Piedmont Natural Gas Company, Inc. |
(Exact name of registrant as specified in its charter) |
North Carolina | 56-0556998 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
4720 Piedmont Row Drive, Charlotte, North Carolina | 28210 | |
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code | (704) 364-3120 |
Large accelerated filer ¨ | Accelerated filer o | |
Non-accelerated filer ý (Do not check if a smaller reporting company) | Smaller reporting company o |
Description | Shares | |
Common Stock, no par value | All of the registrant's common stock is directly owned by Duke Energy Corporation as of October 3, 2016. |
Piedmont Natural Gas Company, Inc. | ||
2016 FORM 10-K ANNUAL REPORT | ||
TABLE OF CONTENTS | ||
Page | ||
Cautionary Statement Regarding Forward-Looking Information | ||
Part I. | ||
Item 1. | Business | |
Item 1A. | Risk Factors | |
Item 1B. | Unresolved Staff Comments | |
Item 2. | Properties | |
Item 3. | Legal Proceedings | |
Item 4. | Mine Safety Disclosures | |
Part II. | ||
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | |
Item 6. | Selected Financial Data | |
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Item 7A. | Quantitative and Qualitative Disclosures about Market Risk | |
Item 8. | Financial Statements and Supplementary Data | |
Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | |
Item 9A. | Controls and Procedures | |
Item 9B. | Other Information | |
Part III. | ||
Item 10. | Directors, Executive Officers and Corporate Governance | |
Item 11. | Executive Compensation | |
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | |
Item 13. | Certain Relationships and Related Transactions, and Director Independence | |
Item 14. | Principal Accounting Fees and Services | |
Part IV. | ||
Item 15. | Exhibits, Financial Statement Schedules | |
Signatures |
• | Economic conditions in our markets. |
• | Wholesale price of natural gas. |
• | Availability of adequate interstate pipeline transportation capacity and natural gas supply. |
• | Regulatory actions at the state level that impact our ability to earn a reasonable rate of return and fully recover our operating costs on a timely basis. |
• | Competition from other companies that supply energy. |
• | Changes in the regional economies, politics, regulations and weather patterns of the three states in which our operations are concentrated. |
• | Costs of complying or effect of noncompliance with state and federal laws and regulations that are applicable to us. |
• | Effect of climate change, carbon neutral or energy efficiency legislation or regulations on costs and market opportunities. |
• | Weather conditions. |
• | Operational interruptions to our gas distribution and transmission activities. |
• | Inability to complete necessary or desirable pipeline expansion or infrastructure development projects. |
• | Elevated levels of capital expenditures. |
• | Changes to our credit ratings. |
• | Availability and cost of external capital. |
• | Federal and state fiscal, tax and monetary policies. |
• | Ability to generate sufficient cash flows to meet all our cash needs. |
• | Ability to satisfy all of our outstanding debt obligations. |
• | Ability of counterparties to meet their obligations to us. |
• | Costs of providing pension benefits. |
• | Earnings from the joint venture businesses in which we invest. |
• | Ability to attract and retain professional and technical employees. |
• | Cybersecurity breaches or failure of technology systems. |
• | Ability to obtain and maintain sufficient insurance. |
• | Changes in our parent's strategy, relationship with us or operating performance. |
(in millions) | Rate Base | Return on Equity | Equity Component of Capital Structure | Effective Date | ||||||
2013 North Carolina Rate Proceeding | $ | 1,822.4 | 10.0% | 50.7% | January 2014 | |||||
2015 South Carolina Rate Stabilization Adjustment Filing (1) | 224.2 | 10.2% | 55.0% | November 2015 | ||||||
2011 Tennessee Rate Proceeding | 348.9 | 10.2% | 52.7% | March 2012 | ||||||
(1) Under the rate stabilization adjustment (RSA) mechanism, we reset our rates in South Carolina based on updated costs and revenues on an annual basis. |
Years Ended October 31, | ||||||||||||
(in millions) | 2016 | 2015 | Variance | |||||||||
Regulated natural gas operating revenues | $ | 1,131.6 | $ | 1,371.7 | $ | (240.1 | ) | |||||
Related party revenue from Duke Energy | 7.0 | 7.0 | ||||||||||
Cost of natural gas | 390.5 | 644.4 | (253.9 | ) | ||||||||
Regulated margin | 748.1 | 727.3 | 20.8 | |||||||||
Nonregulated and other operating revenues | 10.1 | 11.4 | (1.3 | ) | ||||||||
Operations, maintenance and other | 352.9 | 304.8 | 48.1 | |||||||||
Depreciation and amortization | 137.3 | 128.7 | 8.6 | |||||||||
Property and other taxes | 42.6 | 42.4 | 0.2 | |||||||||
Operating Income | 225.4 | 262.8 | (37.4 | ) | ||||||||
Other Income (Expense), net | 160.6 | 33.0 | 127.6 | |||||||||
Interest Expense | 68.6 | 68.6 | — | |||||||||
Income Before Income Taxes | 317.4 | 227.2 | 90.2 | |||||||||
Income Tax Expense | 124.2 | 90.2 | 34.0 | |||||||||
Net Income | $ | 193.2 | $ | 137.0 | $ | 56.2 |
Regulated Margin by Customer Class | ||||||||||||||
(in millions) | 2016 | 2015 | ||||||||||||
Sales and Transportation: | ||||||||||||||
Residential | $ | 397.0 | 53 | % | $ | 376.6 | 52 | % | ||||||
Commercial | 189.3 | 25 | % | 181.6 | 25 | % | ||||||||
Industrial | 51.4 | 7 | % | 49.9 | 7 | % | ||||||||
Power Generation | 77.1 | 10 | % | 77.2 | 10 | % | ||||||||
For Resale | 11.7 | 2 | % | 12.5 | 2 | % | ||||||||
Total | 726.5 | 97 | % | 697.8 | 96 | % | ||||||||
Secondary Market Sales | 17.7 | 2 | % | 21.1 | 3 | % | ||||||||
Miscellaneous | 3.9 | 1 | % | 8.4 | 1 | % | ||||||||
Total | $ | 748.1 | 100 | % | $ | 727.3 | 100 | % |
Gas Deliveries, Customers, Weather Statistics and Number of Employees | |||||||||
Percent | |||||||||
2016 | 2015 | Change | |||||||
Deliveries in Dekatherms (in millions): | |||||||||
Residential | 48.1 | 61.0 | (21.1 | )% | |||||
Commercial | 38.3 | 44.6 | (14.1 | )% | |||||
Industrial | 95.9 | 96.4 | (0.5 | )% | |||||
Power Generation | 296.5 | 262.2 | 13.1 | % | |||||
For Resale | 6.3 | 7.3 | (13.7 | )% | |||||
Throughput | 485.1 | 471.5 | 2.9 | % | |||||
Secondary Market Volumes | 61.3 | 30.8 | 99.0 | % | |||||
Customers Billed (at period end) | 1,026,466 | 1,011,959 | 1.4 | % | |||||
Gross Residential, Commercial and Industrial Customer Additions | 17,328 | 17,017 | 1.8 | % | |||||
Degree Days | |||||||||
Actual | 2,583 | 3,449 | (25.1 | )% | |||||
Normal | 3,265 | 3,257 | 0.2 | % | |||||
Percent (warmer) colder than normal | (20.9 | )% | 5.9 | % | n/a | ||||
Number of Employees (at period end) | 1,971 | 1,943 | 1.4 | % |
Increase | ||||
(in millions) | (Decrease) | |||
Residential and commercial customers | $ | (271.6 | ) | |
Industrial customers | (6.5 | ) | ||
Power generation customers | (0.5 | ) | ||
Secondary market | (62.0 | ) | ||
Margin decoupling mechanism | 58.5 | |||
WNA mechanisms | 22.3 | |||
IMR mechanisms | 27.2 | |||
Other | (0.5 | ) | ||
Total | $ | (233.1 | ) |
• | Residential and commercial customers – the decrease is due to lower consumption from warmer weather and lower wholesale gas costs passed through to customers, slightly offset by customer growth. |
• | Industrial customers – the decrease is primarily due to lower wholesale gas costs and lower volumes from warmer weather. |
• | Secondary market – the decrease is due to lower margin sales prices, partially offset by increased volumes. Secondary market transactions consist of off-system sales and capacity release and asset management arrangements that are a part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and us. Effective October 3, 2016 as a result of the Acquisition, secondary market margins generated through off-system sales and capacity release activity to Duke Energy are 100% credited to customers. |
