registration Form S-3 remaining and available for issuance under the dividend reinvestment and stock purchase program (in shares)					106,535
Issuance of common stock | $	$ 133,200,000				$ 133,200,000		$ 456,800,000
Preferred stock shares authorized (in shares)					5,000,000	5,000,000
Preferred stock shares issued (in shares)					0	0
Preferred stock shares outstanding (in shares)					0	0
Dividend payment restriction formula component - fixed amount | $					$ 8,000,000.0
Retained earnings available to pay dividends in period | $					$ 916,800,000	$ 891,700,000
Laclede Gas
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Common stock, par value (in dollars per share) | $ / shares					$ 1	$ 1
Issuance of common stock | $							$ 1,100,000
Preferred stock shares authorized (in shares)					1,480,000	1,480,000
Regulatory preferred stock and debt securities issuance, amount authorized | $					$ 300,000,000				$ 300,000,000.0	$ 518,000,000.0
Laclede Gas | Affiliated Entity
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Issuance of stock (in shares)					0	0	28
Issuance of common stock | $							$ 1,100,000
Alagasco
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Common stock, par value (in dollars per share) | $ / shares					$ 0.01	$ 0.01
Preferred stock shares authorized (in shares)					120,000	120,000
Preferred stock shares issued (in shares)					0	0
Preferred stock shares outstanding (in shares)					0	0
Subsequent Event
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
SEC effective shelf registration Form S-3 remaining and available for issuance under the dividend reinvestment and stock purchase program (in shares)								101,439
Scenario, Forecast | Minimum
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Issuance of stock (in shares)			2,500,000
Scenario, Forecast | Maximum
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Issuance of stock (in shares)			3,100,000
Junior Subordinated Debt
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Proceeds from convertible debt | $				$ 143,800,000

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STOCKHOLDERS' EQUITY - Stock Purchase Obligation (Details)	12 Months Ended
	Sep. 30, 2016 shares / contract $ / shares	Jun. 30, 2014 $ / shares
Stock Purchase Obligation [Line Items]
Stated value per Corporate Unit (in dollars per share)		$ 50
Equal to or greater than $57.8125
Stock Purchase Obligation [Line Items]
Market value per share of common stock (in dollars per share)	$ 57.8125
Number of shares to be purchased per purchase contract | shares / contract	0.8649
Less than $57.8125, but greater than $46.25 | Minimum
Stock Purchase Obligation [Line Items]
Market value per share of common stock (in dollars per share)	$ 46.25
Less than $57.8125, but greater than $46.25 | Maximum
Stock Purchase Obligation [Line Items]
Market value per share of common stock (in dollars per share)	57.8125
Less than or equal to $46.25
Stock Purchase Obligation [Line Items]
Market value per share of common stock (in dollars per share)	$ 46.25
Number of shares to be purchased per purchase contract | shares / contract	1.0811

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STOCKHOLDERS' EQUITY - Schedule of Company's Equity Units (Details) shares in Thousands, Equity_Security in Thousands, $ in Millions		1 Months Ended	12 Months Ended
	Jun. 11, 2014 USD ($) Equity_Security	Jun. 30, 2014 shares	Sep. 30, 2014 USD ($)
Stockholders' Equity Note [Abstract]
Number of equity units issued (in shares)	2,875	2,875
Total Net Proceeds	$ 139.4
Total Long-term Debt	$ 143.8
RSN Annual Interest Rate	2.00%
Stock Purchase Contract Annual Rate	4.75%	2.00%
Stock Purchase Contract Liability	$ 19.7		$ 19.7

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STOCKHOLDERS' EQUITY - Schedule of Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE	$ 1,573.6	$ 1,508.4	$ 1,046.3
Other comprehensive (loss) income	(2.2)	(0.3)	(0.9)
BALANCE	1,768.2	1,573.6	1,508.4
Laclede Gas
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE	1,037.8	1,007.8	973.9
Other comprehensive (loss) income	(0.1)	0.2	0.2
BALANCE	1,068.5	1,037.8	1,007.8
Net Unrealized Gains (Losses) on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE	(0.4)	0.2
Other comprehensive (loss) income	(1.9)	(0.6)
BALANCE	(2.3)	(0.4)	0.2
Net Unrealized Gains (Losses) on Cash Flow Hedges | Laclede Gas
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE	(0.2)	0.0
Other comprehensive (loss) income	0.3	(0.2)
BALANCE	0.1	(0.2)	0.0
Defined Benefit Pension and Other Postretirement Benefit Plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE	(1.5)	(1.9)
Other comprehensive (loss) income	(0.3)	0.4
BALANCE	(1.8)	(1.5)	(1.9)
Defined Benefit Pension and Other Postretirement Benefit Plans | Laclede Gas
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE	(1.5)	(1.9)
Other comprehensive (loss) income	(0.3)	0.4
BALANCE	(1.8)	(1.5)	(1.9)
Net Unrealized Losses on Available for Sale Securities
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE	(0.1)	0.0
Other comprehensive (loss) income	0.0	(0.1)
BALANCE	(0.1)	(0.1)	0.0
Net Unrealized Losses on Available for Sale Securities | Laclede Gas
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE	0.0	0.0
Other comprehensive (loss) income	(0.1)	0.0
BALANCE	(0.1)	0.0	0.0
AOCI
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE	(2.0)	(1.7)	(0.8)
Other comprehensive (loss) income	(2.2)	(0.3)	(0.9)
BALANCE	(4.2)	(2.0)	(1.7)
AOCI | Laclede Gas
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE	(1.7)	(1.9)	(2.1)
Other comprehensive (loss) income	(0.1)	0.2	0.2
BALANCE	$ (1.8)	$ (1.7)	$ (1.9)

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LONG-TERM DEBT - Maturities of Long-term Debt (Details) $ in Millions	Sep. 30, 2016 USD ($)
Maturities on long-term debt [Abstract]
2017	$ 250.0
2018	100.0
2019	180.0
2020	40.0
2021	55.0
Laclede Gas
Maturities on long-term debt [Abstract]
2017	0.0
2018	100.0
2019	50.0
2020	0.0
2021	0.0
Alagasco
Maturities on long-term debt [Abstract]
2017	0.0
2018	0.0
2019	0.0
2020	40.0
2021	$ 0.0

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LONG-TERM DEBT - Narrative (Details) - USD ($)				12 Months Ended
	Dec. 01, 2015	Sep. 15, 2015	Jan. 15, 2015	Sep. 30, 2016	Nov. 11, 2016	Sep. 09, 2016	Feb. 10, 2016	Sep. 30, 2015	Jun. 30, 2015	Feb. 03, 2015	Nov. 03, 2014	Aug. 19, 2014	Jun. 20, 2014	Jun. 11, 2014
Debt Instrument [Line Items]
Long-term debt issued amount												$ 625,000,000.0
Stated interest rate on debt issued														2.00%
Long-term debt amount bearing variable interest rate				$ 250,000,000
Long-term debt				$ 2,085,800,000
SEC effective shelf registration Form S-3 sale and issuance authorization under the dividend reinvestment and stock purchase program (in shares)				168,698									168,698
SEC effective shelf registration Form S-3 remaining and available for issuance under the dividend reinvestment and stock purchase program (in shares)				106,535
Percent of common stock equity				49.10%				47.00%
Percent of long-term debt				50.90%				53.00%
Debt instrument, principal outstanding, excluding current portion				$ 1,833,700,000				$ 1,771,500,000
Subsequent Event
Debt Instrument [Line Items]
SEC effective shelf registration Form S-3 remaining and available for issuance under the dividend reinvestment and stock purchase program (in shares)					101,439
Senior Notes
Debt Instrument [Line Items]
Long-term debt				1,942,000,000
Senior Notes | Unsecured Series 2016 Senior Notes
Debt Instrument [Line Items]
Long-term debt issued amount						$ 165,000,000.0
Senior Notes | Unsecured Series 2016 Senior Notes, Tranche A
Debt Instrument [Line Items]
Long-term debt issued amount						$ 35,000,000
Stated interest rate on debt issued						2.52%
Senior Notes | Unsecured Series 2016 Senior Notes, Tranche B
Debt Instrument [Line Items]
Long-term debt issued amount						$ 130,000,000
Stated interest rate on debt issued						3.13%
Senior Notes | No Call Options
Debt Instrument [Line Items]
Long-term debt				25,000,000
Senior Notes | Make Whole Call Options
Debt Instrument [Line Items]
Long-term debt				937,000,000
Senior Notes | One to six months prior to maturity | Subject to Callable at Par
Debt Instrument [Line Items]
Long-term debt				$ 730,000,000
Redemption period prior to maturity, minimum				1 month
Redemption period prior to maturity, maximum				6 months
Senior Notes | One year prior to maturity | Subject to Callable at Par
Debt Instrument [Line Items]
Long-term debt				$ 250,000,000
Junior Subordinated Debt | 2.0% Series A Remarketable Subordinated Notes, due April 1, 2022
Debt Instrument [Line Items]
Stated interest rate on debt issued				2.00%
Long-term debt				$ 143,800,000
Laclede Gas
Debt Instrument [Line Items]
Long-term debt				$ 810,000,000
Percent of common stock equity				56.90%				56.20%
Percent of long-term debt				43.10%				43.80%
Regulatory preferred stock and debt securities issuance, amount authorized				$ 300,000,000			$ 300,000,000.0		$ 518,000,000.0
Debt instrument, principal outstanding, excluding current portion				808,300,000				$ 808,100,000
Laclede Gas | No Call Options
Debt Instrument [Line Items]
Long-term debt				25,000,000
Laclede Gas | Make Whole Call Options
Debt Instrument [Line Items]
Long-term debt				435,000,000
Laclede Gas | Three to six months prior to maturity | Subject to Callable at Par
Debt Instrument [Line Items]
Long-term debt				$ 350,000,000
Redemption period prior to maturity, minimum				3 months
Redemption period prior to maturity, maximum				6 months
Laclede Gas | Subsequent Event
Debt Instrument [Line Items]
Regulatory preferred stock and debt securities issuance, authorized debt issuance - remaining available					$ 300,000,000
Alagasco
Debt Instrument [Line Items]
Long-term debt				$ 250,000,000
Percent of common stock equity				77.60%				83.70%
Percent of long-term debt				22.40%				16.30%
Long-term debt reclassified to current				$ 250,000,000
Long-term debt amount authorized										$ 80,000,000.0	$ 35,000,000.0
Debt instrument, principal outstanding, excluding current portion				250,000,000				$ 170,000,000
Debt instrument redeemed			$ 34,800,000
Alagasco | Make Whole Call Options
Debt Instrument [Line Items]
Long-term debt				$ 250,000,000
Alagasco | 5.7% Notes, due January 15, 2035
Debt Instrument [Line Items]
Stated interest rate on debt issued											5.70%
Debt instrument, principal outstanding, excluding current portion											$ 34,800,000
Alagasco | 5.368% Notes, due December 1, 2015
Debt Instrument [Line Items]
Long-term debt issued amount										$ 80,000,000
Alagasco | 3.21% Notes, due September 15, 2025
Debt Instrument [Line Items]
Stated interest rate on debt issued				3.21%				3.21%
Alagasco | Notes 4.31%, Due December 1, 2045
Debt Instrument [Line Items]
Stated interest rate on debt issued				4.31%				4.31%
Alagasco | Unsecured notes
Debt Instrument [Line Items]
Long-term debt issued amount				$ 115,000,000.0
Alagasco | Unsecured notes | 3.21% Notes, due September 15, 2025
Debt Instrument [Line Items]
Long-term debt issued amount		$ 35,000,000.0
Stated interest rate on debt issued		3.21%
Debt issued, maturity term		10 years
Alagasco | Unsecured notes | Notes 4.31%, Due December 1, 2045
Debt Instrument [Line Items]
Long-term debt issued amount	$ 80,000,000.0
Stated interest rate on debt issued	4.31%
Debt issued, maturity term	30 years
Other subsidiaries
Debt Instrument [Line Items]
Long-term debt				$ 67,000,000

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NOTES PAYABLE AND CREDIT AGREEMENTS - Narrative (Details)		12 Months Ended
	Sep. 02, 2014 USD ($) bank	Sep. 30, 2016 USD ($) bank
Line of Credit Facility [Line Items]
Speculative interest rate increase percent		1.00%
Decrease in cash flow with an impact of 100 basis point interest rate increase		$ 2,700,000
Laclede Gas
Line of Credit Facility [Line Items]
Speculative interest rate increase percent		1.00%
Decrease in cash flow with an impact of 100 basis point interest rate increase		$ 2,200,000
Alagasco
Line of Credit Facility [Line Items]
Speculative interest rate increase percent		1.00%
Decrease in cash flow with an impact of 100 basis point interest rate increase		$ 400,000
Line of Credit
Line of Credit Facility [Line Items]
Line of credit facility borrowing capacity		$ 150,000,000.0
Banks in syndicated line of credit facility | bank		9
Minimum required ratio of earnings before interest, taxes, depreciation, and amortization (EBITDA) times interest expense as required by the line of credit covenant		70.00%
Debt to total capitalization ratio		0.585
Line of Credit | Laclede Gas
Line of Credit Facility [Line Items]
Line of credit facility borrowing capacity		$ 450,000,000.0
Banks in syndicated line of credit facility | bank		10
Minimum required ratio of earnings before interest, taxes, depreciation, and amortization (EBITDA) times interest expense as required by the line of credit covenant		70.00%
Debt to total capitalization ratio		0.497
Line of Credit | Alagasco
Line of Credit Facility [Line Items]
Line of credit facility borrowing capacity	$ 150,000,000.0
Banks in syndicated line of credit facility | bank	12
Minimum required ratio of earnings before interest, taxes, depreciation, and amortization (EBITDA) times interest expense as required by the line of credit covenant	70.00%
Debt to total capitalization ratio		0.278
Line of Credit | Liabilities | Lender Concentration Risk
Line of Credit Facility [Line Items]
Percent of debt by a singe bank		15.60%
Line of Credit | Liabilities | Lender Concentration Risk | Laclede Gas
Line of Credit Facility [Line Items]
Percent of debt by a singe bank		15.60%
Line of Credit | Liabilities | Lender Concentration Risk | Alagasco
Line of Credit Facility [Line Items]
Percent of debt by a singe bank	10.00%

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NOTES PAYABLE AND CREDIT AGREEMENTS - Spire Short-term Borrowings (Details) - USD ($)	1 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2016	Sep. 30, 2015
Short-term Debt [Line Items]
Weighted average borrowings outstanding		$ 273,900,000	$ 300,600,000
Weighted average interest rate		0.90%	0.70%
Minimum borrowing outstanding		$ 73,100,000	$ 180,100,000
Maximum borrowing outstanding		427,200,000	488,500,000
Short-term debt		$ 398,700,000	$ 338,000,000
Weighted average interest rate		1.10%	0.80%
Line of Credit
Short-term Debt [Line Items]
Minimum borrowing outstanding		$ 0	$ 32,500,000
Maximum borrowing outstanding		82,000,000	80,000,000
Laclede Gas
Short-term Debt [Line Items]
Weighted average borrowings outstanding		$ 215,700,000	$ 213,000,000
Weighted average interest rate		0.70%	0.40%
Minimum borrowing outstanding		$ 127,800,000.0	$ 104,200,000.0
Maximum borrowing outstanding		307,200,000.0	341,000,000
Short-term debt		$ 243,700,000	$ 233,000,000
Weighted average interest rate		0.80%	0.50%
Laclede Gas | Commercial Paper
Short-term Debt [Line Items]
Weighted average borrowings outstanding		$ 201,000,000	$ 212,700,000
Weighted average interest rate		0.70%	0.40%
Minimum borrowing outstanding		$ 43,000,000	$ 102,100,000.0
Maximum borrowing outstanding		307,200,000.0	341,000,000
Short-term debt		$ 243,700,000	$ 233,000,000
Weighted average interest rate		0.80%	0.50%
Spire | Line of Credit
Short-term Debt [Line Items]
Weighted average borrowings outstanding		$ 42,700,000	$ 65,600,000
Weighted average interest rate		1.60%	1.40%
Short-term debt		$ 73,000,000	$ 74,000,000
Weighted average interest rate		1.80%	1.50%
Alagasco
Short-term Debt [Line Items]
Weighted average borrowings outstanding		$ 42,600,000	$ 22,300,000
Weighted average interest rate		1.40%	1.10%
Minimum borrowing outstanding		$ 19,000,000	$ 0
Maximum borrowing outstanding		82,000,000	69,500,000
Short-term debt		$ 82,000,000	$ 31,000,000
Weighted average interest rate		1.50%	1.20%
Alagasco | Line of Credit
Short-term Debt [Line Items]
Weighted average borrowings outstanding	$ 22,300,000	$ 30,200,000	$ 22,300,000
Weighted average interest rate	1.10%	1.40%	1.10%
Minimum borrowing outstanding		$ 0	$ 0
Maximum borrowing outstanding		82,000,000	69,500,000.0
Short-term debt		$ 82,000,000	$ 31,000,000
Weighted average interest rate		1.50%	1.20%

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NOTES PAYABLE AND CREDIT AGREEMENTS - Laclede Gas' Short-term Borrowings (Details) - USD ($)	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Short-term Debt [Line Items]
Weighted average borrowings outstanding	$ 273,900,000	$ 300,600,000
Weighted average interest rate	0.90%	0.70%
Minimum borrowing outstanding	$ 73,100,000	$ 180,100,000
Maximum borrowing outstanding	427,200,000	488,500,000
Short-term debt	$ 398,700,000	$ 338,000,000
Weighted average interest rate	1.10%	0.80%
Laclede Gas
Short-term Debt [Line Items]
Weighted average borrowings outstanding	$ 215,700,000	$ 213,000,000
Weighted average interest rate	0.70%	0.40%
Minimum borrowing outstanding	$ 127,800,000.0	$ 104,200,000.0
Maximum borrowing outstanding	307,200,000.0	341,000,000
Short-term debt	$ 243,700,000	$ 233,000,000
Weighted average interest rate	0.80%	0.50%
Laclede Gas | Commercial Paper
Short-term Debt [Line Items]
Weighted average borrowings outstanding	$ 201,000,000	$ 212,700,000
Weighted average interest rate	0.70%	0.40%
Minimum borrowing outstanding	$ 43,000,000	$ 102,100,000.0
Maximum borrowing outstanding	307,200,000.0	341,000,000
Short-term debt	$ 243,700,000	$ 233,000,000
Weighted average interest rate	0.80%	0.50%
Laclede Gas | Notes Payable to Related Party
Short-term Debt [Line Items]
Weighted average borrowings outstanding	$ 14,700,000	$ 300,000
Weighted average interest rate	0.80%	0.50%
Minimum borrowing outstanding	$ 0	$ 0
Maximum borrowing outstanding	114,200,000.0	10,400,000.0
Short-term debt	$ 0	$ 0
Weighted average interest rate	0.00%	0.00%

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NOTES PAYABLE AND CREDIT AGREEMENTS - Alagasco's Short-term Borrowings (Details) - USD ($)	1 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2016	Sep. 30, 2015
Short-term Debt [Line Items]
Weighted average borrowings outstanding		$ 273,900,000	$ 300,600,000
Weighted average interest rate		0.90%	0.70%
Minimum borrowing outstanding		$ 73,100,000	$ 180,100,000
Maximum borrowing outstanding		427,200,000	488,500,000
Short-term debt		$ 398,700,000	$ 338,000,000
Weighted average interest rate		1.10%	0.80%
Line of Credit
Short-term Debt [Line Items]
Minimum borrowing outstanding		$ 0	$ 32,500,000
Maximum borrowing outstanding		82,000,000	80,000,000
Alagasco
Short-term Debt [Line Items]
Weighted average borrowings outstanding		$ 42,600,000	$ 22,300,000
Weighted average interest rate		1.40%	1.10%
Minimum borrowing outstanding		$ 19,000,000	$ 0
Maximum borrowing outstanding		82,000,000	69,500,000
Short-term debt		$ 82,000,000	$ 31,000,000
Weighted average interest rate		1.50%	1.20%
Alagasco | Line of Credit
Short-term Debt [Line Items]
Weighted average borrowings outstanding	$ 22,300,000	$ 30,200,000	$ 22,300,000
Weighted average interest rate	1.10%	1.40%	1.10%
Minimum borrowing outstanding		$ 0	$ 0
Maximum borrowing outstanding		82,000,000	69,500,000.0
Short-term debt		$ 82,000,000	$ 31,000,000
Weighted average interest rate		1.50%	1.20%
Alagasco | Notes Payable to Related Party
Short-term Debt [Line Items]
Weighted average borrowings outstanding		$ 12,400,000	$ 0
Weighted average interest rate		1.40%	0.00%
Minimum borrowing outstanding		$ 0	$ 0
Maximum borrowing outstanding		61,900,000.0	0
Short-term debt		$ 0	$ 0
Weighted average interest rate		0.00%	0.00%

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FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 5.2	$ 13.8	$ 16.1		$ 53.0
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	5.2	13.8
Short-term debt	398.7	338.0
Long-term debt, including current portion	2,083.7	1,851.5
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	5.2	13.8
Short-term debt	398.7	338.0
Long-term debt, including current portion	2,257.1	1,944.2
Laclede Gas
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	2.1	1.7	3.7		$ 23.9
Laclede Gas | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	2.1	1.7
Short-term debt	243.7	233.0
Long-term debt, including current portion	808.3	808.1
Laclede Gas | Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	2.1	1.7
Short-term debt	243.7	233.0
Long-term debt, including current portion	900.4	880.2
Alagasco
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0.0	7.2	$ 5.6	$ 3.0
Alagasco | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0.0	7.2
Short-term debt	82.0	31.0
Long-term debt, including current portion	250.0	250.0
Alagasco | Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0.0	7.2
Short-term debt	82.0	31.0
Long-term debt, including current portion	275.5	263.2
Quoted Prices in Active Markets (Level 1)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	5.2	13.8
Short-term debt	0.0	0.0
Long-term debt, including current portion	0.0	0.0
Quoted Prices in Active Markets (Level 1) | Laclede Gas
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	2.1	1.7
Short-term debt	0.0	0.0
Long-term debt, including current portion	0.0	0.0
Quoted Prices in Active Markets (Level 1) | Alagasco
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0.0	7.2
Short-term debt	0.0	0.0
Long-term debt, including current portion	0.0	0.0
Significant Observable Inputs (Level 2)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0.0	0.0
Short-term debt	398.7	338.0
Long-term debt, including current portion	2,257.1	1,944.2
Significant Observable Inputs (Level 2) | Laclede Gas
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0.0	0.0
Short-term debt	243.7	233.0
Long-term debt, including current portion	900.4	880.2
Significant Observable Inputs (Level 2) | Alagasco
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0.0	0.0
Short-term debt	82.0	31.0
Long-term debt, including current portion	275.5	263.2
Significant Unobservable Inputs (Level 3)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0.0	0.0
Short-term debt	0.0	0.0
Long-term debt, including current portion	0.0	0.0
Significant Unobservable Inputs (Level 3) | Laclede Gas
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0.0	0.0
Short-term debt	0.0	0.0
Long-term debt, including current portion	0.0	0.0
Significant Unobservable Inputs (Level 3) | Alagasco
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0.0	0.0
Short-term debt	0.0	0.0
Long-term debt, including current portion	$ 0.0	$ 0.0

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FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
ASSETS
Derivative asset after the effects of netting	$ 13.3	$ 5.2
LIABILITIES
Derivative liability after the effects of netting	4.9	7.6
Laclede Gas
ASSETS
Derivative asset after the effects of netting	4.9	0.0
LIABILITIES
Derivative liability after the effects of netting	0.2	5.9
Fair Value, Measurements, Recurring
ASSETS
Effects of netting and cash margin receivables/payables	(5.0)	(8.4)
Derivative asset after the effects of netting	34.3	24.7
LIABILITIES
Effects of netting and cash margin receivables/payables	(7.6)
Derivative liability after the effects of netting	4.9
Fair Value, Measurements, Recurring | Laclede Gas
ASSETS
Effects of netting and cash margin receivables/payables	(0.7)	(1.3)
Derivative asset after the effects of netting	25.8	19.5
LIABILITIES
Effects of netting and cash margin receivables/payables	(1.6)	(16.7)
Derivative liability after the effects of netting	0.2	5.9
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets (Level 1)
ASSETS
Derivative asset before effects of netting	22.9	23.1
LIABILITIES
Derivative liability before effects of netting	5.1
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets (Level 1) | Laclede Gas
ASSETS
Derivative asset before effects of netting	22.4	16.8
LIABILITIES
Derivative liability before effects of netting	1.6	16.7
Fair Value, Measurements, Recurring | Significant Observable Inputs (Level 2)
ASSETS
Derivative asset before effects of netting	16.2	9.8
LIABILITIES
Derivative liability before effects of netting	7.4
Fair Value, Measurements, Recurring | Significant Observable Inputs (Level 2) | Laclede Gas
ASSETS
Derivative asset before effects of netting	4.1	4.0
LIABILITIES
Derivative liability before effects of netting	0.2	5.9
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
ASSETS
Derivative asset before effects of netting	0.2	0.2
LIABILITIES
Derivative liability before effects of netting	0.0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Laclede Gas
ASSETS
Derivative asset before effects of netting	0.0	0.0
LIABILITIES
Derivative liability before effects of netting	0.0	0.0
Fair Value, Measurements, Recurring | US stock/bond mutual funds | Laclede Gas
ASSETS
Effects of netting and cash margin receivables/payables	0.0	0.0
Derivative asset after the effects of netting	20.9	19.5
Fair Value, Measurements, Recurring | US stock/bond mutual funds | Quoted Prices in Active Markets (Level 1) | Laclede Gas
ASSETS
Derivative asset before effects of netting	16.8	15.5
Fair Value, Measurements, Recurring | US stock/bond mutual funds | Significant Observable Inputs (Level 2) | Laclede Gas
ASSETS
Derivative asset before effects of netting	4.1	4.0
Fair Value, Measurements, Recurring | US stock/bond mutual funds | Significant Unobservable Inputs (Level 3) | Laclede Gas
ASSETS
Derivative asset before effects of netting	0.0	0.0
Fair Value, Measurements, Recurring | NYMEX/ICE natural gas contracts | Laclede Gas
ASSETS
Effects of netting and cash margin receivables/payables	(0.4)	(1.3)
Derivative asset after the effects of netting	4.9	0.0
LIABILITIES
Effects of netting and cash margin receivables/payables	(1.6)	(16.4)
Derivative liability after the effects of netting	0.0	0.0
Fair Value, Measurements, Recurring | NYMEX/ICE natural gas contracts | Quoted Prices in Active Markets (Level 1) | Laclede Gas
ASSETS
Derivative asset before effects of netting	5.3	1.3
LIABILITIES
Derivative liability before effects of netting	1.6	16.4
Fair Value, Measurements, Recurring | NYMEX/ICE natural gas contracts | Significant Observable Inputs (Level 2) | Laclede Gas
ASSETS
Derivative asset before effects of netting	0.0	0.0
LIABILITIES
Derivative liability before effects of netting	0.0	0.0
Fair Value, Measurements, Recurring | NYMEX/ICE natural gas contracts | Significant Unobservable Inputs (Level 3) | Laclede Gas
ASSETS
Derivative asset before effects of netting	0.0	0.0
LIABILITIES
Derivative liability before effects of netting	0.0	0.0
Fair Value, Measurements, Recurring | OTCBB natural gas contracts | Laclede Gas
LIABILITIES
Effects of netting and cash margin receivables/payables	0.0	0.0
Derivative liability after the effects of netting	0.2	5.9
Fair Value, Measurements, Recurring | OTCBB natural gas contracts | Quoted Prices in Active Markets (Level 1) | Laclede Gas
LIABILITIES
Derivative liability before effects of netting	0.0	0.0
Fair Value, Measurements, Recurring | OTCBB natural gas contracts | Significant Observable Inputs (Level 2) | Laclede Gas
LIABILITIES
Derivative liability before effects of netting	0.2	5.9
Fair Value, Measurements, Recurring | OTCBB natural gas contracts | Significant Unobservable Inputs (Level 3) | Laclede Gas
LIABILITIES
Derivative liability before effects of netting	0.0	0.0
Fair Value, Measurements, Recurring | Gasoline and heating oil contracts | Laclede Gas
ASSETS
Effects of netting and cash margin receivables/payables	(0.3)
Derivative asset after the effects of netting	0.0
Fair Value, Measurements, Recurring | Gasoline and heating oil contracts | Quoted Prices in Active Markets (Level 1) | Laclede Gas
ASSETS
Derivative asset before effects of netting	0.3
Fair Value, Measurements, Recurring | Gasoline and heating oil contracts | Significant Observable Inputs (Level 2) | Laclede Gas
ASSETS
Derivative asset before effects of netting	0.0
Fair Value, Measurements, Recurring | Gasoline and heating oil contracts | Significant Unobservable Inputs (Level 3) | Laclede Gas
ASSETS
Derivative asset before effects of netting	0.0
Fair Value, Measurements, Recurring | NYMEX gasoline and heating oil contracts | Laclede Gas
LIABILITIES
Effects of netting and cash margin receivables/payables		(0.3)
Derivative liability after the effects of netting		0.0
Fair Value, Measurements, Recurring | NYMEX gasoline and heating oil contracts | Quoted Prices in Active Markets (Level 1) | Laclede Gas
LIABILITIES
Derivative liability before effects of netting		0.3
Fair Value, Measurements, Recurring | NYMEX gasoline and heating oil contracts | Significant Observable Inputs (Level 2) | Laclede Gas
LIABILITIES
Derivative liability before effects of netting		0.0
Fair Value, Measurements, Recurring | NYMEX gasoline and heating oil contracts | Significant Unobservable Inputs (Level 3) | Laclede Gas
LIABILITIES
Derivative liability before effects of netting		0.0
Fair Value, Measurements, Recurring | Gas Marketing
LIABILITIES
Effects of netting and cash margin receivables/payables		(22.3)
Derivative liability after the effects of netting		7.6
Fair Value, Measurements, Recurring | Gas Marketing | Quoted Prices in Active Markets (Level 1)
LIABILITIES
Derivative liability before effects of netting		17.9
Fair Value, Measurements, Recurring | Gas Marketing | Significant Observable Inputs (Level 2)
LIABILITIES
Derivative liability before effects of netting		12.0
Fair Value, Measurements, Recurring | Gas Marketing | Significant Unobservable Inputs (Level 3)
LIABILITIES
Derivative liability before effects of netting		0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility
ASSETS
Effects of netting and cash margin receivables/payables	(0.7)	(1.3)
Derivative asset after the effects of netting	25.9	19.5
LIABILITIES
Effects of netting and cash margin receivables/payables	(1.6)	(16.7)
Derivative liability after the effects of netting	0.2	5.9
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | Quoted Prices in Active Markets (Level 1)
ASSETS
Derivative asset before effects of netting	22.5	16.8
LIABILITIES
Derivative liability before effects of netting	1.6	16.7
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | Significant Observable Inputs (Level 2)
ASSETS
Derivative asset before effects of netting	4.1	4.0
LIABILITIES
Derivative liability before effects of netting	0.2	5.9
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | Significant Unobservable Inputs (Level 3)
ASSETS
Derivative asset before effects of netting	0.0	0.0
LIABILITIES
Derivative liability before effects of netting	0.0	0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | US stock/bond mutual funds
ASSETS
Effects of netting and cash margin receivables/payables	0.0	0.0
Derivative asset after the effects of netting	20.9	19.5
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | US stock/bond mutual funds | Quoted Prices in Active Markets (Level 1)
ASSETS
Derivative asset before effects of netting	16.8	15.5
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | US stock/bond mutual funds | Significant Observable Inputs (Level 2)
ASSETS
Derivative asset before effects of netting	4.1	4.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | US stock/bond mutual funds | Significant Unobservable Inputs (Level 3)
ASSETS
Derivative asset before effects of netting	0.0	0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | NYMEX/ICE natural gas contracts
ASSETS
Effects of netting and cash margin receivables/payables	(0.4)	(1.3)
Derivative asset after the effects of netting	4.9	0.0
LIABILITIES
Effects of netting and cash margin receivables/payables	(1.6)	(16.4)
Derivative liability after the effects of netting	0.0	0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | NYMEX/ICE natural gas contracts | Quoted Prices in Active Markets (Level 1)
ASSETS
Derivative asset before effects of netting	5.3	1.3
LIABILITIES
Derivative liability before effects of netting	1.6	16.4
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | NYMEX/ICE natural gas contracts | Significant Observable Inputs (Level 2)
ASSETS
Derivative asset before effects of netting	0.0	0.0
LIABILITIES
Derivative liability before effects of netting	0.0	0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | NYMEX/ICE natural gas contracts | Significant Unobservable Inputs (Level 3)
ASSETS
Derivative asset before effects of netting	0.0	0.0
LIABILITIES
Derivative liability before effects of netting	0.0	0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | OTCBB natural gas contracts
LIABILITIES
Effects of netting and cash margin receivables/payables	0.0	0.0
Derivative liability after the effects of netting	0.2	5.9
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | OTCBB natural gas contracts | Quoted Prices in Active Markets (Level 1)
LIABILITIES
Derivative liability before effects of netting	0.0	0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | OTCBB natural gas contracts | Significant Observable Inputs (Level 2)
LIABILITIES
Derivative liability before effects of netting	0.2	5.9
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | OTCBB natural gas contracts | Significant Unobservable Inputs (Level 3)
LIABILITIES
Derivative liability before effects of netting	0.0	0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | Gasoline and heating oil contracts
ASSETS
Effects of netting and cash margin receivables/payables	(0.3)
Derivative asset after the effects of netting	0.1
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | Gasoline and heating oil contracts | Quoted Prices in Active Markets (Level 1)
ASSETS
Derivative asset before effects of netting	0.4
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | Gasoline and heating oil contracts | Significant Observable Inputs (Level 2)
ASSETS
Derivative asset before effects of netting	0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | Gasoline and heating oil contracts | Significant Unobservable Inputs (Level 3)
ASSETS
Derivative asset before effects of netting	0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | NYMEX gasoline and heating oil contracts
LIABILITIES
Effects of netting and cash margin receivables/payables		(0.3)
Derivative liability after the effects of netting		0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | NYMEX gasoline and heating oil contracts | Quoted Prices in Active Markets (Level 1)
LIABILITIES
Derivative liability before effects of netting		0.3
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | NYMEX gasoline and heating oil contracts | Significant Observable Inputs (Level 2)
LIABILITIES
Derivative liability before effects of netting		0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Utility | NYMEX gasoline and heating oil contracts | Significant Unobservable Inputs (Level 3)
LIABILITIES
Derivative liability before effects of netting		0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Marketing | NYMEX/ICE natural gas contracts
ASSETS
Effects of netting and cash margin receivables/payables	(3.4)
Derivative asset after the effects of netting	0.4
LIABILITIES
Effects of netting and cash margin receivables/payables	(5.1)	(5.1)
Derivative liability after the effects of netting	0.0	0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Marketing | NYMEX/ICE natural gas contracts | Quoted Prices in Active Markets (Level 1)
ASSETS
Derivative asset before effects of netting	0.4
LIABILITIES
Derivative liability before effects of netting	3.5	1.2
Operating Segments | Fair Value, Measurements, Recurring | Gas Marketing | NYMEX/ICE natural gas contracts | Significant Observable Inputs (Level 2)
ASSETS
Derivative asset before effects of netting	3.4
LIABILITIES
Derivative liability before effects of netting	1.6	3.9
Operating Segments | Fair Value, Measurements, Recurring | Gas Marketing | NYMEX/ICE natural gas contracts | Significant Unobservable Inputs (Level 3)
ASSETS
Derivative asset before effects of netting	0.0
LIABILITIES
Derivative liability before effects of netting	0.0	0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Marketing | NYMEX natural gas contracts
ASSETS
Effects of netting and cash margin receivables/payables		(6.6)
Derivative asset after the effects of netting		4.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Marketing | NYMEX natural gas contracts | Quoted Prices in Active Markets (Level 1)
ASSETS
Derivative asset before effects of netting		6.3
Operating Segments | Fair Value, Measurements, Recurring | Gas Marketing | NYMEX natural gas contracts | Significant Observable Inputs (Level 2)
ASSETS
Derivative asset before effects of netting		4.3
Operating Segments | Fair Value, Measurements, Recurring | Gas Marketing | NYMEX natural gas contracts | Significant Unobservable Inputs (Level 3)
ASSETS
Derivative asset before effects of netting		0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Marketing | Natural gas commodity contracts
ASSETS
Effects of netting and cash margin receivables/payables	(0.9)	(0.5)
Derivative asset after the effects of netting	8.0	1.2
LIABILITIES
Effects of netting and cash margin receivables/payables	(0.9)	(0.5)
Derivative liability after the effects of netting	1.7	1.7
Operating Segments | Fair Value, Measurements, Recurring | Gas Marketing | Natural gas commodity contracts | Quoted Prices in Active Markets (Level 1)
ASSETS
Derivative asset before effects of netting	0.0	0.0
LIABILITIES
Derivative liability before effects of netting	0.0	0.0
Operating Segments | Fair Value, Measurements, Recurring | Gas Marketing | Natural gas commodity contracts | Significant Observable Inputs (Level 2)
ASSETS
Derivative asset before effects of netting	8.7	1.5
LIABILITIES
Derivative liability before effects of netting	2.6	2.2
Operating Segments | Fair Value, Measurements, Recurring | Gas Marketing | Natural gas commodity contracts | Significant Unobservable Inputs (Level 3)
ASSETS
Derivative asset before effects of netting	0.2	0.2
LIABILITIES
Derivative liability before effects of netting	0.0	$ 0.0
Other | Fair Value, Measurements, Recurring | Interest rate swaps
LIABILITIES
Effects of netting and cash margin receivables/payables	0.0
Derivative liability after the effects of netting	3.0
Other | Fair Value, Measurements, Recurring | Interest rate swaps | Quoted Prices in Active Markets (Level 1)
LIABILITIES
Derivative liability before effects of netting	0.0
Other | Fair Value, Measurements, Recurring | Interest rate swaps | Significant Observable Inputs (Level 2)
LIABILITIES
Derivative liability before effects of netting	3.0
Other | Fair Value, Measurements, Recurring | Interest rate swaps | Significant Unobservable Inputs (Level 3)
LIABILITIES
Derivative liability before effects of netting	$ 0.0