• | Margin decoupling mechanism – the increase is primarily related to warmer weather in North Carolina as compared to the prior period. The margin decoupling mechanism in North Carolina adjusts for variations in residential and commercial use per customer, including those due to weather and conservation. |
• | Weather normalization adjustment (WNA) mechanisms – the increase is primarily related to warmer weather in South Carolina and Tennessee as compared to the prior period. The WNA mechanisms partially offset the impact of colder- or warmer-than-normal weather on bills rendered. |
• | IMR mechanisms – the increase is due to the integrity management rider (IMR) rate adjustments in Tennessee, effective in January 2015 and 2016, and North Carolina, effective in February 2015, December 2015 and June 2016. |
Increase | ||||
(in millions) | (Decrease) | |||
Commodity gas costs passed through to sales customers | $ | (161.4 | ) | |
Commodity gas costs in secondary market transactions | (58.6 | ) | ||
Pipeline demand charges | 0.2 | |||
Regulatory approved gas cost mechanisms | (34.1 | ) | ||
Total | $ | (253.9 | ) |
• | Commodity gas costs passed through to sales customers – the decrease is primarily due to lower wholesale gas costs passed through to sales customers and lower consumption due to warmer weather, slightly offset by customer growth. |
• | Commodity gas costs in secondary market transactions – the decrease is primarily due to lower average wholesale gas costs, partially offset by increased volumes. |
• | Regulatory approved gas cost mechanisms – the decrease is primarily due to a decrease in commodity cost and demand true-ups, partially offset by other regulatory mechanisms. |
Regulatory Mechanism | North Carolina | South Carolina | Tennessee | |||
WNA mechanism* | X | X | ||||
Margin decoupling mechanism * | X | |||||
Natural gas rate stabilization mechanism | X | |||||
Secondary market programs ** | X | X | X | |||
Incentive plan for gas supply ** | X | |||||
IMR mechanism | X | X | ||||
Negotiated margin loss treatment | X | X | ||||
Uncollectible gas cost recovery | X | X | X | |||
* Residential and commercial customers only. | ||||||
** In all jurisdictions, we retain 25% of secondary market margins generated through off-system sales and capacity release activity, with 75% credited to customers. Effective October 3, 2016, secondary market margins generated through off-system sales and capacity release activity to Duke Energy are 100% credited to customers. Our share of net gains or losses in Tennessee is subject to an annual cap of $1.6 million. |
Increase | ||||
(in millions) | (Decrease) | |||
Residential and commercial customers | $ | 28.2 | ||
Industrial customers | 0.6 | |||
Power generation customers | (0.1 | ) | ||
Secondary market activity | (3.4 | ) | ||
Net gas cost adjustments | (4.5 | ) | ||
Total | $ | 20.8 |
• | Residential and commercial customers – the increase is primarily due to IMR rate adjustments in Tennessee and North Carolina, both effective as stated above, and customer growth in all three states. |
• | Secondary market activity – the decrease is primarily due to lower margin sales, partially offset by increased volumes. |
• | Net gas cost adjustments – the decrease is due to North Carolina customer bill credits applied in October 2016 in compliance with the North Carolina Utilities Commission (NCUC) order approving the Acquisition. |
Increase | ||||
(in millions) | (Decrease) | |||
Acquisition and integration-related expenses | $ | 53.0 | ||
Contract labor | 1.9 | |||
Employee benefits | (3.1 | ) | ||
Payroll | (1.2 | ) | ||
Other | (2.5 | ) | ||
Total | $ | 48.1 |
• | Acquisition and integration-related expenses – the increase is due to increased costs paid to outside parties, primarily financial and legal advisory costs, severance costs, retention and acceleration of incentive plans, and an accrual for our commitment of charitable contributions and community support. See Note 2 "Acquisition by Duke Energy Corporation" to the Consolidated Financial Statements in this Form 10-K for further information on these expenses. |
• | Contract labor – the increase is primarily due to the utilization of third parties for operations projects, legal and training design, partially offset by capitalization of contract labor related to accounting software implementation. |
• | Employee benefits – the decrease is primarily due to lower defined benefit plan accruals related to changes in actuarial assumptions. |
• | Payroll – the decrease is primarily related to incremental expense from the accelerated vesting and payment of incentive awards under provisions in the Merger Agreement being reflected in "Acquisition and integration-related expenses" above, partially offset by merit increases. |
Increase | ||||
(in millions) | (Decrease) | |||
Equity in earnings of unconsolidated affiliates | ||||
Constitution Pipeline Company LLC (Constitution) | $ | (7.5 | ) | |
Atlantic Coast Pipeline, LLC (ACP) | 2.3 | |||
Other | (0.7 | ) | ||
Total | (5.9 | ) | ||
Gain on sale of unconsolidated affiliates | 132.8 | |||
Other expense, net | 0.7 | |||
Total | $ | 127.6 |
• | Equity in earnings of unconsolidated affiliates from Constitution – the decrease is primarily due to the discontinued capitalization of ongoing expenditures. |
• | Equity in earnings of unconsolidated affiliates from ACP – the increase is primarily due to higher capitalized interest costs. |
• | Gain on sale of unconsolidated affiliates – the increase was due to the gain on the sale of our 15% ownership interest in SouthStar Energy Services, LLC (SouthStar). See Note 11 "Investments in Unconsolidated Affiliates" to the Consolidated Financial Statements in this Form 10-K for further information on this transaction. |
Increase | ||||
(in millions) | (Decrease) | |||
Regulatory interest expense, net | $ | (7.3 | ) | |
Borrowed AFUDC | (1.2 | ) | ||
Interest expense on long-term debt | 7.2 | |||
Interest expense on short-term debt | 1.3 | |||
Total | $ | — |
• | Regulatory interest expense, net – the change is primarily due to interest income on net amounts due from customers compared with interest expense in the prior period on net amounts due to customers. |
• | Borrowed allowance for funds used during construction (AFUDC) – the decrease is due to increased capitalized interest from higher capital expenditures. |
• | Interest expense on long-term debt – the increase is primarily due to higher amounts of outstanding debt in the current period. |
• | Interest expense on short-term debt – the increase is primarily due to higher average interest rates of 34 basis points over the prior period on higher average daily borrowings. |
(in millions) | North Carolina | Tennessee | |||||
Incremental annual margin revenue - 2014 IMR filing | $ | 1.0 | (1) | $ | 13.1 | ||
Incremental annual margin revenue - 2015 IMR filing | 24.4 | (1) | 6.5 | ||||
Incremental annual margin revenue - 2016 IMR filing | 22.9 | (2) | 1.7 | ||||
Total cumulative incremental annual margin revenue in 2016 (3) | $ | 48.3 | (1) | $ | 21.3 | ||
Amounts recorded as revenues during fiscal year 2016 | $ | 41.5 | $ | 20.9 | |||
Amounts recorded as revenues during fiscal year 2015 | 17.1 | 18.2 | |||||
(1) Amounts reflect incremental annual IMR margin revenue, as adjusted per audit by the NCUC Public Staff under the approved IMR settlement agreement and procedural schedule, which may differ from the amounts reflected in the filed and approved rate adjustments. See Note 3 "Regulatory Matters" to the Consolidated Financial Statements in this Form 10-K for further information on the IMR settlement agreement. | |||||||
(2) Amount reflects additional annual margin revenues of $15.5 million effective December 1, 2015 and $7.4 million effective June 1, 2016 as approved by the NCUC. | |||||||