XML

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Narrative (Details) gal in Millions, MMBTU in Millions				3 Months Ended			12 Months Ended
	Jun. 03, 2016 USD ($)	May 21, 2015 USD ($)	Aug. 06, 2014 USD ($)	Sep. 30, 2016 USD ($) MMBTU $ / gal gal	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Sep. 30, 2016 USD ($) MMBTU $ / gal gal	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)	May 05, 2016 USD ($)	Dec. 01, 2015 USD ($)	Sep. 15, 2015 USD ($)	Apr. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Aug. 19, 2014 USD ($)	Jul. 08, 2014 USD ($)
Derivative [Line Items]
Notional amount of non-exchange traded natural gas commodity contracts (in MMBtu) | MMBTU				122.7			122.7
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2016 | MMBTU				110.8			110.8
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2017 | MMBTU				11.4			11.4
Notional amount of non-exchange traded natural gas commodity to be settled during fiscal 2018 | MMBTU				0.2			0.2
Notional amount of non-exchange traded natural gas commodity to be settled during fiscal 2019 | MMBTU				0.3			0.3
Notional amount					$ 120,000,000.0
Long-term debt issued amount															$ 625,000,000.0
Term of contract					7 years
Derivative average fixed interest rate					1.501%
Unrealized gain on energy-related derivatives							$ 100,000	$ 2,800,000	$ 1,600,000
Gain (loss) to be reclassified within twelve months							0
Cash margin receivables not offset with derivatives				$ 2,900,000			$ 2,900,000	5,900,000
Alagasco
Derivative [Line Items]
Unsecured debt														$ 115,000,000
Gasoline futures contracts notional amount (in gallons) | gal				0.6			0.6
Average price of future contracts (dollars per gallon) | $ / gal				1.53			1.53
Alagasco | 3.21% Notes, due September 15, 2025
Derivative [Line Items]
Unsecured debt												$ 35,000,000
Alagasco | Notes 4.31%, Due December 1, 2045
Derivative [Line Items]
Unsecured debt											$ 80,000,000
Laclede Gas
Derivative [Line Items]
MMBtu (millions) | MMBTU							19.8
Gain (loss) to be reclassified within twelve months							$ 0
Cash margin receivables not offset with derivatives				$ 500,000			$ 500,000	$ 5,900,000
Gasoline futures contracts notional amount (in gallons) | gal				1.8			1.8
Average price of future contracts (dollars per gallon) | $ / gal				1.37			1.37
Interest rate swaps
Derivative [Line Items]
Notional amount						$ 105,000,000
Derivative fixed interest rate						1.776%
Term of contract						5 years
Unrealized gain on energy-related derivatives				$ 1,000,000			$ (3,000,000)
Designated as Hedging Instrument | Interest rate swaps | Alagasco
Derivative [Line Items]
Gain on settlement of derivative		$ 2,700,000
Cash Flow Hedging | Designated as Hedging Instrument | Interest rate swaps
Derivative [Line Items]
Notional amount										$ 85,000,000.0			$ 24,000,000.0			$ 375,000,000.0
Loss on termination and settlement of interest rate swap			$ 19,000,000
Effective portion of gain (loss) recognized in OCI on derivatives	$ (400,000)
Cash Flow Hedging | Designated as Hedging Instrument | Interest rate swaps | Alagasco
Derivative [Line Items]
Notional amount													$ 24,000,000.0	$ 80,500,000
Cash Flow Hedging | Designated as Hedging Instrument | Interest rate swaps | Alagasco | Minimum
Derivative [Line Items]
Derivative fixed interest rate														2.18%
Cash Flow Hedging | Designated as Hedging Instrument | Interest rate swaps | Alagasco | Maximum
Derivative [Line Items]
Derivative fixed interest rate														2.85%

XML

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Exchange-Traded/Cleared Derivatives (Details) MMBTU in Thousands	12 Months Ended
	Sep. 30, 2016 MMBTU $ / gal $ / MMBTU
Laclede Gas
Derivative [Line Items]
MMBtu (millions)	19,800
Avg. Price Per MMBtu | $ / gal	1.37
Short | Gas Utility | Natural gas contracts | Fiscal 2017
Derivative [Line Items]
MMBtu (millions)	0
Avg. Price Per MMBtu | $ / MMBTU	0.00
Short | Gas Utility | Natural gas contracts | Fiscal 2018
Derivative [Line Items]
MMBtu (millions)	0
Avg. Price Per MMBtu | $ / MMBTU	0.00
Short | Gas Utility | ICE Open basis swap positions | Fiscal 2017
Derivative [Line Items]
MMBtu (millions)	0
Avg. Price Per MMBtu | $ / MMBTU	0.00
Short | Gas Utility | ICE Open basis swap positions | Fiscal 2018
Derivative [Line Items]
MMBtu (millions)	0
Avg. Price Per MMBtu | $ / MMBTU	0.00
Short | Gas Utility | ICE Open basis swap positions | Fiscal 2019
Derivative [Line Items]
MMBtu (millions)	0
Avg. Price Per MMBtu | $ / MMBTU	0.00
Short | Gas Marketing | Natural gas contracts | Fiscal 2017
Derivative [Line Items]
MMBtu (millions)	12,200
Avg. Price Per MMBtu | $ / MMBTU	2.86
Short | Gas Marketing | Natural gas contracts | Fiscal 2018
Derivative [Line Items]
MMBtu (millions)	1,270
Avg. Price Per MMBtu | $ / MMBTU	2.95
Short | Gas Marketing | ICE Open basis swap positions | Fiscal 2017
Derivative [Line Items]
MMBtu (millions)	11,880
Avg. Price Per MMBtu | $ / MMBTU	0.19
Short | Gas Marketing | ICE Open basis swap positions | Fiscal 2018
Derivative [Line Items]
MMBtu (millions)	930
Avg. Price Per MMBtu | $ / MMBTU	0.27
Short | Gas Marketing | ICE Open basis swap positions | Fiscal 2019
Derivative [Line Items]
MMBtu (millions)	2,270
Avg. Price Per MMBtu | $ / MMBTU	0.13
Long | Gas Utility | Natural gas contracts | Fiscal 2017
Derivative [Line Items]
MMBtu (millions)	18,430
Avg. Price Per MMBtu | $ / MMBTU	2.95
Long | Gas Utility | Natural gas contracts | Fiscal 2017 | Laclede Gas
Derivative [Line Items]
MMBtu (millions)	18,430
Avg. Price Per MMBtu | $ / MMBTU	2.95
Long | Gas Utility | Natural gas contracts | Fiscal 2018
Derivative [Line Items]
MMBtu (millions)	330
Avg. Price Per MMBtu | $ / MMBTU	2.83
Long | Gas Utility | Natural gas contracts | Fiscal 2018 | Laclede Gas
Derivative [Line Items]
MMBtu (millions)	330
Avg. Price Per MMBtu | $ / MMBTU	2.83
Long | Gas Utility | Natural gas contracts | Fiscal 2019
Derivative [Line Items]
MMBtu (millions)	0
Avg. Price Per MMBtu | $ / MMBTU	0.00
Long | Gas Utility | ICE Open basis swap positions | Fiscal 2017
Derivative [Line Items]
MMBtu (millions)	0
Avg. Price Per MMBtu | $ / MMBTU	0.00
Long | Gas Utility | ICE Open basis swap positions | Fiscal 2018
Derivative [Line Items]
MMBtu (millions)	0
Avg. Price Per MMBtu | $ / MMBTU	0.00
Long | Gas Utility | ICE Open basis swap positions | Fiscal 2019
Derivative [Line Items]
MMBtu (millions)	0
Avg. Price Per MMBtu | $ / MMBTU	0.00
Long | Gas Utility | OTC Open long futures/swap positions | Fiscal 2017
Derivative [Line Items]
MMBtu (millions)	320
Avg. Price Per MMBtu | $ / MMBTU	3.64
Long | Gas Utility | OTC Open long futures/swap positions | Fiscal 2017 | Laclede Gas
Derivative [Line Items]
MMBtu (millions)	320
Avg. Price Per MMBtu | $ / MMBTU	3.64
Long | Gas Marketing | Natural gas contracts | Fiscal 2017
Derivative [Line Items]
MMBtu (millions)	4,620
Avg. Price Per MMBtu | $ / MMBTU	3.12
Long | Gas Marketing | Natural gas contracts | Fiscal 2018
Derivative [Line Items]
MMBtu (millions)	450
Avg. Price Per MMBtu | $ / MMBTU	3.02
Long | Gas Marketing | Natural gas contracts | Fiscal 2019
Derivative [Line Items]
MMBtu (millions)	40
Avg. Price Per MMBtu | $ / MMBTU	2.89
Long | Gas Marketing | ICE Open basis swap positions | Fiscal 2017
Derivative [Line Items]
MMBtu (millions)	16,620
Avg. Price Per MMBtu | $ / MMBTU	0.34
Long | Gas Marketing | ICE Open basis swap positions | Fiscal 2018
Derivative [Line Items]
MMBtu (millions)	2,010
Avg. Price Per MMBtu | $ / MMBTU	0.43
Long | Gas Marketing | ICE Open basis swap positions | Fiscal 2019
Derivative [Line Items]
MMBtu (millions)	80
Avg. Price Per MMBtu | $ / MMBTU	0.40
Long | Gas Marketing | OTC Open long futures/swap positions | Fiscal 2017
Derivative [Line Items]
MMBtu (millions)	0
Avg. Price Per MMBtu | $ / MMBTU	0.00

XML

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Gains (Losses) on Derivative Instruments (Details) - USD ($) $ in Millions		12 Months Ended
	Jun. 03, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Designated as Hedging Instrument | Cash Flow Hedging
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) reclassified from AOCI to income		$ (1.1)	$ (4.4)	$ 2.5
Ineffective portion of gain (loss) on derivatives recognized in income		0.3	(0.4)	(0.2)
Designated as Hedging Instrument | Cash Flow Hedging | Other Comprehensive Income (Loss)
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives		(4.0)	(5.5)	(4.5)
Designated as Hedging Instrument | Cash Flow Hedging | Natural gas contracts
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) reclassified from AOCI to income		(0.6)	(3.5)	2.7
Ineffective portion of gain (loss) on derivatives recognized in income		0.2	(0.5)	0.0
Designated as Hedging Instrument | Cash Flow Hedging | Natural gas contracts | Other Comprehensive Income (Loss)
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives		(0.6)	(4.3)	(4.6)
Designated as Hedging Instrument | Cash Flow Hedging | Natural gas contracts | Gas Marketing Operating Revenues
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) reclassified from AOCI to income		4.3	1.7	4.2
Ineffective portion of gain (loss) on derivatives recognized in income		0.1	0.0	(0.1)
Designated as Hedging Instrument | Cash Flow Hedging | Natural gas contracts | Gas Marketing Operating Expenses
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) reclassified from AOCI to income		(4.9)	(5.2)	(1.5)
Ineffective portion of gain (loss) on derivatives recognized in income		0.1	(0.5)	0.1
Designated as Hedging Instrument | Cash Flow Hedging | Gasoline and heating oil contracts | Other Comprehensive Income (Loss)
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives		0.0	(1.2)	0.1
Designated as Hedging Instrument | Cash Flow Hedging | Gasoline and heating oil contracts | Gas Utility Other Operating Expenses
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) reclassified from AOCI to income		(0.5)	(0.9)	(0.2)
Ineffective portion of gain (loss) on derivatives recognized in income		0.1	0.1	(0.2)
Designated as Hedging Instrument | Cash Flow Hedging | Interest rate swaps
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives	$ (0.4)
Designated as Hedging Instrument | Cash Flow Hedging | Interest rate swaps | Other Comprehensive Income (Loss)
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives		(3.4)	0.0	0.0
Not Designated as Hedging Instrument
Derivatives Not Designated as Hedging Instruments [Abstract]
Gain (loss) recognized in income on derivatives		10.6	(11.1)	(5.7)
Not Designated as Hedging Instrument | Gasoline and heating oil contracts | Other Income and (Income Deductions) - Net
Derivatives Not Designated as Hedging Instruments [Abstract]
Gain (loss) recognized in income on derivatives		0.0	(0.2)	0.0
Not Designated as Hedging Instrument | Natural gas commodity contracts | Gas Marketing Operating Revenues
Derivatives Not Designated as Hedging Instruments [Abstract]
Gain (loss) recognized in income on derivatives		12.3	(1.3)	(8.7)
Not Designated as Hedging Instrument | NYMEX / ICE natural gas contracts | Gas Marketing Operating Revenues
Derivatives Not Designated as Hedging Instruments [Abstract]
Gain (loss) recognized in income on derivatives		(1.7)	(9.6)	3.0
Laclede Gas | Designated as Hedging Instrument | Cash Flow Hedging | Gasoline and heating oil contracts | Other Comprehensive Income (Loss)
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives		0.0	(1.2)	0.1
Laclede Gas | Designated as Hedging Instrument | Cash Flow Hedging | Gasoline and heating oil contracts | Gas Utility Other Operating Expenses
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) reclassified from AOCI to income		(0.5)	(0.9)	(0.2)
Ineffective portion of gain (loss) on derivatives recognized in income		0.1	0.1	(0.2)
Laclede Gas | Not Designated as Hedging Instrument | Gasoline and heating oil contracts | Other Income and (Income Deductions) - Net
Derivatives Not Designated as Hedging Instruments [Abstract]
Gain (loss) recognized in income on derivatives		$ 0.0	$ (0.2)	$ 0.0

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	$ 18.4	$ 13.5
Fair value of liability derivatives presented above	12.5	29.8
Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	3.2
Fair value of liability derivatives presented above	3.9
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	15.2	8.3
Fair value of liability derivatives presented above	8.6	25.8
Other | Interest rate swaps | Designated as Hedging Instrument | Derivative Instrument Assets
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	0.0
Gas Utility | Operating Segments | Gasoline and heating oil contracts | Designated as Hedging Instrument | Derivative Instrument Assets
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	0.3
Fair value of liability derivatives presented above	0.0
Gas Utility | Operating Segments | Gasoline and heating oil contracts | Designated as Hedging Instrument | Accounts Receivable – Other
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above		0.0
Fair value of liability derivatives presented above		0.3
Gas Utility | Operating Segments | Natural gas contracts | Not Designated as Hedging Instrument | Derivative Instrument Assets
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	0.0	0.0
Fair value of liability derivatives presented above	0.2	5.7
Gas Utility | Operating Segments | Natural gas contracts | Not Designated as Hedging Instrument | Accounts Receivable – Other
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	5.4	1.2
Fair value of liability derivatives presented above	1.6	16.4
Gas Utility | Operating Segments | Natural gas contracts | Not Designated as Hedging Instrument | Deferred Charges – Other
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above		0.0
Fair value of liability derivatives presented above		0.2
Gas Marketing | Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above		5.2
Fair value of liability derivatives presented above		4.0
Gas Marketing | Operating Segments | Natural gas contracts | Designated as Hedging Instrument | Derivative Instrument Assets
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	2.5	4.1
Fair value of liability derivatives presented above	0.8	3.2
Gas Marketing | Operating Segments | Natural gas contracts | Designated as Hedging Instrument | Deferred Charges – Other
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	0.4	1.1
Fair value of liability derivatives presented above	0.1	0.5
Gas Marketing | Operating Segments | NYMEX / ICE natural gas contracts | Not Designated as Hedging Instrument | Derivative Instrument Assets
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	0.8	4.7
Fair value of liability derivatives presented above	4.1	0.6
Gas Marketing | Operating Segments | NYMEX / ICE natural gas contracts | Not Designated as Hedging Instrument | Deferred Charges – Other
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	0.0	0.7
Fair value of liability derivatives presented above	0.1	0.7
Gas Marketing | Operating Segments | Natural gas commodity contracts | Not Designated as Hedging Instrument | Derivative Instrument Assets
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	6.5	1.4
Fair value of liability derivatives presented above	0.2	0.1
Gas Marketing | Operating Segments | Natural gas commodity contracts | Not Designated as Hedging Instrument | Deferred Charges – Other
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	2.1
Fair value of liability derivatives presented above	0.3
Gas Marketing | Operating Segments | Natural gas commodity contracts | Not Designated as Hedging Instrument | Current Liabilities – Other
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	0.2	0.2
Fair value of liability derivatives presented above	2.0	1.4
Gas Marketing | Operating Segments | Natural gas commodity contracts | Not Designated as Hedging Instrument | Deferred Credits – Other
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	0.2	0.1
Fair value of liability derivatives presented above	0.1	0.7
Other Segments | Other | Interest rate swaps | Designated as Hedging Instrument | Derivative Instrument Assets
Derivatives, Fair Value [Line Items]
Fair value of liability derivatives presented above	3.0
Laclede Gas
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	5.7	1.2
Fair value of liability derivatives presented above	1.8	22.6
Laclede Gas | Gas Utility
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	5.7	1.2
Fair value of liability derivatives presented above	1.8	22.6
Laclede Gas | Gas Utility | Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	0.3	0.0
Fair value of liability derivatives presented above	0.0	0.3
Laclede Gas | Gas Utility | Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	5.4	1.2
Fair value of liability derivatives presented above	1.8	22.3
Laclede Gas | Gas Utility | Gasoline and heating oil contracts | Designated as Hedging Instrument | Derivative Instrument Assets
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	0.3
Fair value of liability derivatives presented above	0.0
Laclede Gas | Gas Utility | Gasoline and heating oil contracts | Designated as Hedging Instrument | Accounts Receivable – Other
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above		0.0
Fair value of liability derivatives presented above		0.3
Laclede Gas | Gas Utility | Natural gas contracts | Not Designated as Hedging Instrument | Derivative Instrument Assets
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above		0.0
Fair value of liability derivatives presented above		5.7
Laclede Gas | Gas Utility | Natural gas contracts | Not Designated as Hedging Instrument | Accounts Receivable – Other
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	5.4	1.2
Fair value of liability derivatives presented above	1.6	16.4
Laclede Gas | Gas Utility | Natural gas contracts | Not Designated as Hedging Instrument | Deferred Charges – Other
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above		0.0
Fair value of liability derivatives presented above		$ 0.2
Laclede Gas | Gas Utility | OTCBB natural gas contracts | Not Designated as Hedging Instrument | Derivative Instrument Assets
Derivatives, Fair Value [Line Items]
Fair value of asset derivatives presented above	0.0
Fair value of liability derivatives presented above	$ 0.2

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Instruments Reconciliation (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Offsetting Derivative Assets [Abstract]
Fair value of asset derivatives presented above	$ 18.4	$ 13.5
Fair value of cash margin receivables offset with derivatives	2.5	13.9
Netting of assets and liabilities with the same counterparty	(7.6)	(22.2)
Derivative asset after the effects of netting	13.3	5.2
Derivative instrument assets	11.4	4.6
Deferred Charges – Other	1.9	0.6
Offsetting Derivative Liabilities [Abstract]
Fair value of liability derivatives presented above	12.5	29.8
Netting of assets and liabilities with the same counterparty	(7.6)	(22.2)
Derivative liability after the effects of netting	4.9	7.6
Current Liabilities – Other	4.8	6.8
Deferred Credits – Other	0.1	0.8
Laclede Gas
Offsetting Derivative Assets [Abstract]
Fair value of asset derivatives presented above	5.7	1.2
Fair value of cash margin receivables offset with derivatives	0.8	15.5
Netting of assets and liabilities with the same counterparty	(1.6)	(16.7)
Derivative asset after the effects of netting	4.9	0.0
Derivative instrument assets	4.9	0.0
Offsetting Derivative Liabilities [Abstract]
Fair value of liability derivatives presented above	1.8	22.6
Netting of assets and liabilities with the same counterparty	(1.6)	(16.7)
Derivative liability after the effects of netting	0.2	5.9
Current Liabilities – Other	0.2	5.7
Deferred Credits – Other	$ 0.0	$ 0.2

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CONCENTRATIONS OF CREDIT RISK (Details) $ in Millions	Sep. 30, 2016 USD ($) counterparty
Concentration Risk [Line Items]
Number of large counterparties for which credit risk is disclosed | counterparty	5
Energy Producers And Their Affiliates
Concentration Risk [Line Items]
Accounts receivable	$ 15.8
Net receivable amount	12.4
Utility Companies And Their Affiliates
Concentration Risk [Line Items]
Accounts receivable	52.8
Net receivable amount	50.5
Largest Counterparties
Concentration Risk [Line Items]
Accounts receivable	31.2
Net receivable amount	$ 27.2

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INCOME TAXES - Narrative (Details) - USD ($)	Sep. 30, 2016	Sep. 30, 2015
Tax Credit Carryforward [Line Items]
Federal and state loss carryforwards	$ 297,000,000
Contribution carryforwards	12,200,000
Valuation allowance	900,000	$ 0
Tax credit carryforwards	3,500,000
Unrecognized tax benefits affect on the Company's effective tax rate	3,300,000	3,100,000
Income taxes accrued	0	0
income tax penalties accrued	0
Laclede Gas
Tax Credit Carryforward [Line Items]
Federal and state loss carryforwards	105,000,000
Contribution carryforwards	12,000,000
Valuation allowance	900,000	0
Tax credit carryforwards	2,000,000
Unrecognized tax benefits affect on the Company's effective tax rate	3,100,000	2,900,000
Income taxes accrued	0	0
income tax penalties accrued	0	$ 0
Alagasco
Tax Credit Carryforward [Line Items]
Federal and state loss carryforwards	$ 159,000,000

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INCOME TAXES - Net Provisions for Income Taxes (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Federal
Current		$ 0.1	$ (3.3)	$ 0.3
Deferred		62.0	58.8	30.6
Investment tax credits		(0.2)	(0.2)	(0.2)
State and local
Current		0.6	0.0	0.6
Deferred		7.0	6.9	1.0
Total income tax expense		69.5	62.2	32.3
Laclede Gas
Federal
Current		0.0	(2.1)	(0.1)
Deferred		37.5	40.9	34.3
Investment tax credits		(0.2)	(0.2)	(0.2)
State and local
Current		0.1	(0.1)	0.0
Deferred		8.0	4.7	1.5
Total income tax expense		45.4	43.2	$ 35.5
Alagasco
Federal
Current	$ 14.1	(0.8)	0.0
Deferred	3.5	29.4	25.9
State and local
Current	1.8	0.0	0.1
Deferred	0.5	3.8	3.3
Total income tax expense	$ 19.9	$ 32.4	$ 29.3

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INCOME TAXES - Effective Income Tax Rate Variation from Stated Tax Rate (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Income Tax Contingency [Line Items]
Federal income tax statutory rate		35.00%	35.00%	35.00%
State and local income taxes, net of federal income tax benefits		2.80%	3.00%	1.80%
Certain expenses capitalized on books and deducted on tax return		(3.40%)	(3.70%)	(4.90%)
Taxes related to prior years		(0.20%)	(0.60%)	(0.70%)
Other items – net		(1.70%)	(2.50%)	(3.60%)
Effective income tax rate		32.50%	31.20%	27.60%
Laclede Gas
Income Tax Contingency [Line Items]
Federal income tax statutory rate		35.00%	35.00%	35.00%
State and local income taxes, net of federal income tax benefits		2.80%	2.80%	1.80%
Certain expenses capitalized on books and deducted on tax return		(4.80%)	(4.90%)	(4.50%)
Taxes related to prior years		(0.20%)	(0.80%)	(0.70%)
Other items – net		(2.80%)	(3.00%)	(3.30%)
Effective income tax rate		30.00%	29.10%	28.30%
Alagasco
Income Tax Contingency [Line Items]
Federal income tax statutory rate	35.00%	35.00%	35.00%
State and local income taxes, net of federal income tax benefits	2.80%	2.80%	2.80%
Other items – net	(0.20%)	0.10%	0.10%
Effective income tax rate	37.60%	37.90%	37.90%

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INCOME TAXES - Significant Items in Net Deferred Tax Liability (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Deferred tax assets:
Reserves not currently deductible	$ 21.3	$ 14.8
Pension and other postretirement benefits	68.3	62.5
Operating losses	102.3	47.3
Other	0.0	1.5
Deferred tax assets	191.9	126.1
Less: valuation allowance	0.9	0.0
Total deferred tax assets	191.0	126.1
Deferred tax liabilities:
Relating to property	623.1	472.1
Regulatory pension and other postretirement benefits	106.8	110.6
Deferred gas costs	20.0	8.1
Other	48.4	11.6
Total deferred tax liabilities	798.3	602.4
Net deferred tax liability	607.3	476.3
Net deferred tax asset – current	0.0	5.8
Net deferred tax liability	607.3
Det deferred tax asset (liability) - noncurrent		482.1
Laclede Gas
Deferred tax assets:
Reserves not currently deductible	14.9	15.4
Pension and other postretirement benefits	56.9	62.5
Operating losses	29.9	3.7
Other	0.0	1.5
Deferred tax assets	101.7	83.1
Less: valuation allowance	0.9	0.0
Total deferred tax assets	100.8	83.1
Deferred tax liabilities:
Relating to property	497.0	425.0
Regulatory pension and other postretirement benefits	106.8	120.2
Deferred gas costs	20.0	8.2
Other	33.9	14.5
Total deferred tax liabilities	657.7	567.9
Net deferred tax liability	556.9	484.8
Net deferred tax asset – current	0.0	0.4
Net deferred tax liability	556.9
Det deferred tax asset (liability) - noncurrent		485.2
Alagasco
Deferred tax assets:
Reserves not currently deductible	6.3	7.0
Pension and other postretirement benefits	11.4	9.6
Goodwill	233.4	251.5
Operating losses	60.2	32.4
Other	0.0	1.4
Deferred tax assets	311.3	301.9
Deferred tax liabilities:
Relating to property	87.6	45.1
Other	2.3	2.2
Total deferred tax liabilities	89.9	47.3
Net deferred tax asset	221.4	254.6
Net deferred tax asset – current	0.0	6.2
Deferred income tax	$ 221.4
Deferred income tax		$ 248.4