(3) IMR recovery period in both jurisdictions does not align with our fiscal year. See Note 3 "Regulatory Matters" to the Consolidated Financial Statements in this Form 10-K for further information on the recovery periods. |
Fair Value as | ||||||||||||||||||||||||||||||||
Expected Maturity Date | of October 31, | |||||||||||||||||||||||||||||||
(in millions) | 2017 | 2018 | 2019 | 2020 | 2021 | Thereafter | Total | 2016 | ||||||||||||||||||||||||
Fixed Rate Long-term Debt | $ | 35.0 | $ | — | $ | — | $ | — | $ | 160.0 | $ | 1,640.0 | $ | 1,835.0 | $ | 2,061.2 | ||||||||||||||||
Average Interest Rate | 8.51 | % | — | % | — | % | — | % | 4.24 | % | 4.60 | % | 4.64 | % |
Years Ended October 31, | ||||||||||||
(in millions) | 2016 | 2015 | 2014 | |||||||||
Operating Revenues | ||||||||||||
Regulated natural gas (1) | $ | 1,131.6 | $ | 1,371.7 | $ | 1,470.0 | ||||||
Nonregulated and other | 10.1 | 11.4 | 9.5 | |||||||||
Related party revenue from Duke Energy (2) | 7.0 | |||||||||||
Total operating revenues | 1,148.7 | 1,383.1 | 1,479.5 | |||||||||
Operating Expenses | ||||||||||||
Cost of natural gas (1) | 390.5 | 644.4 | 779.8 | |||||||||
Operations, maintenance and other | 352.9 | 304.8 | 279.9 | |||||||||
Depreciation and amortization | 137.3 | 128.7 | 119.0 | |||||||||
Property and other taxes | 42.6 | 42.4 | 37.7 | |||||||||
Total operating expenses | 923.3 | 1,120.3 | 1,216.4 | |||||||||
Operating Income | 225.4 | 262.8 | 263.1 | |||||||||
Other Income and Expense | ||||||||||||
Equity in earnings of unconsolidated affiliates | 28.6 | 34.5 | 32.8 | |||||||||
Gain on sale of unconsolidated affiliates | 132.8 | — | — | |||||||||
Other expense, net | 0.8 | 1.5 | 2.6 | |||||||||
Total other income and expense | 160.6 | 33.0 | 30.2 | |||||||||
Interest Expense | 68.6 | 68.6 | 54.7 | |||||||||
Income Before Income Taxes | 317.4 | 227.2 | 238.6 | |||||||||
Income Tax Expense | 124.2 | 90.2 | 94.8 | |||||||||
Net Income | 193.2 | 137.0 | 143.8 | |||||||||
Other Comprehensive Income (Loss), net of tax | ||||||||||||
Unrealized (loss) gain from hedging activities, net of tax of ($2.5), ($1.0) and $0.2 for the years ended October 31, 2016, 2015 and 2014, respectively | (2.8 | ) | (1.6 | ) | 0.3 | |||||||
Reclassification adjustment of realized loss (gain) from hedging activities of equity method investments included in net income, net of tax of $2.0, $0.7 and ($0.2) for the years ended October 31, 2016, 2015 and 2014, respectively | 3.4 | 1.0 | (0.3 | ) | ||||||||
Other Comprehensive Income (Loss), net of tax | 0.6 | (0.6 | ) | — | ||||||||
Comprehensive Income | $ | 193.8 | $ | 136.4 | $ | 143.8 | ||||||
(1) See Note 11 for amounts attributable to investments in unconsolidated affiliates. | ||||||||||||
(2) See Note 14 for details on related party transactions with Duke Energy. | ||||||||||||
See Notes to Consolidated Financial Statements. |
October 31, | ||||||||
(in millions) | 2016 | 2015 | ||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 16.6 | $ | 13.7 | ||||
Receivables (less allowance for doubtful accounts of $1.9 in 2016 and $1.6 in 2015) | 75.2 | 86.9 | ||||||
Receivables from affiliated companies (1) (2) | 7.0 | 0.2 | ||||||
Inventory | 55.6 | 69.5 | ||||||
Regulatory assets | 113.7 | 19.1 | ||||||
Prepaids | 27.2 | 28.9 | ||||||
Other | 12.0 | 12.8 | ||||||
Total current assets | 307.3 | 231.1 | ||||||
Investments and Other Assets | ||||||||
Investments in equity method unconsolidated affiliates | 199.2 | 207.0 | ||||||
Goodwill | 48.9 | 48.9 | ||||||
Other | 10.9 | 53.1 | ||||||
Total investments and other assets | 259.0 | 309.0 | ||||||
Property, Plant and Equipment | ||||||||
Cost | 6,079.1 | 5,601.3 | ||||||
Accumulated depreciation and amortization | (1,329.5 | ) | (1,252.9 | ) | ||||
Net property, plant and equipment | 4,749.6 | 4,348.4 | ||||||
Regulatory Assets and Deferred Debits | ||||||||
Regulatory assets | 373.3 | 196.7 | ||||||
Other | 1.8 | 1.1 | ||||||
Total regulatory assets and deferred debits | 375.1 | 197.8 | ||||||
Total Assets | $ | 5,691.0 | $ | 5,086.3 | ||||
LIABILITIES AND EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts payable | $ | 130.5 | $ | 120.3 | ||||
Accounts payable to affiliated companies (1) (2) | 8.7 | 2.5 | ||||||
Notes payable and commercial paper | 145.0 | 340.0 | ||||||
Taxes accrued | 68.4 | 30.3 | ||||||
Interest accrued | 29.3 | 29.5 | ||||||
Current maturities of long-term debt | 35.0 | 40.0 | ||||||
Regulatory liabilities | — | 21.5 | ||||||
Gas supply derivative liabilities, at fair value | 41.5 | — | ||||||
Other | 61.7 | 59.3 | ||||||
Total current liabilities | 520.1 | 643.4 | ||||||
Long-Term Debt | 1,786.0 | 1,523.7 | ||||||
Deferred Credits and Other Liabilities | ||||||||
Deferred income taxes | 904.1 | 829.2 | ||||||
Investment tax credits | 0.9 | 1.0 | ||||||
Accrued pension and other post-retirement benefit costs | 23.4 | 15.1 | ||||||
Asset retirement obligations | 14.1 | 19.7 | ||||||
Regulatory liabilities | 617.0 | 590.3 | ||||||
Other | 180.5 | 37.6 | ||||||
Total deferred credits and other liabilities | 1,740.0 | 1,492.9 | ||||||
Commitments and Contingencies | ||||||||
Equity | ||||||||
Common stock, no par value: 100 shares authorized and outstanding in 2016 and 200.0 million authorized and 80.9 million outstanding in 2015 | 859.8 | 721.4 | ||||||
Retained earnings | 785.3 | 705.7 | ||||||
Accumulated other comprehensive loss | (0.2 | ) | (0.8 | ) | ||||
Total equity | 1,644.9 | 1,426.3 | ||||||
Total Liabilities and Equity | $ | 5,691.0 | $ | 5,086.3 | ||||
(1) See Note 11 for amounts attributable to investments in unconsolidated affiliates. | ||||||||
(2) See Note 14 for details on related party transactions with Duke Energy. | ||||||||
See Notes to Consolidated Financial Statements. |
Years Ended October 31, | ||||||||||||
(in millions) | 2016 | 2015 | 2014 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITES | ||||||||||||
Net income | $ | 193.2 | $ | 137.0 | $ | 143.8 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization | 148.3 | 140.2 | 129.3 | |||||||||
Provision for doubtful accounts | 4.9 | 5.1 | 7.0 | |||||||||
Impairment charges | — | — | 2.0 | |||||||||
Net gain on sale of property | — | — | (0.8 | ) | ||||||||
Net gain on sale of interests in unconsolidated affiliates, net of tax | (80.9 | ) | — | — | ||||||||
Deferred income taxes, net | 74.2 | 73.0 | 87.2 | |||||||||
Equity in earnings of unconsolidated affiliates | (28.6 | ) | (34.5 | ) | (32.8 | ) | ||||||
Distributions of earnings from unconsolidated affiliates | 25.8 | 24.9 | 24.8 | |||||||||
Accrued/deferred postretirement benefit costs | 12.4 | 2.2 | 5.9 | |||||||||
Contributions to benefit plans | (14.0 | ) | (12.7 | ) | (22.5 | ) | ||||||
Settlement of legal asset retirement obligations | (6.4 | ) | (5.6 | ) | (3.5 | ) | ||||||
(Increase) decrease in: | ||||||||||||
Receivables, net | 6.9 | (2.6 | ) | 9.7 | ||||||||
Receivables from affiliated companies | (7.0 | ) | ||||||||||
Inventory | 13.9 | 16.3 | (10.1 | ) | ||||||||
Regulatory assets | (291.6 | ) | (24.0 | ) | 21.2 | |||||||
Other current assets | 2.4 | 38.4 | (12.0 | ) | ||||||||
Increase (decrease) in: | ||||||||||||
Accounts payable | 6.2 | (5.1 | ) | (4.7 | ) | |||||||
Accounts payable to affiliated companies | 6.3 | |||||||||||
Taxes accrued | (13.7 | ) | 3.8 | 3.6 | ||||||||
Gas supply derivatives, at fair value | 187.9 | — | — | |||||||||
Other current liabilities | (13.5 | ) | (20.5 | ) | 51.1 | |||||||
Other assets | 58.2 | 7.4 | 20.7 | |||||||||
Other liabilities | 23.5 | 28.3 | 10.7 | |||||||||
Net cash provided by operating activities | 308.4 | 371.6 | 430.6 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
Capital expenditures | (521.8 | ) | (443.7 | ) | (460.5 | ) | ||||||
Allowance for borrowed funds used during construction | (12.3 | ) | (11.1 | ) | (16.4 | ) | ||||||
Investment expenditures | (47.4 | ) | (29.7 | ) | (37.6 | ) | ||||||