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INCOME TAXES - Unrecognized Tax Benefit Reconciliation (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Unrecognized tax benefits [Roll Forward]
Unrecognized tax benefits, beginning of year		$ 7.1	$ 4.6	$ 2.4
Increases related to tax positions taken in current year		3.4	2.9	2.6
Reductions due to lapse of applicable statute of limitations		(0.5)	(0.4)	(0.4)
Unrecognized tax benefits, end of year	$ 4.6	10.0	7.1	4.6
Laclede Gas
Unrecognized tax benefits [Roll Forward]
Unrecognized tax benefits, beginning of year		6.9	4.2	2.0
Increases related to tax positions taken in current year		3.3	2.9	2.5
Reductions due to lapse of applicable statute of limitations		(0.5)	(0.2)	(0.3)
Unrecognized tax benefits, end of year	4.2	9.7	6.9	4.2
Alagasco
Unrecognized tax benefits [Roll Forward]
Unrecognized tax benefits, beginning of year	0.3	0.0	0.0
Reductions due to lapse of applicable statute of limitations	(0.3)	0.0	0.0
Unrecognized tax benefits, end of year	$ 0.0	$ 0.0	$ 0.0	$ 0.0

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014	Jan. 01, 2011	Feb. 20, 2010
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Extent of Lump-sum payments recognized, percentage	100.00%
Implementation period used to calculate return on plan assets	4 years
Gains or losses includible in cost amortized to extent exceeds benefit obligations or market-related value of plan assets, percentage	10.00%
Anticipated Contributions to pension plans for qualified trust	$ 29.0
Anticipated contributions to pension plans for non-qualified plans	$ 0.6
Medical insurance available until age is reached after early retirement	65 years
Recovery in rates for postretirement benefit				$ 9.5
Laclede Gas
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Recovery in rates for the qualified pension plans base allowance				$ 15.5
Other Plans [Abstract]
401(K) plans, cost of defined contributions	$ 8.2	$ 8.0	$ 6.7
Alagasco
Other Plans [Abstract]
401(K) plans, cost of defined contributions	2.3	3.0	4.7
Missouri Gas Energy (MGE)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Recovery in rates for the qualified pension plans base allowance					$ 10.0
Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Settlement benefits paid	$ 16.6	$ 71.1	$ 22.1
Pension Plans | Laclede Gas
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted allocation of plan assets	100.00%	100.00%
Settlement benefits paid	$ 0.0	$ 58.2
Pension Plans | Alagasco
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted allocation of plan assets	100.00%	100.00%
Settlement benefits paid	$ 16.6	$ 12.9
Postretirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Anticipated contributions to the postretirement plans for qualified trusts	10.3
Anticipated payment directly to participants in postretirement plan	$ 0.4
Postretirement Plans | Laclede Gas
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted allocation of plan assets	100.00%
Postretirement Plans | Alagasco
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted allocation of plan assets	100.00%
Equity markets | Pension Plans | Laclede Gas
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted allocation of plan assets	56.20%	52.00%
Equity markets | Pension Plans | Alagasco
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted allocation of plan assets	60.00%	60.00%
Equity markets | Postretirement Plans | Laclede Gas
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted allocation of plan assets	60.00%
Equity markets | Postretirement Plans | Alagasco
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted allocation of plan assets	60.00%
Debt securities | Pension Plans | Laclede Gas
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted allocation of plan assets	43.80%	48.00%
Debt securities | Postretirement Plans | Laclede Gas
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted allocation of plan assets	40.00%
Debt securities | Postretirement Plans | Alagasco
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted allocation of plan assets	40.00%

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Net Periodic Cost (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Pension Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost – benefits earned during the period		$ 15.3	$ 17.3	$ 10.2
Interest cost on projected benefit obligation		28.0	29.5	24.5
Expected return on plan assets		(34.9)	(37.4)	(27.2)
Amortization of other comprehensive income		0.0	0.0	0.4
Amortization of prior service cost		0.4	0.5	0.5
Amortization of actuarial loss		8.0	7.5	7.1
Loss on lump-sum settlements		3.3	19.6	1.5
Special termination benefits		1.6	0.0	0.0
Subtotal		21.7	37.0	17.0
Regulatory adjustment		17.8	(2.1)	10.4
Net benefit cost		39.5	34.9	27.4
Postretirement Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost – benefits earned during the period		10.9	12.8	11.3
Interest cost on projected benefit obligation		10.2	11.2	8.9
Expected return on plan assets		(13.5)	(13.2)	(7.3)
Amortization of other comprehensive income		0.0	0.0	(0.2)
Amortization of prior service cost		0.3	0.8	0.0
Amortization of actuarial loss		3.6	5.1	6.0
Special termination benefits		2.6	0.0	0.0
Subtotal		14.1	16.7	18.7
Regulatory adjustment		(6.6)	(11.0)	(9.6)
Net benefit cost		7.5	5.7	9.1
Laclede Gas | Pension Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost – benefits earned during the period		10.0	11.5	9.7
Interest cost on projected benefit obligation		21.7	23.3	24.0
Expected return on plan assets		(26.7)	(29.2)	(26.5)
Amortization of other comprehensive income		0.0	0.0	0.0
Amortization of prior service cost		0.4	0.5	0.5
Amortization of actuarial loss		7.9	7.5	7.1
Loss on lump-sum settlements		0.0	18.0	1.5
Special termination benefits		1.6	0.0	0.0
Subtotal		14.9	31.6	16.3
Regulatory adjustment		11.7	(5.2)	10.4
Net benefit cost		26.6	26.4	26.7
Laclede Gas | Postretirement Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost – benefits earned during the period		10.6	12.3	11.2
Interest cost on projected benefit obligation		8.1	8.6	8.7
Expected return on plan assets		(8.5)	(8.1)	(6.8)
Amortization of other comprehensive income		0.0	0.0	0.0
Amortization of prior service cost		0.3	0.8	0.0
Amortization of actuarial loss		3.8	5.1	6.0
Special termination benefits		2.6	0.0	0.0
Subtotal		16.9	18.7	19.1
Regulatory adjustment		(4.8)	(9.2)	(9.6)
Net benefit cost		12.1	9.5	$ 9.5
Alagasco | Pension Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost – benefits earned during the period	$ 5.1	5.3	5.8
Interest cost on projected benefit obligation	4.1	6.3	6.2
Expected return on plan assets	(5.2)	(8.2)	(8.2)
Amortization of other comprehensive income	0.0	0.0	0.0
Amortization of prior service cost	0.1	0.0	0.0
Amortization of actuarial loss	2.2	0.1	0.0
Loss on lump-sum settlements	10.1	3.3	1.6
Special termination benefits	0.0	0.0	0.0
Subtotal	16.4	6.8	5.4
Regulatory adjustment	0.4	6.1	3.1
Net benefit cost	16.8	12.9	8.5
Alagasco | Postretirement Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost – benefits earned during the period	0.4	0.3	0.5
Interest cost on projected benefit obligation	1.9	2.1	2.6
Expected return on plan assets	(3.6)	(5.0)	(5.1)
Amortization of other comprehensive income	0.0	0.0	0.0
Amortization of prior service cost	0.0	0.0	0.0
Amortization of actuarial loss	(1.0)	(0.2)	0.0
Special termination benefits	0.0	0.0	0.0
Subtotal	(2.3)	(2.8)	(2.0)
Regulatory adjustment	(0.2)	(1.8)	(1.8)
Net benefit cost	$ (2.5)	$ (4.6)	$ (3.8)

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Changes in Plan Assets and Benefit Obligations (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amortization of actuarial loss		$ 0.3	$ (0.4)	$ (0.5)
Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current year actuarial loss		46.8	48.3	15.7
Amortization of actuarial loss		(8.0)	(7.5)	(7.1)
Acceleration of loss recognized due to settlement		(3.3)	(19.6)	(1.5)
Current year prior service credit		5.0	0.0	0.0
Amortization of prior service cost		(0.4)	(0.5)	(0.5)
Subtotal		40.1	20.7	6.6
Regulatory adjustment		(39.8)	(21.2)	(6.1)
Total recognized in OCI		0.3	(0.5)	0.5
Postretirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current year actuarial loss		0.8	(8.5)	(3.1)
Amortization of actuarial loss		(3.6)	(5.1)	(6.0)
Current year prior service credit		(1.8)	(4.9)	0.0
Amortization of prior service cost		(0.3)	(0.8)	2.5
Subtotal		(4.9)	(19.3)	(6.6)
Regulatory adjustment		4.9	19.3	6.6
Total recognized in OCI		0.0	0.0	0.0
Laclede Gas
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amortization of actuarial loss		0.3	(0.4)	(0.4)
Laclede Gas | Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current year actuarial loss		21.6	26.0	14.2
Amortization of actuarial loss		(7.9)	(7.5)	(7.1)
Acceleration of loss recognized due to settlement		0.0	(18.0)	(1.5)
Current year prior service credit		5.0	0.0	0.0
Amortization of prior service cost		(0.4)	(0.5)	(0.5)
Subtotal		18.3	0.0	5.1
Regulatory adjustment		(18.0)	(0.5)	(4.7)
Total recognized in OCI		0.3	(0.5)	0.4
Laclede Gas | Postretirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current year actuarial loss		1.4	(2.4)	(4.2)
Amortization of actuarial loss		(3.8)	(5.1)	(6.0)
Current year prior service credit		0.0	(4.9)	0.0
Amortization of prior service cost		(0.3)	(0.8)	2.5
Subtotal		(2.7)	(13.2)	(7.7)
Regulatory adjustment		2.7	13.2	7.7
Total recognized in OCI		0.0	0.0	$ 0.0
Alagasco | Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current year actuarial loss	$ 1.5	25.2	22.3
Amortization of actuarial loss	0.0	(0.1)	0.0
Acceleration of loss recognized due to settlement	0.0	(3.3)	(1.6)
Current year prior service credit	0.0	0.0	0.0
Amortization of prior service cost	0.0	0.0	0.0
Subtotal	1.5	21.8	20.7
Regulatory adjustment	(1.5)	(21.8)	(20.7)
Total recognized in OCI	0.0	0.0	0.0
Alagasco | Postretirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current year actuarial loss	1.1	(0.6)	(6.1)
Amortization of actuarial loss	0.0	0.2	0.0
Current year prior service credit	0.0	(1.8)	0.0
Amortization of prior service cost	0.0	0.0	0.0
Subtotal	1.1	(2.2)	(6.1)
Regulatory adjustment	(1.1)	2.2	6.1
Total recognized in OCI	$ 0.0	$ 0.0	$ 0.0

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Benefit Obligation Rollforward (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Pension Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of year		$ 652.3	$ 692.4
Service cost		15.3	17.3	$ 10.2
Interest cost		28.0	29.5	24.5
Actuarial loss (gain)		85.8	(12.8)
Plan amendments		5.1	0.0
EnergySouth acquisition		60.4	0.0
Settlement loss		1.1	16.5
Special termination benefits		1.6	0.0
Settlement benefits paid		(16.6)	(71.1)	(22.1)
Regular benefits paid		(38.3)	(19.5)
Benefit obligation, end of year	$ 692.4	794.7	652.3	692.4
Accumulated benefit obligation, end of year		724.5	591.4
Postretirement Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of year		239.2	258.5
Service cost		10.9	12.8	11.3
Interest cost		10.2	11.2	8.9
Actuarial loss (gain)		7.1	(23.7)
Plan amendments		(1.8)	(4.9)
EnergySouth acquisition		5.9	0.0
Special termination benefits		2.6	0.0
Retiree drug subsidy program		0.2	0.4
Regular benefits paid		(15.1)	(15.1)
Benefit obligation, end of year	258.5	259.2	239.2	258.5
Laclede Gas | Pension Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of year		497.6	543.6
Service cost		10.0	11.5	9.7
Interest cost		21.7	23.3	24.0
Actuarial loss (gain)		59.2	(20.7)
Plan amendments		5.1	0.0
EnergySouth acquisition		0.0	0.0
Settlement loss		0.0	14.5
Special termination benefits		1.6
Settlement benefits paid		0.0	(58.2)
Regular benefits paid		(35.2)	(16.4)
Benefit obligation, end of year	543.6	560.0	497.6	543.6
Accumulated benefit obligation, end of year		517.7	456.9
Laclede Gas | Postretirement Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of year		191.9	197.9
Service cost		10.6	12.3	11.2
Interest cost		8.1	8.6	8.7
Actuarial loss (gain)		6.7	(10.9)
Plan amendments		0.0	(4.9)
EnergySouth acquisition		0.0	0.0
Special termination benefits		2.6	0.0
Retiree drug subsidy program		0.0	0.0
Regular benefits paid		(12.0)	(11.1)
Benefit obligation, end of year	197.9	207.9	191.9	197.9
Alagasco | Pension Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of year		154.7	148.8
Service cost	5.1	5.3	5.8
Interest cost	4.1	6.3	6.2
Actuarial loss (gain)		26.6	7.9
Plan amendments		0.0	0.0
EnergySouth acquisition		0.0	0.0
Settlement loss		1.1	2.0
Special termination benefits			0.0
Settlement benefits paid		(16.6)	(12.9)
Regular benefits paid		(3.1)	(3.1)
Benefit obligation, end of year	148.8	174.3	154.7	148.8
Accumulated benefit obligation, end of year		149.8	134.5
Alagasco | Postretirement Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of year		47.3	60.6
Service cost	0.4	0.3	0.5
Interest cost	1.9	2.1	2.6
Actuarial loss (gain)		0.4	(12.8)
Plan amendments		(1.8)	0.0
EnergySouth acquisition		0.0	0.0
Special termination benefits		0.0	0.0
Retiree drug subsidy program		0.2	0.4
Regular benefits paid		(3.1)	(4.0)
Benefit obligation, end of year	$ 60.6	$ 45.4	$ 47.3	$ 60.6

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Fair Value of Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Pension Plans
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of year	$ 448.9	$ 506.6
Actual return on plan assets	75.1	(7.2)
Employer contributions	26.6	40.1
EnergySouth acquisition	44.8	0.0
Settlement benefits paid	(16.6)	(71.1)	$ (22.1)
Regular benefits paid	(38.3)	(19.5)
Fair value of plan assets, end of year	540.5	448.9	506.6
Funded status of plans, end of year	(254.2)	(203.4)
Postretirement Plans
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of year	223.3	222.5
Actual return on plan assets	19.9	(2.0)
Employer contributions	14.3	17.9
EnergySouth acquisition	4.0	0.0
Regular benefits paid	(15.1)	(15.1)
Fair value of plan assets, end of year	246.4	223.3	222.5
Funded status of plans, end of year	(12.8)	(15.9)
Laclede Gas | Pension Plans
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of year	339.9	387.4
Actual return on plan assets	64.4	(3.0)
Employer contributions	26.6	30.1
EnergySouth acquisition	0.0	0.0
Settlement benefits paid	0.0	(58.2)
Regular benefits paid	(35.2)	(16.4)
Fair value of plan assets, end of year	395.7	339.9	387.4
Funded status of plans, end of year	(164.3)	(157.7)
Laclede Gas | Postretirement Plans
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of year	143.6	137.2
Actual return on plan assets	13.8	(0.4)
Employer contributions	14.3	17.9
EnergySouth acquisition	0.0	0.0
Regular benefits paid	(12.0)	(11.1)
Fair value of plan assets, end of year	159.7	143.6	137.2
Funded status of plans, end of year	(48.2)	(48.3)
Alagasco | Pension Plans
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of year	109.0	119.2
Actual return on plan assets	10.7	(4.2)
Employer contributions	0.0	10.0
EnergySouth acquisition	0.0	0.0
Settlement benefits paid	(16.6)	(12.9)
Regular benefits paid	(3.1)	(3.1)
Fair value of plan assets, end of year	100.0	109.0	119.2
Funded status of plans, end of year	(74.3)	(45.7)
Alagasco | Postretirement Plans
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of year	79.7	85.3
Actual return on plan assets	6.2	(1.6)
Employer contributions	0.0	0.0
EnergySouth acquisition	0.0	0.0
Regular benefits paid	(3.1)	(4.0)
Fair value of plan assets, end of year	82.8	79.7	$ 85.3
Funded status of plans, end of year	$ 37.4	$ 32.4