Distributions of capital from unconsolidated affiliates | 18.0 | 1.5 | 3.9 | |||||||||
Net proceeds from the sales of interests in unconsolidated affiliates and other assets | 174.5 | 0.7 | 1.9 | |||||||||
Other | 15.3 | 3.9 | 4.2 | |||||||||
Net cash used in investing activities | (373.7 | ) | (478.4 | ) | (504.5 | ) |
Years Ended October 31, | ||||||||||||
(in millions) | 2016 | 2015 | 2014 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
Proceeds from the: | ||||||||||||
Issuance of long-term debt | $ | 299.6 | $ | 149.9 | $ | 249.6 | ||||||
Issuance of common stock related to employee benefit plans | 17.0 | 27.0 | 25.6 | |||||||||
Issuance of common stock, net of expense | 104.6 | 53.7 | 47.3 | |||||||||
Payments for the: | ||||||||||||
Redemptions of long-term debt | (40.0 | ) | — | (100.0 | ) | |||||||
Expenses related to issuance of debt | (4.3 | ) | (1.3 | ) | (2.9 | ) | ||||||
Notes payable and commercial paper | (195.0 | ) | (15.0 | ) | (45.0 | ) | ||||||
Dividends paid | (113.7 | ) | (103.4 | ) | (99.2 | ) | ||||||
Net cash provided by financing activities | 68.2 | 110.9 | 75.4 | |||||||||
Net increase in cash and cash equivalents | 2.9 | 4.1 | 1.5 | |||||||||
Cash and cash equivalents at beginning of period | 13.7 | 9.6 | 8.1 | |||||||||
Cash and cash equivalents at end of period | $ | 16.6 | $ | 13.7 | $ | 9.6 | ||||||
Supplemental Disclosures: | ||||||||||||
Cash paid for interest, net of amount capitalized | $ | 81.4 | $ | 71.5 | $ | 64.3 | ||||||
Cash (received from) paid for income taxes | (24.5 | ) | 3.2 | 10.8 | ||||||||
Significant non-cash transactions: | ||||||||||||
Accrued capital expenditures | $ | 62.8 | $ | 58.9 | $ | 38.9 | ||||||
See Notes to Consolidated Financial Statements. |
(in millions) | Common Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total Equity | ||||||||||||
Balance at October 31, 2013 | $ | 561.6 | $ | 627.2 | $ | (0.2 | ) | $ | 1,188.6 | |||||||
Net income | 143.8 | 143.8 | ||||||||||||||
Other comprehensive income, net of tax | — | — | ||||||||||||||
Common stock issuances, including dividend reinvestment and employee benefits | 75.2 | 75.2 | ||||||||||||||
Expenses from Issuance of Common Stock | — | — | ||||||||||||||
Tax Benefit from Dividends Paid on ESOP Shares | 0.2 | 0.2 | ||||||||||||||
Common stock dividends | (99.2 | ) | (99.2 | ) | ||||||||||||
Balance at October 31, 2014 | 636.8 | 672.0 | (0.2 | ) | 1,308.6 | |||||||||||
Net income | 137.0 | 137.0 | ||||||||||||||
Other comprehensive loss, net of tax | (0.6 | ) | (0.6 | ) | ||||||||||||
Common stock issuances, including dividend reinvestment and employee benefits | 85.0 | 85.0 | ||||||||||||||
Expenses from Issuance of Common Stock | (0.4 | ) | (0.4 | ) | ||||||||||||
Tax Benefit from Dividends Paid on ESOP Shares | 0.1 | 0.1 | ||||||||||||||
Common stock dividends | (103.4 | ) | (103.4 | ) | ||||||||||||
Balance at October 31, 2015 | 721.4 | 705.7 | (0.8 | ) | 1,426.3 | |||||||||||
Net income | 193.2 | 193.2 | ||||||||||||||
Other comprehensive income, net of tax | 0.6 | 0.6 | ||||||||||||||
Common stock issuances, including dividend reinvestment and employee benefits | 138.5 | 138.5 | ||||||||||||||
Expenses from Issuance of Common Stock | (0.1 | ) | (0.1 | ) | ||||||||||||
Tax Benefit from Dividends Paid on ESOP Shares | 0.1 | 0.1 | ||||||||||||||
Common stock dividends | (113.7 | ) | (113.7 | ) | ||||||||||||
Balance at October 31, 2016 | $ | 859.8 | $ | 785.3 | $ | (0.2 | ) | $ | 1,644.9 | |||||||
See Notes to Consolidated Financial Statements. |
(in millions) | 2016 | 2015 | ||||||
Hedging activities of equity method investments | $ | (0.2 | ) | $ | (0.8 | ) |
(in millions) | 2016 | 2015 | ||||||
Intangible plant | $ | 3.4 | $ | 3.4 | ||||
Other storage plant | 189.1 | 181.0 | ||||||
Transmission plant | 2,315.8 | 2,024.3 | ||||||
Distribution plant | 2,864.7 | 2,766.9 | ||||||
General plant | 469.7 | 452.3 | ||||||
Asset retirement cost | — | 4.1 | ||||||
Contributions in aid of construction | (5.6 | ) | (5.4 | ) | ||||
Total utility plant in service | 5,837.1 | 5,426.6 | ||||||
Construction work in progress | 233.0 | 170.3 | ||||||
Plant held for future use | 7.7 | 3.1 | ||||||
Other property | 1.3 | 1.3 | ||||||
Total cost | 6,079.1 | 5,601.3 | ||||||
Utility plant in service accumulated depreciation | (1,328.6 | ) | (1,252.0 | ) | ||||
Other property accumulated depreciation and amortization | (0.9 | ) | (0.9 | ) | ||||
Total accumulated depreciation and amortization | (1,329.5 | ) | (1,252.9 | ) | ||||
Total net property, plant and equipment | $ | 4,749.6 | $ | 4,348.4 |
(in millions) | 2016 | 2015 | 2014 | |||||||||
AFUDC | $ | 12.3 | $ | 11.1 | $ | 16.4 |
(in millions) | 2016 | 2015 | ||||||
Gas receivables | $ | 43.1 | $ | 57.6 | ||||
Unbilled revenues | 13.4 | 17.4 | ||||||
Other miscellaneous receivables | 20.6 | 13.5 | ||||||
Allowance for doubtful accounts | (1.9 | ) | (1.6 | ) | ||||
Receivables and Allowance for Doubtful Accounts | $ | 75.2 | $ | 86.9 |
(in millions) | 2016 | 2015 | 2014 | |||||||||
Balance at beginning of year | $ | 1.6 | $ | 2.2 | $ | 1.6 | ||||||
Additions charged to uncollectibles expense | 4.9 | 5.1 | 7.0 | |||||||||
Accounts written off, net of recoveries | (4.6 | ) | (5.7 | ) | (6.4 | ) | ||||||
Balance at end of year | $ | 1.9 | $ | 1.6 | $ | 2.2 |
2016 | 2015 | |||||||||||||||
(in millions) | Cost | Fair Value | Cost | Fair Value | ||||||||||||
Money markets | $ | 0.5 | $ | 0.5 | $ | 0.5 | $ | 0.5 | ||||||||
Mutual funds | 3.2 | 3.7 | 3.8 | 4.4 | ||||||||||||
Total trading securities | $ | 3.7 | $ | 4.2 | $ | 4.3 | $ | 4.9 |
(in millions) | 2016 | 2015 | ||||||
Regulatory non-legal AROs | $ | 538.0 | $ | 521.5 | ||||
Conditional AROs | 14.1 | 19.7 | ||||||
Total cost of removal obligations | $ | 552.1 | $ | 541.2 |
(in millions) | 2016 | 2015 | ||||||
Beginning of period | $ | 19.7 | $ | 14.7 | ||||
Liabilities incurred during the period | 5.5 | 4.7 | ||||||
Liabilities settled during the period | (6.5 | ) | (5.6 | ) | ||||
Accretion | 1.1 | 0.9 | ||||||
Adjustment to estimated cash flows | (5.7 | ) | 5.0 | |||||
End of period | $ | 14.1 | $ | 19.7 |
Guidance | Description | Effective date | Effect on the financial statements or other significant matters |
ASU 2014-09, May 2014, Revenue from Contracts with Customers (Topic 606), including subsequent ASUs clarifying the guidance | Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect consideration expected to be received in exchange for those goods or services. In doing so, more judgment and estimates may be needed than under current guidance. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from any entity's contracts with customers. An entity may choose to adopt the new standard on either a full retrospective basis (practical expedients available) or through a cumulative effect adjustment to retained earnings as of the start of first period of adoption. | Annual periods (and interim periods within those periods) beginning after December 15, 2017, with early adoption permitted for annual periods beginning after December 15, 2016. | As a Duke Energy registrant, we intend to adopt the revised accounting guidance effective for the interim and annual periods beginning January 1, 2018. We are currently evaluating the effect on our financial position and results of operations, as well as the transition approach we will take. The evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. In our evaluation, we are monitoring specific developments for our industry. |
Guidance | Description | Effective date | Effect on the financial statements or other significant matters |
ASU 2016-02, February 2016, Leases (Topic 842) | Under the new standard, entities will recognize right-of-use (ROU) assets and related liabilities on the balance sheet for leases with a term greater than one year. Amortization of the ROU asset will be accounted for using: (1) the finance lease approach, or (2) the operating lease approach. Under the finance lease approach, the ROU asset will be amortized on a straight-line basis with the amortization and the interest on the lease liability presented separately in the income statement. Under the operating lease approach, a single straight-line expense will be presented in the income statement. Qualitative and quantitative disclosures are required to enable a user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach, including the option to elect practical expedients, is required for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements at the date of initial application. | Annual periods (and interim periods within those periods) beginning after December 15, 2018, with early adoption permitted. | We are currently evaluating the effect on our financial position and results of operations. We do expect an increase in assets and liabilities from the recording of our operating leases. |
ASU 2016-15, August 2016, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments | The amendment is intended to provide specific guidance on eight cash flow classification issues to reduce the diversity in practice. The eight issues are: 1) debt prepayment or debt extinguishment costs, 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, 3) contingent consideration payments made after a business combination, 4) proceeds from the settlement of life insurance claims, 5) proceeds from the settlement of corporate owned life insurance policies, including bank-owned life insurance policies, 6) distributions received from equity method investees, 7) beneficial interests in securitization transactions and 8) separately identifiable cash flows and application of the predominance principle. | Annual periods (and interim periods within those periods) beginning after December 15, 2017. Early adoption is permitted in any interim or annual period if all amendments are adopted in that period with any adjustments reflected as of the beginning of the fiscal year that includes the interim period. | We are currently evaluating the effect on the presentation of our cash flows. |
• | Funding by the combined company of annual charitable contributions totaling at least $17.5 million in North Carolina during each of the four years after the Acquisition; |
• | Commitment by the combined company of $7.5 million for low-income household energy assistance and workforce development programs in North Carolina during the first year after the Acquisition; |
• | Exclusion of certain expenses related to the Acquisition, including severance costs, from customer bills; |
• | Withdrawal of our March 2016 petition requesting approval of deferred accounting treatment for certain distribution integrity management program expenses; and |
• | A one-time bill credit to our North Carolina customers collectively of $10.0 million. |
(in millions) | 2016 | 2015 | |||||
Financial and legal advisory costs | $ | 22.4 | $ | 8.6 | |||
Severance costs (1) | 18.7 | — | |||||
Charitable contributions and community support (2) | 8.8 | — | |||||
Acceleration of incentive plans (3) | 5.3 | — | |||||
Key employee retention payments | 3.5 | — | |||||
Other | 2.9 | — | |||||
Total | $ | 61.6 | $ | 8.6 | |||
(1) See Note 15 for further information on severance costs. | |||||||
(2) Charitable contributions and community support reflect: 1) the unconditional obligation to provide funding at a level comparable to historic practices over the next four years, and 2) the unconditional obligation to provide funding for low-income household energy assistance and workforce development programs in North Carolina over the next year. | |||||||
(3) See Note 9 for further information on the accelerated vesting, payment and taxation of certain share-based awards. |
(in millions) | 2016 | 2015 | ||||||
REGULATORY ASSETS | ||||||||
Current Regulatory Assets | ||||||||
Unamortized debt expense on reacquired debt | $ | 0.2 | $ | 0.2 | ||||
Amounts due from customers | 61.9 | 8.2 | ||||||
Environmental costs | 1.5 | 1.5 | ||||||
Deferred operations and maintenance expenses | 0.9 | 0.8 | ||||||
Deferred pipeline integrity expenses | 3.5 | 3.5 | ||||||
Deferred pension and other retirement benefit costs | 2.8 | 2.8 | ||||||
Robeson LNG development costs | 0.1 | 0.4 | ||||||
Derivatives - gas supply contracts held for utility operations | 41.5 | — | ||||||
Other | 1.3 | 1.7 | ||||||
Total current regulatory assets | 113.7 | 19.1 | ||||||
Noncurrent Regulatory Assets | ||||||||
Unamortized debt expense on reacquired debt | 4.4 | 4.7 | ||||||
Environmental costs | 3.6 | 5.1 | ||||||
Deferred operations and maintenance expenses | 3.1 | 4.0 | ||||||
Deferred pipeline integrity expenses | 32.4 | 29.8 | ||||||
Deferred pension and other retirement benefits costs | 16.8 | 17.9 | ||||||
Amounts not yet recognized as a component of pension and other retirement benefit costs | 151.6 | 114.8 | ||||||
Regulatory cost of removal asset | 14.1 | 19.1 | ||||||
Robeson LNG development costs | — | 0.1 | ||||||
Derivatives - gas supply contracts held for utility operations | 146.4 | — | ||||||
Other | 0.9 | 1.2 | ||||||
Total noncurrent regulatory assets | 373.3 | 196.7 | ||||||
Total Regulatory Assets | $ | 487.0 | $ | 215.8 |
REGULATORY LIABILITIES | ||||||||
Current Regulatory Liabilities | ||||||||
Amounts due to customers | $ | — | $ | 21.5 | ||||
Noncurrent Regulatory Liabilities | ||||||||
Regulatory cost of removal obligations | 538.0 | 521.5 | ||||||
Deferred income taxes | 78.9 | 68.7 | ||||||
Amounts not yet recognized as a component of pension and other retirement benefit costs | 0.1 | 0.1 | ||||||
Total noncurrent regulatory liabilities | 617.0 | 590.3 | ||||||
Total Regulatory Liabilities | $ | 617.0 | $ | 611.8 |
• | Semi-annual IMR rate adjustments each December 1 and June 1, starting December 1, 2015, based on eligible capital investments in integrity and safety projects closed to plant as of September 30 and March 31. |
• | Extension of the IMR tariff from October 31, 2017 to October 31, 2019. |
• | An established procedural process and time line for NCUC Public Staff’s annual review of our IMR filings. |
• | Fixed percentages to quantify various classes of system integrity expenditures to be recovered through the IMR with the remaining to be recovered through a future rate case: |
• | Transmission integrity: 85% IMR / 15% rate case. |
• | Distribution integrity: 90% IMR / 10% rate case. |
• | Right-of-way clearing for integrity projects: 15% IMR / 85% rate case. |
• | Work and asset management system: 68% IMR / 32% rate case. |
• | Tax-related adjustments. |
• | An immaterial reduction in IMR margin, which we recorded in the fourth fiscal quarter of 2015. |
(in millions) | 2016 | 2015 | 2014 | |||||||||
Allocated to customers as gas cost reductions | $ | 52.0 | $ | 60.1 | $ | 72.2 | ||||||
Margin allocated to us | 17.7 | 21.1 | 25.4 | |||||||||
Margin from secondary market activity | $ | 69.7 | $ | 81.2 | $ | 97.6 |
(in millions) | Shares | Amount | |||||
Balance, October 31, 2013 | 76.1 | $ | 561.6 | ||||
Issued to participants in the Employee Stock Purchase Plan (ESPP) | — | 1.1 | |||||
Issued to participants in the Dividend Reinvestment and Stock Purchase Plan (DRIP) | 0.7 | 23.5 | |||||
Issued to incentive compensation plan (ICP) | 0.1 | 3.3 | |||||
Issuance of common stock through forward sale agreements (FSAs), net of expenses | 1.6 | 47.3 | |||||
Balance, October 31, 2014 | 78.5 | 636.8 | |||||
Issued to ESPP | — | 1.2 | |||||
Issued to DRIP | 0.7 | 24.7 | |||||
Issued to ICP | 0.2 | 5.0 | |||||
Issuance of common stock through FSAs, net of expenses | 1.5 | 53.7 | |||||
Balance, October 31, 2015 | 80.9 | 721.4 | |||||
Issued to ESPP * | — | 1.0 | |||||
Issued to DRIP * | 0.3 | 14.5 | |||||
Issued to ICP | 0.3 | 18.3 | |||||