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Amounts Recognized in Consolidated Balance Sheets (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Noncurrent liabilities	$ (303.7)	$ (253.4)
Pension Plans
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Current liabilities	(0.6)	(0.5)
Noncurrent liabilities	(253.6)	(202.9)
Total	(254.2)	(203.4)
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
Net actuarial loss	179.4	143.9
Prior service costs	8.2	3.5
Subtotal	187.6	147.4
Adjustments for amounts included in regulatory assets	(184.8)	(144.9)
Total	2.8	2.5
Postretirement Plans
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Current assets	0.3	0.0
Noncurrent assets	37.4	35.5
Current liabilities	(0.4)	(0.3)
Noncurrent liabilities	(50.1)	(51.1)
Total	(12.8)	(15.9)
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
Net actuarial loss	38.0	40.8
Prior service costs	(5.2)	(3.1)
Subtotal	32.8	37.7
Adjustments for amounts included in regulatory assets	(32.8)	(37.7)
Total	0.0	0.0
Laclede Gas
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Noncurrent liabilities	(211.8)	(207.8)
Laclede Gas | Pension Plans
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Current liabilities	(0.6)	(0.5)
Noncurrent liabilities	(163.7)	(157.2)
Total	(164.3)	(157.7)
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
Net actuarial loss	135.5	121.9
Prior service costs	8.2	3.5
Subtotal	143.7	125.4
Adjustments for amounts included in regulatory assets	(140.9)	(122.9)
Total	2.8	2.5
Laclede Gas | Postretirement Plans
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Current assets	0.3	0.0
Noncurrent assets	0.0	3.1
Current liabilities	(0.4)	(0.3)
Noncurrent liabilities	(48.1)	(51.1)
Total	(48.2)	(48.3)
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
Net actuarial loss	43.4	45.8
Prior service costs	(3.4)	(3.1)
Subtotal	40.0	42.7
Adjustments for amounts included in regulatory assets	(40.0)	(42.7)
Total	0.0	0.0
Alagasco
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Noncurrent liabilities	(74.3)	(45.6)
Alagasco | Pension Plans
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Current liabilities	0.0	0.0
Noncurrent liabilities	(74.3)	(45.7)
Total	(74.3)	(45.7)
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
Net actuarial loss	43.9	22.0
Prior service costs	0.0	0.0
Subtotal	43.9	22.0
Adjustments for amounts included in regulatory assets	(43.9)	(22.0)
Total	0.0	0.0
Alagasco | Postretirement Plans
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Current assets	0.0	0.0
Noncurrent assets	37.4	32.4
Current liabilities	0.0	0.0
Noncurrent liabilities	0.0	0.0
Total	37.4	32.4
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
Net actuarial loss	(5.4)	(5.0)
Prior service costs	(1.8)	0.0
Subtotal	(7.2)	(5.0)
Adjustments for amounts included in regulatory assets	7.2	5.0
Total	$ 0.0	$ 0.0

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Pre-tax Amortization from AOCI (Details) $ in Millions	12 Months Ended
	Sep. 30, 2016 USD ($)
Pension Plans
Pre-tax amounts are expected to be amortized from accumulated other comprehensive income [Abstract]
Amortization of net actuarial loss (gain)	$ 13.5
Amortization of prior service cost	1.0
Subtotal	14.5
Regulatory adjustment	(14.2)
Total	0.3
Postretirement Plans
Pre-tax amounts are expected to be amortized from accumulated other comprehensive income [Abstract]
Amortization of net actuarial loss (gain)	2.4
Amortization of prior service cost	0.1
Subtotal	2.5
Regulatory adjustment	(2.5)
Total	0.0
Laclede Gas | Pension Plans
Pre-tax amounts are expected to be amortized from accumulated other comprehensive income [Abstract]
Amortization of net actuarial loss (gain)	11.6
Amortization of prior service cost	1.0
Subtotal	12.6
Regulatory adjustment	(12.3)
Total	0.3
Laclede Gas | Postretirement Plans
Pre-tax amounts are expected to be amortized from accumulated other comprehensive income [Abstract]
Amortization of net actuarial loss (gain)	2.5
Amortization of prior service cost	0.3
Subtotal	2.8
Regulatory adjustment	(2.8)
Total	0.0
Alagasco | Pension Plans
Pre-tax amounts are expected to be amortized from accumulated other comprehensive income [Abstract]
Amortization of net actuarial loss (gain)	1.9
Amortization of prior service cost	0.0
Subtotal	1.9
Regulatory adjustment	(1.9)
Total	0.0
Alagasco | Postretirement Plans
Pre-tax amounts are expected to be amortized from accumulated other comprehensive income [Abstract]
Amortization of net actuarial loss (gain)	(0.1)
Amortization of prior service cost	(0.2)
Subtotal	(0.3)
Regulatory adjustment	0.3
Total	$ 0.0

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Assumptions Used to Calculate Net Periodic Cost and Benefit Obligations (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Alagasco | Pension Plans
Assumptions used to calculate net periodic cost [Abstract]
Weighted average rate of future compensation increase	2.92%	3.00%	2.92%
Expected long-term rate of return on plan assets		7.50%
Alagasco | Pension Plans | Minimum
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate	4.00%	4.25%	4.15%
Expected long-term rate of return on plan assets	7.00%		7.00%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate		3.45%	4.25%
Alagasco | Pension Plans | Maximum
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate	4.05%	4.30%	4.25%
Expected long-term rate of return on plan assets	7.25%		7.25%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate		3.50%	4.30%
Alagasco | Postretirement Plans
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate		4.50%	4.40%	4.25%
Weighted average rate of future compensation increase				2.92%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate		3.60%	4.50%
Alagasco | Postretirement Plans | Minimum
Assumptions used to calculate net periodic cost [Abstract]
Expected long-term rate of return on plan assets	4.75%	4.50%	4.75%
Alagasco | Postretirement Plans | Maximum
Assumptions used to calculate net periodic cost [Abstract]
Expected long-term rate of return on plan assets	7.25%	7.25%	7.50%
Laclede Gas | Pension Plans
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate		4.40%	4.30%	4.70%
Weighted average rate of future compensation increase		3.00%	3.00%	3.00%
Expected long-term rate of return on plan assets		7.75%	7.75%	7.75%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate		3.50%	4.40%
Laclede Gas | Postretirement Plans
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate		4.00%	4.15%	4.60%
Weighted average rate of future compensation increase		3.00%	3.00%	3.00%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate		3.15%	4.00%
Weighted average rate of future compensation increase		3.00%	3.00%
Laclede Gas | Postretirement Plans | Minimum
Assumptions used to calculate net periodic cost [Abstract]
Expected long-term rate of return on plan assets		6.00%	6.25%	6.25%
Laclede Gas | Postretirement Plans | Maximum
Assumptions used to calculate net periodic cost [Abstract]
Expected long-term rate of return on plan assets		7.75%	7.75%	7.75%
Missouri Gas Energy (MGE) | Pension Plans
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate		4.50%	4.45%	5.00%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate		3.50%	4.50%
Missouri Gas Energy (MGE) | Postretirement Plans
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate		4.30%	4.40%	4.95%
Expected long-term rate of return on plan assets		4.75%	5.00%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate		3.45%	4.30%
Missouri Gas Energy (MGE) | Postretirement Plans | Minimum
Assumptions used to calculate net periodic cost [Abstract]
Expected long-term rate of return on plan assets				3.75%
Missouri Gas Energy (MGE) | Postretirement Plans | Maximum
Assumptions used to calculate net periodic cost [Abstract]
Expected long-term rate of return on plan assets				5.75%
Laclede Gas, Alabama Gas Company, And Missouri Gas Energy | Pension Plans
Assumptions used to calculate benefit obligations [Abstract]
Weighted average rate of future compensation increase		3.00%	3.00%

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Projected Benefit Obligation (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 794.8	$ 652.3
Accumulated benefit obligation	724.5	591.4
Fair value of plan assets	540.5	448.9
Laclede Gas
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	560.0	497.6
Accumulated benefit obligation	517.7	456.9
Fair value of plan assets	395.7	339.9
Alagasco
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	174.3	154.7
Accumulated benefit obligation	149.8	134.5
Fair value of plan assets	$ 100.0	$ 109.0

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Targeted and Actual Plan Assets by Category (Details)	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Alagasco | Pension Plans
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	100.00%	100.00%
Actual allocation of plan assets	100.00%	100.00%
Alagasco | Pension Plans | Equity markets
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	60.00%	60.00%
Actual allocation of plan assets	59.20%	52.90%
Alagasco | Pension Plans | Commodity Contract [Member]
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	29.00%	29.00%
Actual allocation of plan assets	28.80%	27.90%
Alagasco | Pension Plans | Real Estate [Member]
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	11.00%	11.00%
Actual allocation of plan assets	12.00%	19.20%
Alagasco | Postretirement Plans
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	100.00%
Actual allocation of plan assets	100.00%	100.00%
Alagasco | Postretirement Plans | Equity markets
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	60.00%
Actual allocation of plan assets	60.50%	59.70%
Alagasco | Postretirement Plans | Debt securities
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	40.00%
Actual allocation of plan assets	39.50%	40.30%
Laclede Gas | Pension Plans
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	100.00%	100.00%
Actual allocation of plan assets	100.00%	100.00%
Laclede Gas | Pension Plans | Equity markets
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	56.20%	52.00%
Actual allocation of plan assets	56.90%	48.40%
Laclede Gas | Pension Plans | Debt securities
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	43.80%	48.00%
Actual allocation of plan assets	43.10%	50.10%
Laclede Gas | Pension Plans | Other
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	0.00%	0.00%
Actual allocation of plan assets	0.00%	1.50%
Laclede Gas | Postretirement Plans
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	100.00%
Actual allocation of plan assets	100.00%	100.00%
Laclede Gas | Postretirement Plans | Equity markets
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	60.00%
Actual allocation of plan assets	59.10%	59.60%
Laclede Gas | Postretirement Plans | Debt securities
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	40.00%
Actual allocation of plan assets	39.40%	39.70%
Laclede Gas | Postretirement Plans | Other
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	0.00%
Actual allocation of plan assets	1.50%	0.70%

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Expected Future Benefit Payments (Details) $ in Millions	Sep. 30, 2016 USD ($)
Pension Plans
Expected benefit payments [Abstract]
2017	$ 61.3
2018	56.2
2019	57.1
2020	56.6
2021	56.8
2022 - 2026	286.3
Postretirement Plans
Expected benefit payments [Abstract]
2017	15.4
2018	16.7
2019	17.9
2020	19.1
2021	20.1
2022 - 2026	108.6
Laclede Gas | Pension Plans
Expected benefit payments [Abstract]
2017	48.2
2018	43.3
2019	43.5
2020	42.2
2021	40.4
2022 - 2026	196.6
Laclede Gas | Postretirement Plans
Expected benefit payments [Abstract]
2017	12.3
2018	13.7
2019	14.8
2020	15.8
2021	16.8
2022 - 2026	92.5
Alagasco | Pension Plans
Expected benefit payments [Abstract]
2017	10.9
2018	10.6
2019	11.2
2020	11.9
2021	13.7
2022 - 2026	74.5
Alagasco | Postretirement Plans
Expected benefit payments [Abstract]
2017	2.9
2018	2.8
2019	2.8
2020	2.9
2021	2.9
2022 - 2026	$ 14.1

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Assumed Medical Cost Trend Rates and Effect of 1% Changed (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Rate to which the medical cost trend rate is assumed to decline (the ultimate medical cost trend rate)	5.00%	5.00%
Year the rate reaches the ultimate trend	2023	2020
Assumed 1% change in the assumed medical cost trend rate [Abstract]
Effect of 1% increase on net periodic postretirement benefit cost	$ 1.5
Effect of 1% decrease on net periodic postretirement benefit cost	(1.4)
Effect of 1% increase on accumulated postretirement benefit obligation	11.0
Effect of 1% decrease on accumulated postretirement benefit obligation	$ (10.2)
Laclede Gas
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Medical cost trend assumed for next year	7.50%	7.00%
Assumed 1% change in the assumed medical cost trend rate [Abstract]
Effect of 1% increase on net periodic postretirement benefit cost	$ 1.5
Effect of 1% decrease on net periodic postretirement benefit cost	(1.4)
Effect of 1% increase on accumulated postretirement benefit obligation	9.0
Effect of 1% decrease on accumulated postretirement benefit obligation	$ (8.4)
Alagasco
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Medical cost trend assumed for next year	7.50%	7.00%
Assumed 1% change in the assumed medical cost trend rate [Abstract]
Effect of 1% increase on net periodic postretirement benefit cost	$ 0.0
Effect of 1% decrease on net periodic postretirement benefit cost	0.0
Effect of 1% increase on accumulated postretirement benefit obligation	1.3
Effect of 1% decrease on accumulated postretirement benefit obligation	$ (1.2)

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS - Fair Value Measurements of Plan Assets (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	$ 540.5	$ 448.9	$ 506.6
Pension Plans | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	51.2	43.6
Pension Plans | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	126.1	130.6
Pension Plans | US bond mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	149.0	9.3
Pension Plans | US government
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	45.1	58.7
Pension Plans | US corporate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	137.4	166.6
Pension Plans | US municipal
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	6.3	5.9
Pension Plans | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	25.3	31.3
Pension Plans | Derivative instruments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.1	2.9
Pension Plans | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	383.6	272.2
Pension Plans | Quoted Prices in Active Markets (Level 1) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	51.2	43.4
Pension Plans | Quoted Prices in Active Markets (Level 1) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	99.3	46.4
Pension Plans | Quoted Prices in Active Markets (Level 1) | US bond mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	23.0	0.0
Pension Plans | Quoted Prices in Active Markets (Level 1) | US government
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	42.1	58.7
Pension Plans | Quoted Prices in Active Markets (Level 1) | US corporate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	137.4	123.7
Pension Plans | Quoted Prices in Active Markets (Level 1) | US municipal
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	6.3	0.0
Pension Plans | Quoted Prices in Active Markets (Level 1) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	25.3	0.0
Pension Plans | Quoted Prices in Active Markets (Level 1) | Derivative instruments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	(1.0)	0.0
Pension Plans | Significant Observable Inputs (Level 2)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	156.8	167.1
Pension Plans | Significant Observable Inputs (Level 2) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.2
Pension Plans | Significant Observable Inputs (Level 2) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	26.7	74.6
Pension Plans | Significant Observable Inputs (Level 2) | US bond mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	126.0	9.3
Pension Plans | Significant Observable Inputs (Level 2) | US government
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	3.0	0.0
Pension Plans | Significant Observable Inputs (Level 2) | US corporate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	42.9
Pension Plans | Significant Observable Inputs (Level 2) | US municipal
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	5.9
Pension Plans | Significant Observable Inputs (Level 2) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	31.3
Pension Plans | Significant Observable Inputs (Level 2) | Derivative instruments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	1.1	2.9
Pension Plans | Significant Unobservable Inputs (Level 3)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.1	9.6
Pension Plans | Significant Unobservable Inputs (Level 3) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Pension Plans | Significant Unobservable Inputs (Level 3) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.1	9.6
Pension Plans | Significant Unobservable Inputs (Level 3) | US bond mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Pension Plans | Significant Unobservable Inputs (Level 3) | US government
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Pension Plans | Significant Unobservable Inputs (Level 3) | US corporate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Pension Plans | Significant Unobservable Inputs (Level 3) | US municipal
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Pension Plans | Significant Unobservable Inputs (Level 3) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Pension Plans | Significant Unobservable Inputs (Level 3) | Derivative instruments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Postretirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	246.4	223.3	222.5
Postretirement Plans | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	4.8	1.6
Postretirement Plans | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	226.4	208.3
Postretirement Plans | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	15.2	13.4
Postretirement Plans | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	163.6	117.1
Postretirement Plans | Quoted Prices in Active Markets (Level 1) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	4.8	1.6
Postretirement Plans | Quoted Prices in Active Markets (Level 1) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	157.9	115.5
Postretirement Plans | Quoted Prices in Active Markets (Level 1) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.9	0.0
Postretirement Plans | Significant Observable Inputs (Level 2)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	82.8	106.2
Postretirement Plans | Significant Observable Inputs (Level 2) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Postretirement Plans | Significant Observable Inputs (Level 2) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	68.5	92.8
Postretirement Plans | Significant Observable Inputs (Level 2) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	14.3	13.4
Postretirement Plans | Significant Unobservable Inputs (Level 3)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Postretirement Plans | Significant Unobservable Inputs (Level 3) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Postretirement Plans | Significant Unobservable Inputs (Level 3) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Postretirement Plans | Significant Unobservable Inputs (Level 3) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Laclede Gas | Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	395.7	339.9	387.4
Laclede Gas | Pension Plans | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	46.5	31.8
Laclede Gas | Pension Plans | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	14.9	67.7
Laclede Gas | Pension Plans | US bond mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	120.2
Laclede Gas | Pension Plans | US government
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	45.1	37.7
Laclede Gas | Pension Plans | US corporate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	137.4	166.6
Laclede Gas | Pension Plans | US municipal
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	6.3	5.9
Laclede Gas | Pension Plans | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	25.2	27.3
Laclede Gas | Pension Plans | Derivative instruments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		2.9
Laclede Gas | Pension Plans | Other
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.1
Laclede Gas | Pension Plans | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	256.5	193.2
Laclede Gas | Pension Plans | Quoted Prices in Active Markets (Level 1) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	46.5	31.8
Laclede Gas | Pension Plans | Quoted Prices in Active Markets (Level 1) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Laclede Gas | Pension Plans | Quoted Prices in Active Markets (Level 1) | US bond mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0
Laclede Gas | Pension Plans | Quoted Prices in Active Markets (Level 1) | US government
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	42.1	37.7
Laclede Gas | Pension Plans | Quoted Prices in Active Markets (Level 1) | US corporate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	137.4	123.7
Laclede Gas | Pension Plans | Quoted Prices in Active Markets (Level 1) | US municipal
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	6.3	0.0
Laclede Gas | Pension Plans | Quoted Prices in Active Markets (Level 1) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	25.2	0.0
Laclede Gas | Pension Plans | Quoted Prices in Active Markets (Level 1) | Derivative instruments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		0.0
Laclede Gas | Pension Plans | Quoted Prices in Active Markets (Level 1) | Other
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	(1.0)
Laclede Gas | Pension Plans | Significant Observable Inputs (Level 2)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	139.1	146.6
Laclede Gas | Pension Plans | Significant Observable Inputs (Level 2) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Laclede Gas | Pension Plans | Significant Observable Inputs (Level 2) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	14.8	67.6
Laclede Gas | Pension Plans | Significant Observable Inputs (Level 2) | US bond mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	120.2
Laclede Gas | Pension Plans | Significant Observable Inputs (Level 2) | US government
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	3.0	0.0
Laclede Gas | Pension Plans | Significant Observable Inputs (Level 2) | US corporate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	42.9
Laclede Gas | Pension Plans | Significant Observable Inputs (Level 2) | US municipal
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	5.9
Laclede Gas | Pension Plans | Significant Observable Inputs (Level 2) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	27.3
Laclede Gas | Pension Plans | Significant Observable Inputs (Level 2) | Derivative instruments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		2.9
Laclede Gas | Pension Plans | Significant Observable Inputs (Level 2) | Other
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	1.1
Laclede Gas | Pension Plans | Significant Unobservable Inputs (Level 3)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.1	0.1
Laclede Gas | Pension Plans | Significant Unobservable Inputs (Level 3) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Laclede Gas | Pension Plans | Significant Unobservable Inputs (Level 3) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.1	0.1
Laclede Gas | Pension Plans | Significant Unobservable Inputs (Level 3) | US bond mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0
Laclede Gas | Pension Plans | Significant Unobservable Inputs (Level 3) | US government
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Laclede Gas | Pension Plans | Significant Unobservable Inputs (Level 3) | US corporate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Laclede Gas | Pension Plans | Significant Unobservable Inputs (Level 3) | US municipal
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Laclede Gas | Pension Plans | Significant Unobservable Inputs (Level 3) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Laclede Gas | Pension Plans | Significant Unobservable Inputs (Level 3) | Derivative instruments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		0.0
Laclede Gas | Pension Plans | Significant Unobservable Inputs (Level 3) | Other
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0
Laclede Gas | Postretirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	159.7	143.6	137.2
Laclede Gas | Postretirement Plans | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	4.6	1.6
Laclede Gas | Postretirement Plans | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	155.1	142.0
Laclede Gas | Postretirement Plans | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	159.7	117.1
Laclede Gas | Postretirement Plans | Quoted Prices in Active Markets (Level 1) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	4.6	1.6
Laclede Gas | Postretirement Plans | Quoted Prices in Active Markets (Level 1) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	155.1	115.5
Laclede Gas | Postretirement Plans | Significant Observable Inputs (Level 2)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	26.5
Laclede Gas | Postretirement Plans | Significant Observable Inputs (Level 2) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Laclede Gas | Postretirement Plans | Significant Observable Inputs (Level 2) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	26.5
Laclede Gas | Postretirement Plans | Significant Unobservable Inputs (Level 3)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Laclede Gas | Postretirement Plans | Significant Unobservable Inputs (Level 3) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Laclede Gas | Postretirement Plans | Significant Unobservable Inputs (Level 3) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Alagasco | Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	100.0	109.0	119.2
Alagasco | Pension Plans | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.4	11.8
Alagasco | Pension Plans | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	70.9	62.9
Alagasco | Pension Plans | US bond mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	28.7	9.3
Alagasco | Pension Plans | US government
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		21.0
Alagasco | Pension Plans | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		4.0
Alagasco | Pension Plans | Derivative instruments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		0.0
Alagasco | Pension Plans | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	82.4	58.0
Alagasco | Pension Plans | Quoted Prices in Active Markets (Level 1) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.4	11.6
Alagasco | Pension Plans | Quoted Prices in Active Markets (Level 1) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	59.0	46.4
Alagasco | Pension Plans | Quoted Prices in Active Markets (Level 1) | US bond mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	23.0	0.0
Alagasco | Pension Plans | Quoted Prices in Active Markets (Level 1) | US government
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		0.0
Alagasco | Pension Plans | Quoted Prices in Active Markets (Level 1) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		0.0
Alagasco | Pension Plans | Quoted Prices in Active Markets (Level 1) | Derivative instruments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		0.0
Alagasco | Pension Plans | Significant Observable Inputs (Level 2)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	17.6	41.5
Alagasco | Pension Plans | Significant Observable Inputs (Level 2) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.2
Alagasco | Pension Plans | Significant Observable Inputs (Level 2) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	11.9	7.0
Alagasco | Pension Plans | Significant Observable Inputs (Level 2) | US bond mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	5.7	9.3
Alagasco | Pension Plans | Significant Observable Inputs (Level 2) | US government
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		21.0
Alagasco | Pension Plans | Significant Observable Inputs (Level 2) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		4.0
Alagasco | Pension Plans | Significant Observable Inputs (Level 2) | Derivative instruments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		0.0
Alagasco | Pension Plans | Significant Unobservable Inputs (Level 3)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	9.5
Alagasco | Pension Plans | Significant Unobservable Inputs (Level 3) | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Alagasco | Pension Plans | Significant Unobservable Inputs (Level 3) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	9.5
Alagasco | Pension Plans | Significant Unobservable Inputs (Level 3) | US bond mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Alagasco | Pension Plans | Significant Unobservable Inputs (Level 3) | US government
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		0.0
Alagasco | Pension Plans | Significant Unobservable Inputs (Level 3) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets		0.0
Alagasco | Postretirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	82.8	79.7	$ 85.3
Alagasco | Postretirement Plans | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	68.5	66.3
Alagasco | Postretirement Plans | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	14.3	13.4
Alagasco | Postretirement Plans | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Alagasco | Postretirement Plans | Quoted Prices in Active Markets (Level 1) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Alagasco | Postretirement Plans | Quoted Prices in Active Markets (Level 1) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Alagasco | Postretirement Plans | Significant Observable Inputs (Level 2)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	82.8	79.7
Alagasco | Postretirement Plans | Significant Observable Inputs (Level 2) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	68.5	66.3
Alagasco | Postretirement Plans | Significant Observable Inputs (Level 2) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	14.3	13.4
Alagasco | Postretirement Plans | Significant Unobservable Inputs (Level 3)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Alagasco | Postretirement Plans | Significant Unobservable Inputs (Level 3) | Stock/bond mutual fund
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.0	0.0
Alagasco | Postretirement Plans | Significant Unobservable Inputs (Level 3) | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	$ 0.0	$ 0.0

XML

INFORMATION BY OPERATING SEGMENT - Schedule of Operating Segment Information (Details) $ in Millions	3 Months Ended								12 Months Ended
	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2016 USD ($) operating_segment	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)
Segment Reporting, Revenue Reconciling Item [Line Items]
Number of operating segments | operating_segment									2
Operating Segment Information [Abstract]
Total Operating Revenues	$ 279.3	$ 249.3	$ 609.3	$ 399.4	$ 204.2	$ 275.2	$ 877.4	$ 619.6	$ 1,537.3	$ 1,976.4	$ 1,627.2
Gas Utility
Natural and propane gas									492.2	882.4	731.7
Other operation and maintenance expenses									377.5	390.6	287.8
Depreciation and amortization									136.9	129.9	82.4
Taxes, other than income taxes									125.2	142.1	112.0
Total Gas Utility Operating Expenses									1,131.8	1,545.0	1,213.9
Gas Marketing and other									123.2	158.9	246.9
Total Operating Expenses									1,255.0	1,703.9	1,460.8
Operating Income	(7.7)	$ 35.3	$ 167.7	$ 87.0	(8.5)	$ 36.0	$ 157.7	$ 87.3	282.3	272.5	166.4
Net Economic Earnings									149.1	138.3	100.1
Capital Expenditures									293.3	289.8	171.0
ASSETS
Total Assets	6,077.4				5,290.2				6,077.4	5,290.2	5,074.0
Eliminations
Operating Segment Information [Abstract]
Total Operating Revenues									(5.4)	(76.5)	(91.0)
Gas Utility
Natural and propane gas									(47.5)	(75.2)	(90.1)
Other operation and maintenance expenses									(1.8)	(1.0)	(0.9)
Depreciation and amortization									0.0	0.0	0.0
Taxes, other than income taxes									0.0	0.0	0.0
Total Gas Utility Operating Expenses									(49.3)	(76.2)	(91.0)
Gas Marketing and other									43.9	(0.3)	0.0
Total Operating Expenses									(5.4)	(76.5)	(91.0)
Operating Income									0.0	0.0	0.0
Net Economic Earnings									0.0	0.0	0.0
Capital Expenditures									0.0	0.0	0.0
ASSETS
Total Assets	(1,161.9)				(1,116.8)				(1,161.9)	(1,116.8)	(1,178.4)
Other
Operating Segment Information [Abstract]
Total Operating Revenues									1.6	1.7	2.0
Gas Utility
Depreciation and amortization expense									0.5	0.6	0.5
ASSETS
Total Assets	1,842.4				1,560.2				1,842.4	1,560.2	1,575.7
Corporate Eliminations
Operating Segment Information [Abstract]
Total Operating Revenues									3.2	2.0	1.8
Corporate And Eliminations
Operating Segment Information [Abstract]
Total Operating Revenues									4.8	3.7	3.8
Gas Utility
Natural and propane gas									0.0	0.0	0.0
Other operation and maintenance expenses									0.0	0.0	0.0
Depreciation and amortization									0.0	0.0	0.0
Taxes, other than income taxes									0.0	0.0	0.0
Total Gas Utility Operating Expenses									0.0	0.0	0.0
Gas Marketing and other									12.6	12.6	20.5
Total Operating Expenses									12.6	12.6	20.5
Operating Income									(7.8)	(8.9)	(16.7)
Net Economic Earnings									(17.6)	(16.3)	(2.9)
Capital Expenditures									1.6	5.4	2.4
Gas Utility
Operating Segment Information [Abstract]
Total Operating Revenues									1,457.2	1,891.8	1,462.6
Gas Utility | Operating Segments
Operating Segment Information [Abstract]
Total Operating Revenues									1,459.4	1,895.8	1,467.8
Gas Utility
Natural and propane gas									539.7	957.6	821.8
Other operation and maintenance expenses									379.3	391.6	288.7
Depreciation and amortization									136.9	129.9	82.4
Taxes, other than income taxes									125.2	142.1	112.0
Total Gas Utility Operating Expenses									1,181.1	1,621.2	1,304.9
Gas Marketing and other									0.0	0.0	0.0
Total Operating Expenses									1,181.1	1,621.2	1,304.9
Operating Income									278.3	274.6	162.9
Net Economic Earnings									160.3	150.4	92.8
Capital Expenditures									291.7	284.4	168.6
ASSETS
Total Assets	5,191.9				4,686.2				5,191.9	4,686.2	4,520.0
Gas Utility | Eliminations
Operating Segment Information [Abstract]
Total Operating Revenues									2.2	4.0	5.2
Gas Marketing
Operating Segment Information [Abstract]
Total Operating Revenues									78.5	82.9	162.6
Gas Marketing | Operating Segments
Operating Segment Information [Abstract]
Total Operating Revenues									78.5	153.4	246.6
Gas Utility
Natural and propane gas									0.0	0.0	0.0
Other operation and maintenance expenses									0.0	0.0	0.0
Depreciation and amortization									0.0	0.0	0.0
Taxes, other than income taxes									0.0	0.0	0.0
Total Gas Utility Operating Expenses									0.0	0.0	0.0
Gas Marketing and other									66.7	146.6	226.4
Total Operating Expenses									66.7	146.6	226.4
Operating Income									11.8	6.8	20.2
Net Economic Earnings									6.4	4.2	10.2
Capital Expenditures									0.0	0.0	0.0
Depreciation and amortization expense									0.1	0.3	0.4
ASSETS
Total Assets	$ 205.0				$ 160.6				205.0	160.6	156.7
Gas Marketing | Eliminations
Operating Segment Information [Abstract]
Total Operating Revenues									$ 0.0	$ 70.5	$ 84.0

XML

INFORMATION BY OPERATING SEGMENT - Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Segment Reporting [Abstract]
Net Income	$ (14.2)	$ 10.7	$ 100.8	$ 46.9	$ (18.7)	$ 14.1	$ 94.4	$ 47.1	$ 144.2	$ 136.9	$ 84.6
Unrealized gain on energy-related derivatives									(0.1)	(2.8)	(1.6)
Lower of cost or market inventory adjustments									0.2	0.4	(1.1)
Realized (gain) loss on economic hedges prior to the sale of the physical commodity									(1.6)	2.4	(0.4)
Acquisition, divestiture and restructuring activities									9.2	9.8	29.5
Gain on sale of property									0.0	(7.6)	0.0
Income tax effect of adjustments									(2.8)	(0.8)	(10.9)
Net Economic Earnings									$ 149.1	$ 138.3	$ 100.1