Issuance of common stock through FSAs, net of expenses | 1.8 | 104.6 | |||||
Outstanding shares of common stock converted into the right to receive cash | (83.3 | ) | |||||
Balance, October 31, 2016 | — | $ | 859.8 | ||||
* In anticipation of the Acquisition, we suspended new investments in our DRIP and ESPP, effective July 31, 2016. |
(in millions, except per share amounts) | |||||||||||
Equity Issuance Transaction | Number of Shares | Settled | Net Proceeds Before Issuance Costs (1) | Net Settlement Price Per Share (2) | |||||||
FSA - executed March 2015 | 0.6 | October 2015 | $ | 21.8 | $35.50 | ||||||
FSA - executed June 2015 | 0.8 | October 2015 | 28.2 | $35.49 | |||||||
FSA - executed September 2015 | 0.1 | October 2015 | 4.1 | $36.03 | |||||||
Total 2015 ATM program | 1.5 | $ | 54.1 | ||||||||
FSA - executed January 2016 | 0.4 | September 2016 | $ | 20.2 | $56.25 | ||||||
FSA - executed March 2016 | 0.6 | September 2016 | 36.2 | $58.35 | |||||||
FSA - executed June 2016 | 0.8 | September 2016 | 48.3 | $58.87 | |||||||
Total 2016 ATM program | 1.8 | $ | 104.7 | ||||||||
(1) Issuance costs incurred as follows: October 2015 shares $0.4 million and September 2016 shares $0.1 million. | |||||||||||
(2) Net of 1.5% commission plus other adjustments. |
Changes in Accumulated OCIL (1) | ||||||||
(in millions) | 2016 | 2015 | ||||||
Accumulated OCIL beginning balance, net of tax | $ | (0.8 | ) | $ | (0.2 | ) | ||
Hedging activities of equity method investments: | ||||||||
OCIL before reclassifications, net of tax | (2.8 | ) | (1.6 | ) | ||||
Amounts reclassified from accumulated OCIL, net of tax | 3.4 | 1.0 | ||||||
Total current period activity of hedging activities of equity method investments, net of tax | 0.6 | (0.6 | ) | |||||
Accumulated OCIL ending balance, net of tax | $ | (0.2 | ) | $ | (0.8 | ) | ||
(1) Amounts in parentheses indicate debits to accumulated OCIL. |
Reclassification Out of Accumulated OCIL (1) | ||||||||||
Years Ended | Affected Line Items on Statement of Operations and Comprehensive Income | |||||||||
October 31, | ||||||||||
(in millions) | 2016 | 2015 | ||||||||
Hedging activities of equity method investments | $ | 1.4 | $ | 1.7 | Equity in earnings of unconsolidated affiliates | |||||
Income tax expense | 2.0 | (0.7 | ) | Income tax expense | ||||||
Total reclassification for the period, net of tax | $ | 3.4 | $ | 1.0 | ||||||
(1) Amounts in parentheses indicate debits to accumulated OCIL. |
Long-Term Debt as of October 31, 2016 | ||||||||||||
(in millions) | Principal | Unamortized Debt Issuance Expenses and Discounts | Total | |||||||||
Senior Notes: | ||||||||||||
8.51%, due September 30, 2017 | $ | 35.0 | $ | — | $ | 35.0 | ||||||
4.24%, due June 6, 2021 | 160.0 | (0.6 | ) | 159.4 | ||||||||
3.47%, due July 16, 2027 | 100.0 | (0.6 | ) | 99.4 | ||||||||
3.57%, due July 16, 2027 | 200.0 | (1.2 | ) | 198.8 | ||||||||
4.10%, due September 18, 2034 | 250.0 | (2.5 | ) | 247.5 | ||||||||
4.65%, due August 1, 2043 | 300.0 | (2.9 | ) | 297.1 | ||||||||
3.60%, due September 1, 2025 | 150.0 | (1.4 | ) | 148.6 | ||||||||
3.64%, due November 1, 2046 | 300.0 | (3.4 | ) | 296.6 | ||||||||
Medium-Term Notes: | ||||||||||||
6.87%, due October 6, 2023 | 45.0 | (0.1 | ) | 44.9 | ||||||||
8.45%, due September 19, 2024 | 40.0 | (0.1 | ) | 39.9 | ||||||||
7.40%, due October 3, 2025 | 55.0 | (0.2 | ) | 54.8 | ||||||||
7.50%, due October 9, 2026 | 40.0 | (0.1 | ) | 39.9 | ||||||||
7.95%, due September 14, 2029 | 60.0 | (0.2 | ) | 59.8 | ||||||||
6.00%, due December 19, 2033 | 100.0 | (0.7 | ) | 99.3 | ||||||||
Total | 1,835.0 | (14.0 | ) | 1,821.0 | ||||||||
Less current maturities | 35.0 | — | 35.0 | |||||||||
Total | $ | 1,800.0 | $ | (14.0 | ) | $ | 1,786.0 |
Long-Term Debt as of October 31, 2015 | ||||||||||||
(in millions) | Principal | Unamortized Debt Issuance Expenses and Discounts | Total | |||||||||
Senior Notes: | ||||||||||||
2.92%, due June 6, 2016 | $ | 40.0 | $ | (0.1 | ) | $ | 39.9 | |||||
8.51%, due September 30, 2017 | 35.0 | — | 35.0 | |||||||||
4.24%, due June 6, 2021 | 160.0 | (0.8 | ) | 159.2 | ||||||||
3.47%, due July 16, 2027 | 100.0 | (0.6 | ) | 99.4 | ||||||||
3.57%, due July 16, 2027 | 200.0 | (1.3 | ) | 198.7 | ||||||||
4.10%, due September 18, 2034 | 250.0 | (2.6 | ) | 247.4 | ||||||||
4.65%, due August 1, 2043 | 300.0 | (3.0 | ) | 297.0 | ||||||||
3.60%, due September 1, 2025 | 150.0 | (1.4 | ) | 148.6 | ||||||||
Medium-Term Notes: | ||||||||||||
6.87%, due October 6, 2023 | 45.0 | (0.1 | ) | 44.9 | ||||||||
8.45%, due September 19, 2024 | 40.0 | (0.1 | ) | 39.9 | ||||||||
7.40%, due October 3, 2025 | 55.0 | (0.2 | ) | 54.8 | ||||||||
7.50%, due October 9, 2026 | 40.0 | (0.1 | ) | 39.9 | ||||||||
7.95%, due September 14, 2029 | 60.0 | (0.3 | ) | 59.7 | ||||||||
6.00%, due December 19, 2033 | 100.0 | (0.7 | ) | 99.3 | ||||||||
Total | 1,575.0 | (11.3 | ) | 1,563.7 | ||||||||
Less current maturities | 40.0 | — | 40.0 | |||||||||
Total | $ | 1,535.0 | $ | (11.3 | ) | $ | 1,523.7 |
(in millions) | |||
2017 | $ | 35.0 | |
2018 | — | ||
2019 | — | ||
2020 | — | ||
2021 | 160.0 | ||
Thereafter | 1,640.0 | ||
Total | $ | 1,835.0 |
• | Failure to make principal or interest payments, |
• | Bankruptcy, liquidation or insolvency, |
• | Final judgment against us in excess of $1.0 million that after 60 days is not discharged, satisfied or stayed pending appeal, |
• | Specified events under the Employee Retirement Income Security Act of 1974, |
• | Change in control, and |
• | Failure to observe or perform covenants, including: |
• | Interest coverage of at least 1.75 times. Interest coverage was 4.65 times as of October 31, 2016; |
• | Funded debt cannot exceed 70% of total capitalization. Funded debt was 55% of total capitalization as of October 31, 2016; |
• | Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded debt of our subsidiaries as of October 31, 2016; |
• | Restrictions on permitted liens; |
• | Restrictions on paying dividends on or repurchasing our stock or making investments in subsidiaries; and |
• | Restrictions on burdensome agreements. |
(in millions) | |||
Minimum amount outstanding | $ | 110.0 | |
Maximum amount outstanding | $ | 530.0 | |
Minimum interest rate | .20 | % | |
Maximum interest rate | .75 | % | |
Weighted average interest rate | .55 | % |
Recurring Fair Value Measurements as of October 31, 2016 | ||||||||||||||||||||
Significant | Effects of | |||||||||||||||||||
Quoted Prices | Other | Significant | Netting and | |||||||||||||||||
in Active | Observable | Unobservable | Cash Collateral | Total | ||||||||||||||||
Markets | Inputs | Inputs | Receivables/ | Carrying | ||||||||||||||||
(in millions) | (Level 1) | (Level 2) | (Level 3) | Payables | Value | |||||||||||||||
Assets: | ||||||||||||||||||||
Derivatives held for distribution operations | $ | 1.5 | $ | — | $ | — | $ | — | $ | 1.5 | ||||||||||
Debt and equity securities held as trading securities: | ||||||||||||||||||||
Money markets | 0.5 | — | — | — | 0.5 | |||||||||||||||
Mutual funds | 3.7 | — | — | — | 3.7 | |||||||||||||||
Total fair value assets | $ | 5.7 | $ | — | $ | — | $ | — | $ | 5.7 | ||||||||||
Liabilities: | ||||||||||||||||||||
Derivatives - gas supply contracts held for utility operations | $ | — | $ | — | $ | 187.9 | $ | — | $ | 187.9 |
Recurring Fair Value Measurements as of October 31, 2015 | ||||||||||||||||||||
Significant | Effects of | |||||||||||||||||||
Quoted Prices | Other | Significant | Netting and | |||||||||||||||||
in Active | Observable | Unobservable | Cash Collateral | Total | ||||||||||||||||
Markets | Inputs | Inputs | Receivables/ | Carrying | ||||||||||||||||
(in millions) | (Level 1) | (Level 2) | (Level 3) | Payables | Value | |||||||||||||||
Assets: | ||||||||||||||||||||
Derivatives held for distribution operations | $ | 1.3 | $ | — | $ | — | $ | — | $ | 1.3 | ||||||||||
Debt and equity securities held as trading securities: | ||||||||||||||||||||