XML

REGULATORY MATTERS - Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Regulatory Assets [Line Items]
Regulatory assets, current	$ 93.9	$ 40.5
Regulatory assets, non current	838.0	737.6
Total Regulatory Assets	931.9	778.1
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	30.6	60.6
Regulatory liabilities, noncurrent	130.7	119.3
Total Regulatory Liabilities	161.3	179.9
RSE adjustment
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	7.5	12.2
Unbilled service margin
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	5.9	6.4
Pension and postretirement costs
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	9.3	10.8
Regulatory liabilities, noncurrent	9.4	16.2
Unamortized purchased gas adjustments
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	1.7	28.2
Postretirement liabilities
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	28.9	28.9
Accrued cost of removal
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	74.8	58.7
Other
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	6.2	3.0
Regulatory liabilities, noncurrent	17.6	15.5
Pension and postretirement benefit costs
Regulatory Assets [Line Items]
Regulatory assets, current	27.0	22.0
Regulatory assets, non current	487.9	448.7
Unamortized purchased gas adjustments
Regulatory Assets [Line Items]
Regulatory assets, current	49.7	12.9
Future income taxes due from customers
Regulatory Assets [Line Items]
Regulatory assets, non current	151.3	134.5
Accrued cost of removal
Regulatory Assets [Line Items]
Regulatory assets, non current	130.6	78.9
Purchased gas costs
Regulatory Assets [Line Items]
Regulatory assets, non current	12.6	24.1
Energy efficiency
Regulatory Assets [Line Items]
Regulatory assets, non current	25.5	22.3
Other
Regulatory Assets [Line Items]
Regulatory assets, current	17.2	5.6
Regulatory assets, non current	30.1	29.1
Laclede Gas
Regulatory Assets [Line Items]
Regulatory assets, current	67.0	29.1
Regulatory assets, non current	589.8	573.6
Total Regulatory Assets	656.8	602.7
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	1.3	0.6
Regulatory liabilities, noncurrent	67.3	70.6
Total Regulatory Liabilities	68.6	71.2
Laclede Gas | RSE adjustment
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	0.0	0.0
Laclede Gas | Unbilled service margin
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	0.0	0.0
Laclede Gas | Pension and postretirement costs
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	0.0	0.0
Regulatory liabilities, noncurrent	0.0	0.0
Laclede Gas | Unamortized purchased gas adjustments
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	0.0	0.0
Laclede Gas | Postretirement liabilities
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	0.0	0.0
Laclede Gas | Accrued cost of removal
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	55.1	58.7
Laclede Gas | Other
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	1.3	0.6
Regulatory liabilities, noncurrent	12.2	11.9
Laclede Gas | Pension and postretirement benefit costs
Regulatory Assets [Line Items]
Regulatory assets, current	20.2	15.5
Regulatory assets, non current	375.7	368.0
Laclede Gas | Unamortized purchased gas adjustments
Regulatory Assets [Line Items]
Regulatory assets, current	43.1	12.9
Laclede Gas | Future income taxes due from customers
Regulatory Assets [Line Items]
Regulatory assets, non current	151.3	134.5
Laclede Gas | Accrued cost of removal
Regulatory Assets [Line Items]
Regulatory assets, non current	0.0	0.0
Laclede Gas | Purchased gas costs
Regulatory Assets [Line Items]
Regulatory assets, non current	12.6	24.1
Laclede Gas | Energy efficiency
Regulatory Assets [Line Items]
Regulatory assets, non current	25.5	22.3
Laclede Gas | Other
Regulatory Assets [Line Items]
Regulatory assets, current	3.7	0.7
Regulatory assets, non current	24.7	24.7
Alagasco
Regulatory Assets [Line Items]
Regulatory assets, current	20.5	11.4
Regulatory assets, non current	230.7	163.6
Total Regulatory Assets	251.2	175.0
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	22.7	60.0
Regulatory liabilities, noncurrent	41.7	48.7
Total Regulatory Liabilities	64.4	108.7
Alagasco | RSE adjustment
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	5.0	12.2
Alagasco | Unbilled service margin
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	5.9	6.4
Alagasco | Pension and postretirement costs
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	9.3	10.8
Regulatory liabilities, noncurrent	9.4	16.2
Alagasco | Unamortized purchased gas adjustments
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	0.0	28.2
Alagasco | Postretirement liabilities
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	28.9	28.9
Alagasco | Accrued cost of removal
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	0.0	0.0
Alagasco | Other
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	2.5	2.4
Regulatory liabilities, noncurrent	3.4	3.6
Alagasco | Pension and postretirement benefit costs
Regulatory Assets [Line Items]
Regulatory assets, current	6.8	6.5
Regulatory assets, non current	98.9	80.7
Alagasco | Unamortized purchased gas adjustments
Regulatory Assets [Line Items]
Regulatory assets, current	5.6	0.0
Alagasco | Future income taxes due from customers
Regulatory Assets [Line Items]
Regulatory assets, non current	0.0	0.0
Alagasco | Accrued cost of removal
Regulatory Assets [Line Items]
Regulatory assets, non current	130.6	78.9
Alagasco | Purchased gas costs
Regulatory Assets [Line Items]
Regulatory assets, non current	0.0	0.0
Alagasco | Energy efficiency
Regulatory Assets [Line Items]
Regulatory assets, non current	0.0	0.0
Alagasco | Other
Regulatory Assets [Line Items]
Regulatory assets, current	8.1	4.9
Regulatory assets, non current	$ 1.2	$ 4.0

XML

REGULATORY MATTERS - Schedule of Regulatory Assets Not Earnings a Return (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Regulatory Assets [Line Items]
Total Regulatory Assets Not Earning a Return	$ 404.8	$ 372.4
Future income taxes due from customers
Regulatory Assets [Line Items]
Total Regulatory Assets Not Earning a Return	151.3	134.5
Pension and postretirement benefit costs
Regulatory Assets [Line Items]
Total Regulatory Assets Not Earning a Return	240.6	223.7
Compensated absences
Regulatory Assets [Line Items]
Total Regulatory Assets Not Earning a Return	0.0	0.0
Other
Regulatory Assets [Line Items]
Total Regulatory Assets Not Earning a Return	12.9	14.2
Laclede Gas
Regulatory Assets [Line Items]
Total Regulatory Assets Not Earning a Return	404.8	372.4
Laclede Gas | Future income taxes due from customers
Regulatory Assets [Line Items]
Total Regulatory Assets Not Earning a Return	151.3	134.5
Laclede Gas | Pension and postretirement benefit costs
Regulatory Assets [Line Items]
Total Regulatory Assets Not Earning a Return	240.6	223.7
Laclede Gas | Compensated absences
Regulatory Assets [Line Items]
Total Regulatory Assets Not Earning a Return	0.0	0.0
Laclede Gas | Other
Regulatory Assets [Line Items]
Total Regulatory Assets Not Earning a Return	$ 12.9	$ 14.2

XML

REGULATORY MATTERS - Narrative (Details) - USD ($)													12 Months Ended
	Oct. 01, 2017	Dec. 01, 2016	Oct. 26, 2016	Sep. 30, 2016	Jul. 31, 2016	May 31, 2016	May 19, 2016	Apr. 30, 2016	Jan. 31, 2016	Dec. 01, 2015	Nov. 12, 2015	Jan. 01, 2014	Sep. 30, 2016	Sep. 30, 2015	Nov. 11, 2016	Apr. 15, 2016	Feb. 10, 2016	Jun. 30, 2015
Public Utilities, General Disclosures [Line Items]
Regulatory assets for which no return on investment during recovery period is provided				$ 404,800,000									$ 404,800,000	$ 372,400,000
Remaining recovery period for regulatory assets for which no return on investment during recovery period is provided													15 years
Laclede Gas
Public Utilities, General Disclosures [Line Items]
Regulatory assets for which no return on investment during recovery period is provided				404,800,000									$ 404,800,000	372,400,000
Regulatory preferred stock and debt securities issuance, amount authorized				300,000,000									$ 300,000,000				$ 300,000,000.0	$ 518,000,000.0
Regulatory preferred stock and debt securities issuance, amount requested																$ 550,000,000
Alagasco
Public Utilities, General Disclosures [Line Items]
Potential performance-based adjustment													0.05%
APSC | Alagasco
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease) amount				$ (2,700,000)	$ (4,800,000)			$ (5,800,000)	$ 0				$ 7,800,000	$ 4,700,000
Approved return rate on equity												10.80%
Maximum return on equity, percentage of prior year revenues										4.00%
Rate increase (decrease), margin of index range				1.75%									1.75%
Infrastructure System Replacement Surcharge | MoPSC | Laclede Gas
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease) amount						$ 25,000,000	$ 5,400,000				$ 4,400,000
Approved rate increase, annualized revenue										$ 19,600,000
Requested rate increase				$ 5,000,000
Infrastructure System Replacement Surcharge | MoPSC | Missouri Gas Energy (MGE)
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease) amount						$ 10,300,000	$ 3,600,000				$ 1,900,000
Approved rate increase, annualized revenue										$ 6,700,000
Requested rate increase				$ 3,400,000
Subsequent Event | Laclede Gas
Public Utilities, General Disclosures [Line Items]
Regulatory preferred stock and debt securities issuance, authorized debt issuance - remaining available															$ 300,000,000
Subsequent Event | APSC | Alagasco
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease) amount	$ (4,800,000)		$ (1,300,000)
Minimum | APSC | Alagasco
Public Utilities, General Disclosures [Line Items]
Approved return rate on equity												10.50%
Maximum | APSC | Alagasco
Public Utilities, General Disclosures [Line Items]
Approved return rate on equity												10.95%
Scenario, Forecast | APSC | Alagasco
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease) amount		$ (2,700,000)

XML

COMMITMENTS AND CONTINGENCIES - Commitments (Details) MMcf in Thousands, $ in Millions	12 Months Ended
	Sep. 30, 2016 USD ($) MMcf
Long-term Purchase Commitment [Line Items]
Minimum total payments required for natural gas contracts	$ 1,647.8
Laclede Gas
Long-term Purchase Commitment [Line Items]
Minimum total payments required for natural gas contracts	1,227.6
Laclede Gas | Purchase Commitment | Subsidiary of Common Parent
Long-term Purchase Commitment [Line Items]
Annual purchase commitment	$ 1.0
Commitment termination minimum required notification period	6 months
Alagasco
Long-term Purchase Commitment [Line Items]
Minimum total payments required for natural gas contracts	$ 352.7
Alagasco | Inventories
Long-term Purchase Commitment [Line Items]
Minimum volume purchase commitment required (in Mmcf) | MMcf	93

XML

COMMITMENTS AND CONTINGENCIES - Leases and Guarantees (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Loss Contingencies [Line Items]
Aggregate rental expense	$ 11.9	$ 14.1	$ 6.7
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Minimum rental commitments - in fiscal year 2017	10.5
Minimum rental commitments - due in fiscal year 2018	7.5
Minimum rental commitments - due in fiscal year 2019	7.3
Minimum rental commitments - due in fiscal year 2020	6.2
Minimum rental commitments - due in fiscal year 2021	6.0
Minimum rental commitments - due later	53.4
Minimum rental commitments - total	90.9
Sublease rentals	2.1	2.1	0.2
Minimum future sublease rentals to be received - fiscal year 2017	2.1
Minimum future sublease rentals to be received - fiscal year 2018	2.1
Minimum future sublease rentals to be received - fiscal year 2019	2.1
Minimum future sublease rentals to be received - fiscal year 2020	0.5
Outstanding mortgage loans incurred in connection with various real estate ventures with general partners	1.4
Laclede Gas
Loss Contingencies [Line Items]
Aggregate rental expense	4.3	7.6	6.3
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Minimum rental commitments - in fiscal year 2017	2.5
Minimum rental commitments - due in fiscal year 2018	0.9
Minimum rental commitments - due in fiscal year 2019	0.9
Minimum rental commitments - due in fiscal year 2020	0.3
Minimum rental commitments - due in fiscal year 2021	0.1
Minimum rental commitments - due later	0.0
Minimum rental commitments - total	4.7
Alagasco
Loss Contingencies [Line Items]
Aggregate rental expense	3.7	4.0	2.0
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Minimum rental commitments - in fiscal year 2017	3.9
Minimum rental commitments - due in fiscal year 2018	2.5
Minimum rental commitments - due in fiscal year 2019	2.5
Minimum rental commitments - due in fiscal year 2020	2.1
Minimum rental commitments - due in fiscal year 2021	2.1
Minimum rental commitments - due later	4.9
Minimum rental commitments - total	18.0
Sublease rentals	2.1	$ 2.1	$ 0.2
Minimum future sublease rentals to be received - fiscal year 2017	2.1
Minimum future sublease rentals to be received - fiscal year 2018	2.1
Minimum future sublease rentals to be received - fiscal year 2019	2.1
Minimum future sublease rentals to be received - fiscal year 2020	$ 0.5

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COMMITMENTS AND CONTINGENCIES - Contingencies (Details)		12 Months Ended	54 Months Ended
	Dec. 17, 2013 fatality	Sep. 30, 2016 plaintiff site lawsuit	Sep. 30, 2016 site lawsuit	Sep. 30, 2014 site
Site Contingency [Line Items]
Number of incident fatalities | fatality	1
Laclede Gas
Site Contingency [Line Items]
Number of former manufactured gas plant (MGP) sites in Missouri		3	3
Number of former manufactured gas plant (MGP) sites in Shrewsbury, Missouri		1	1
Number of former manufactured gas plant (MGP) sites in the City of St. Louis		2	2
Laclede Gas | Previous Ownership
Site Contingency [Line Items]
Number of former manufactured gas plant (MGP)				19
Missouri Gas Energy (MGE) | Previous Ownership
Site Contingency [Line Items]
Number of former manufactured gas plant (MGP)		7	7
Alagasco
Site Contingency [Line Items]
Number of former manufactured gas plant (MGP)		9	9
Number of former manufactured gas distribution		5	5
Alagasco | Current Ownership
Site Contingency [Line Items]
Number of former manufactured gas plant (MGP)		4	4
Number of former manufactured gas distribution		1	1
Mobile Gas
Site Contingency [Line Items]
Number of lawsuits | lawsuit			14
Number of lawsuits settled | lawsuit			11
Number of lawsuits pending | lawsuit		3	3
Mobile Gas | Pending Litigation
Site Contingency [Line Items]
Number of plaintiffs | plaintiff		270
Mobile Gas | Previous Ownership
Site Contingency [Line Items]
Number of former manufactured gas plant (MGP)				1

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INTERIM FINANCIAL INFORMATION (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								9 Months Ended	12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Quarterly Financial Information [Line Items]
Total Operating Revenues	$ 279.3	$ 249.3	$ 609.3	$ 399.4	$ 204.2	$ 275.2	$ 877.4	$ 619.6		$ 1,537.3	$ 1,976.4	$ 1,627.2
Operating Income (Loss)	(7.7)	35.3	167.7	87.0	(8.5)	36.0	157.7	87.3		282.3	272.5	166.4
Net Income (Loss)	$ (14.2)	$ 10.7	$ 100.8	$ 46.9	$ (18.7)	$ 14.1	$ 94.4	$ 47.1		$ 144.2	$ 136.9	$ 84.6
Basic Earnings Per Share of Common Stock (in dollars per share)	$ (0.31)	$ 0.24	$ 2.32	$ 1.08	$ (0.43)	$ 0.32	$ 2.18	$ 1.09		$ 3.26	$ 3.16	$ 2.36
Diluted Earnings Per Share of Common Stock (in dollars per share)	$ (0.31)	$ 0.24	$ 2.31	$ 1.08	$ (0.43)	$ 0.32	$ 2.18	$ 1.09		$ 3.24	$ 3.16	$ 2.35
Laclede Gas
Quarterly Financial Information [Line Items]
Total Operating Revenues	$ 144.3	$ 179.3	$ 446.7	$ 317.2	$ 151.0	$ 187.5	$ 615.7	$ 462.4		$ 1,087.5	$ 1,416.6	$ 1,448.2
Operating Income (Loss)	5.4	29.4	87.0	65.1	5.5	34.5	80.6	64.8		186.9	185.4	166.4
Net Income (Loss)	(1.7)	13.9	54.3	39.4	(3.6)	20.0	49.9	39.0		105.9	105.3	$ 90.1
Alagasco
Quarterly Financial Information [Line Items]
Total Operating Revenues	46.2	74.0	166.0	82.3	52.2	73.7	233.3	120.0	$ 417.2	368.5	479.2
Operating Income (Loss)	(17.1)	9.3	80.4	18.9	(12.5)	3.9	77.4	20.4	62.2	91.5	89.2
Net Income (Loss)	$ (8.8)	$ 4.0	$ 48.1	$ 9.9	$ (9.6)	$ 0.7	$ 46.3	$ 10.6	$ 33.0	$ 53.2	$ 48.0