Money markets | 0.5 | — | — | — | 0.5 | |||||||||||||||
Mutual funds | 4.4 | — | — | — | 4.4 | |||||||||||||||
Total fair value assets | $ | 6.2 | $ | — | $ | — | $ | — | $ | 6.2 |
(in millions) | 2016 | ||
Gas supply derivative liabilities, beginning balance | $ | — | |
Realized and unrealized losses: | |||
Recorded to regulatory assets * | 187.9 | ||
Purchases, sales and settlements (net) | — | ||
Transfer in/out of Level 3 | — | ||
Gas supply derivative liabilities, ending balance | $ | 187.9 | |
* Included are the actual costs recorded within "Cost of natural gas" on the Consolidated Statements of Operations and Comprehensive Income due to the confidential nature of contract pricing. |
Fair Value of Derivative Instruments | ||||||||
(in millions) | 2016 | 2015 | ||||||
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards: | ||||||||
Financial Asset Instruments: | ||||||||
Current Assets - Gas purchase derivative assets | $ | 1.5 | $ | 1.3 | ||||
Nonfinancial Liabilities Instruments: | ||||||||
Current Liabilities - Gas supply derivative liabilities | 41.5 | |||||||
Noncurrent Liabilities - Gas supply derivative liabilities | 146.4 |
Amount of | Amount of | Location of Gain (Loss) | ||||||||||||||||
Gain (Loss) Recognized | Gain (Loss) Deferred | Recognized through | ||||||||||||||||
on Derivative Instruments | Under PGA Procedures | PGA Procedures | ||||||||||||||||
Twelve Months Ended | Twelve Months Ended | |||||||||||||||||
October 31, | October 31, | |||||||||||||||||
(in millions) | 2016 | 2015 | 2016 | 2015 | ||||||||||||||
Gas purchase options | $ | (5.2 | ) | $ | (4.4 | ) | $ | (5.2 | ) | $ | (4.4 | ) | Cost of natural gas |
(in millions) | Principal | Fair Value | ||||||
As of October 31, 2016 | $ | 1,835.0 | $ | 2,061.2 | ||||
As of October 31, 2015 | 1,575.0 | 1,720.6 |
(in millions) | 2016 | 2015 | 2014 | |||||||||
Operating lease payments (1) | $ | 4.8 | $ | 5.0 | $ | 4.7 | ||||||
(1) Operating lease payments do not include payments for common area maintenance, utilities or tax payments. |
(in millions) | |||
2017 | $ | 4.7 | |
2018 | 4.6 | ||
2019 | 4.4 | ||
2020 | 4.5 | ||
2021 | 4.6 | ||
Thereafter | 19.8 | ||
Total | $ | 42.6 |
Pipeline | Gas Supply | Gas Supply | Telecommunications | |||||||||||||||||||||
and Storage | Reservation | Purchase | and Information | |||||||||||||||||||||
(in millions) | Capacity | Fees | Commitments | Technology | Other | Total | ||||||||||||||||||
2017 | $ | 170.0 | $ | 2.2 | $ | 124.4 | $ | 9.6 | $ | 62.1 | $ | 368.3 | ||||||||||||
2018 | 143.8 | — | 96.8 | 5.4 | — | 246.0 | ||||||||||||||||||
2019 | 133.4 | — | 96.8 | 5.2 | — | 235.4 | ||||||||||||||||||
2020 | 115.4 | — | 97.1 | 4.5 | — | 217.0 | ||||||||||||||||||
2021 | 113.7 | — | 96.8 | 1.1 | — | 211.6 | ||||||||||||||||||
Thereafter | 405.5 | — | 896.1 | — | — | 1,301.6 | ||||||||||||||||||
Total | $ | 1,081.8 | $ | 2.2 | $ | 1,408.0 | $ | 25.8 | $ | 62.1 | $ | 2,579.9 |
• | Achieve full funding over the longer term, and |
• | Fixed income securities: includes U.S. treasuries, corporate bonds, high yield debt (bank loans), asset-backed securities and derivatives. The derivatives in the fixed income portfolio are fully collateralized. The investment guidelines limit liabilities created with derivatives in the fixed income portfolio to cash equivalents plus 10% of the portfolio’s market value. The aggregate risk exposure of the plan can be no greater than that which could be achieved without using derivatives. |
• | Equity securities: includes large cap growth, large cap value and small cap domestic equity securities, as well as international equity. |
• | Real estate: includes a diversified global real estate investment trust fund. |
• | Other investments: includes commodities, hedge funds and private equity funds that follow several diversified strategies. |
Target | Assets as of October 31, | ||||||||
Asset Allocations | Allocation | 2016 | 2015 | ||||||
Fixed income securities | 45 | % | 46 | % | 46 | % | |||
Equity securities | 35 | % | 33 | % | 34 | % | |||
Real estate | 5 | % | 5 | % | 5 | % | |||
Cash and cash equivalents | — | % | 2 | % | 1 | % | |||
Other investments | 15 | % | 14 | % | 14 | % | |||
Total | 100 | % | 100 | % | 100 | % |
Target | Assets as of October 31, | |||||||||
Asset Allocations | Allocation | 2016 | 2015 | |||||||
Fixed income securities | 45 | % | (1) | 47 | % | 47 | % | |||
Equity securities | 47 | % | 44 | % | 44 | % | ||||
Real estate | 5 | % | 5 | % | 5 | % | ||||
Cash and cash equivalents | 3 | % | 4 | % | 4 | % | ||||
Total | 100 | % | 100 | % | 100 | % | ||||
(1) Includes 5% target allocation to high yield fixed income. |
(in millions) | 2016 | 2015 | ||||||
Funding | $ | 0.5 | $ | 0.5 | ||||
Liability | 4.7 | 5.3 |
Qualified Pension | Nonqualified Pension | Other Benefits | ||||||||||||||||||||||
(in millions) | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||||
Accumulated benefit obligation at year end | $ | 296.3 | $ | 263.1 | $ | 4.6 | $ | 5.5 | N/A | N/A | ||||||||||||||
Change in projected benefit obligation: | ||||||||||||||||||||||||
Obligation at beginning of year | $ | 311.5 | $ | 302.7 | $ | 5.5 | $ | 5.9 | $ | 37.6 | $ | 37.8 | ||||||||||||
Service cost | 10.6 | 11.4 | — | — | 1.2 | 1.2 | ||||||||||||||||||
Interest cost | 9.5 | 12.0 | 0.2 | 0.2 | 1.3 | 1.5 | ||||||||||||||||||
Plan amendments | — | — | — | — | — | (1.9 | ) | |||||||||||||||||
Plan settlements | — | — | (0.9 | ) | — | — | — | |||||||||||||||||
Actuarial loss (gain) | 34.1 | 3.5 | 0.3 | (0.1 | ) | 1.6 | 1.7 | |||||||||||||||||
Participant contributions | — | — | — | — | 0.1 | 0.6 | ||||||||||||||||||
Administrative expenses | (0.5 | ) | (0.6 | ) | — | — | — | — | ||||||||||||||||
Benefit payments | (13.5 | ) | (17.5 | ) | (0.5 | ) | (0.5 | ) | (2.5 | ) | (3.3 | ) | ||||||||||||
Obligation at end of year | 351.7 | 311.5 | 4.6 | 5.5 | 39.3 | 37.6 | ||||||||||||||||||
Change in fair value of plan assets: | ||||||||||||||||||||||||
Fair value at beginning of year | 329.3 | 336.4 | — | — | 27.5 | 27.7 | ||||||||||||||||||
Actual return on plan assets | 17.6 | 1.0 | — | — | 1.1 | 0.3 | ||||||||||||||||||
Employer contributions | 10.0 | 10.0 | 1.4 | 0.5 | 2.6 | 2.2 | ||||||||||||||||||
Participant contributions | — | — | — | — | 0.1 | 0.6 | ||||||||||||||||||
Administrative expenses | (0.5 | ) | (0.6 | ) | — | — | — | — | ||||||||||||||||
Plan settlements | — | — | (0.9 | ) | — | — | — | |||||||||||||||||
Benefit payments | (13.5 | ) | (17.5 | ) | (0.5 | ) | (0.5 | ) | (2.5 | ) | (3.3 | ) | ||||||||||||
Fair value at end of year | 342.9 | 329.3 | — | — | 28.8 | 27.5 | ||||||||||||||||||
Funded status at year end - (under) over | $ | (8.8 | ) | $ | 17.8 | $ | (4.6 | ) | $ | (5.5 | ) | $ | (10.5 | ) | $ | (10.1 | ) | |||||||
Noncurrent assets | $ | — | $ | 17.8 | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Current liabilities | — | — | (0.5 | ) | (0.5 | ) | — | — | ||||||||||||||||
Noncurrent liabilities | (8.8 | ) | — | (4.1 | ) | (5.0 | ) | (10.5 | ) | (10.1 | ) | |||||||||||||
Net amount recognized | $ | (8.8 | ) | $ | 17.8 | $ | (4.6 | ) | $ | (5.5 | ) | $ | (10.5 | ) | $ | (10.1 | ) | |||||||
Amounts Not Yet Recognized as a Component | ||||||||||||||||||||||||
of Cost and Recognized in a Deferred | ||||||||||||||||||||||||
Regulatory Account: | ||||||||||||||||||||||||
Unrecognized prior service credit (cost) | $ | 10.7 | $ | 12.8 | $ | — | $ | (0.2 | ) | $ | 1.5 | $ | 1.9 | |||||||||||
Unrecognized actuarial loss | (153.1 | ) | (120.5 | ) | (1.5 | ) | (1.6 | ) | (9.1 | ) | (7.2 | ) | ||||||||||||
Regulatory asset | (142.4 | ) | (107.7 | ) | (1.5 | ) | (1.8 | ) | (7.6 | ) | (5.3 | ) | ||||||||||||
Cumulative employer contributions in | ||||||||||||||||||||||||
excess of cost | 133.6 | 125.5 | (3.1 | ) | (3.7 | ) | (2.9 | ) | (4.8 | ) | ||||||||||||||
Net amount recognized | $ | (8.8 | ) | $ | 17.8 | $ | (4.6 | ) | $ | (5.5 | ) | $ | (10.5 | ) | $ | (10.1 | ) | |||||||
Weighted average assumptions used in the measurement of | ||||||||||||||||||||||||
the benefit obligations: | ||||||||||||||||||||||||
Discount rate | 3.80 | % | 4.34 | % | 3.80 | % | 3.85 | % | 3.80 | % | 4.38 | % | ||||||||||||
Rate of compensation increase | 4.05 | % | 4.07 | % | N/A | N/A | N/A | N/A |
Qualified Pension | Nonqualified Pension | Other Benefits | ||||||||||||||||||||||||||||||||||
(in millions) | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 | |||||||||||||||||||||||||||
Service cost | $ | 10.6 | $ | 11.4 | $ | 10.9 | $ | — | $ | — | $ | — | $ | 1.2 | $ | 1.2 | $ | 1.1 | ||||||||||||||||||
Interest cost | 9.5 | 12.0 | 11.7 | 0.2 | 0.2 | 0.2 | 1.3 | 1.5 | 1.5 | |||||||||||||||||||||||||||
Expected return on plan assets | (24.0 | ) | (23.6 | ) | (22.5 | ) | — | — | — | (1.8 | ) | (1.8 | ) | (1.8 | ) | |||||||||||||||||||||
Amortization of prior service (credit) | ||||||||||||||||||||||||||||||||||||
cost | (2.2 | ) | (2.2 | ) | (2.2 | ) | 0.2 | 0.2 | 0.2 | (0.3 | ) | — | — | |||||||||||||||||||||||
Amortization of net loss | 8.0 | 8.7 | 7.7 | — | 0.1 | 0.1 | 0.4 | — | — | |||||||||||||||||||||||||||
Settlement loss recognized | — | — | — | 0.3 | — | — | — | — | — | |||||||||||||||||||||||||||
Net periodic benefit cost | 1.9 | 6.3 | 5.6 | 0.7 | 0.5 | 0.5 | 0.8 | 0.9 | 0.8 | |||||||||||||||||||||||||||
Other changes in plan assets and benefit | ||||||||||||||||||||||||||||||||||||
obligation recognized through | ||||||||||||||||||||||||||||||||||||
regulatory asset or liability: | ||||||||||||||||||||||||||||||||||||
Prior service cost (credit) | — | — | — | — | — | 0.5 | — | (1.9 | ) | — | ||||||||||||||||||||||||||
Net loss (gain) | 40.5 | 26.2 | 14.4 | 0.3 | (0.1 | ) | 1.0 | 2.4 | 3.2 | 3.6 | ||||||||||||||||||||||||||
Amounts recognized as a component of | ||||||||||||||||||||||||||||||||||||
net periodic benefit cost: | ||||||||||||||||||||||||||||||||||||
Amortization of net loss | (8.0 | ) | (8.7 | ) | (7.7 | ) | — | (0.1 | ) | (0.1 | ) | (0.4 | ) | — | — | |||||||||||||||||||||
Settlement loss recognized | — | — | — | (0.3 | ) | — | — | — | — | — | ||||||||||||||||||||||||||
Prior service credit (cost) | 2.2 | 2.2 | 2.2 | (0.2 | ) | (0.2 | ) | (0.2 | ) | 0.3 | — | — | ||||||||||||||||||||||||
Total recognized in regulatory asset | ||||||||||||||||||||||||||||||||||||
(liability) | 34.7 | 19.7 | 8.9 | (0.2 | ) | (0.4 | ) | 1.2 | 2.3 | 1.3 | 3.6 | |||||||||||||||||||||||||
Total recognized in net periodic benefit | ||||||||||||||||||||||||||||||||||||
and regulatory asset | $ | 36.6 | $ | 26.0 | $ | 14.5 | $ | 0.5 | $ | 0.1 | $ | 1.7 | $ | 3.1 | $ | 2.2 | $ | 4.4 | ||||||||||||||||||
Weighted average assumptions used to determine the net periodic benefit cost: | ||||||||||||||||||||||||||||||||||||
Discount rate | 4.34 | % | 4.13 | % | 4.55 | % | 3.85 | % | 3.69 | % | 3.98 | % | 4.38 | % | 4.03 | % | 4.44 | % | ||||||||||||||||||
Expected long-term rate of return on plan assets | 7.25 | % | 7.50 | % | 7.75 | % | N/A | N/A | N/A | 7.25 | % | 7.50 | % | 7.75 | % | |||||||||||||||||||||
Rate of compensation increase | 4.07 | % | 3.68 | % | 3.72 | % | N/A | N/A | N/A | N/A | N/A | N/A |
Qualified | Nonqualified | Other | ||||||||||
(in millions) | Pension | Pension | Benefits | |||||||||
Amortization of unrecognized prior service credit | $ | (2.2 | ) | $ | — | $ | (0.3 | ) | ||||
Amortization of unrecognized actuarial loss | 11.3 | 0.1 | 0.7 |
(in millions) | |||
Qualified pension plan | $ | 10.0 | |
Nonqualified pension plans | 0.5 | ||
MPP plan | 2.1 | ||
OPEB plan | 2.2 |
Qualified | Nonqualified | Other | ||||||||||
(in millions) | Pension | Pension | Benefits | |||||||||
2017 | $ | 39.6 | $ | 0.5 | $ | 1.9 | ||||||
2018 | 25.2 | 0.5 | 2.1 | |||||||||
2019 | 25.0 | 0.5 | 2.2 | |||||||||
2020 | 24.8 | 0.4 | 2.4 | |||||||||
2021 | 24.9 | 0.4 | 2.4 | |||||||||
2022 – 2026 | 126.8 | 1.7 | 13.1 |
• | U.S. treasuries – These are Level 2 assets whose values are based on observable market information including quotes from a quotation reporting system, established market makers or pricing services. This asset class includes long duration fixed income investments. |
• | Corporate bonds, collateralized mortgage obligations, municipals – These are Level 2 assets valued based on primarily observable market information or broker quotes on a non-active market. This class includes long duration fixed income investments. |
• | Derivatives – The Level 1 assets are valued using a compilation of observable market information on an active market. The Level 2 assets are valued using broker quotes on a non-active market. |
Redemptions | ||||||
Redemption | Notice | |||||
Investment | Frequency | Other Redemption Restrictions | Period | |||
Common trust fund - International growth | Monthly | None | 30 days | |||
Hedge fund of funds | Quarterly | Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on "first in first out" basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2016. | 65 days | |||
Private equity fund of funds | Limited | Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval. | (1) | |||
Commodities fund of funds | Monthly | Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete. | 35 business days | |||
Bank loans | Daily | None | 30 days |
Qualified Pension Plan as of October 31, 2016 | |||||||||||||||||
(in millions) | Quoted Prices In Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total Carrying Value | |||||||||||||
Cash and cash equivalents | $ | 5.1 | $ | 0.8 | $ | — | $ | 5.9 | |||||||||
Fixed income securities | — | 78.9 | — | 78.9 | |||||||||||||
Equity securities | 44.4 | — | — | 44.4 | |||||||||||||
Mutual funds | 78.2 | 55.0 | — | 133.2 | |||||||||||||
Common trust fund | — | 25.0 | — | 25.0 | |||||||||||||
Private equity fund of funds | — | — | 8.9 | 8.9 | |||||||||||||
Other Investments: | |||||||||||||||||
Hedge fund of funds | 20.0 | (1) | |||||||||||||||
Commodities fund of funds | 9.2 | (1) | |||||||||||||||
High yield debt (bank loans) | 17.4 | (1) | |||||||||||||||
Total assets at fair value | $ | 127.7 | $ | 159.7 | $ | 8.9 | $ | 342.9 |
Qualified Pension Plan as of October 31, 2015 | |||||||||||||||||
(in millions) | Quoted Prices In Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total Carrying Value | |||||||||||||
Cash and cash equivalents | $ | 2.8 | $ | 0.1 | $ | — | $ | 2.9 | |||||||||
Fixed income securities | — | 84.1 | — | 84.1 | |||||||||||||
Equity securities | 44.7 | — | — | 44.7 | |||||||||||||
Mutual funds | 78.9 | 42.9 | — | 121.8 | |||||||||||||
Common trust fund | — | 23.6 | — | 23.6 | |||||||||||||
Private equity fund of funds | — | — | 8.3 | 8.3 | |||||||||||||
Other Investments: | |||||||||||||||||
Hedge fund of funds | 19.8 | (1) | |||||||||||||||
Commodities fund of funds | 7.7 | (1) | |||||||||||||||
High yield debt (bank loans) | 16.4 | (1) | |||||||||||||||
Total assets at fair value | $ | 126.4 | $ | 150.7 | $ | 8.3 | $ | 329.3 | |||||||||
(1) In accordance with accounting guidance, certain investments that are measured at fair value using the NAV per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above. |
Private | ||||
Equity Fund | ||||
(in millions) | of Funds | |||
Balance, October 31, 2014 | $ | 7.2 | ||
Actual return on plan assets: | ||||
Relating to assets still held at the reporting date | 0.4 | |||
Relating to assets sold during the period | 0.6 | |||
Purchases, sales and settlements (net) | 0.1 | |||
Transfer in/out of Level 3 | — | |||
Balance, October 31, 2015 | 8.3 | |||
Actual return on plan assets: | ||||
Relating to assets still held at the reporting date | 0.1 | |||
Relating to assets sold during the period | 0.5 | |||
Purchases, sales and settlements (net) | — | |||
Transfer in/out of Level 3 | — | |||
Balance, October 31, 2016 | $ | 8.9 |
Other Benefits as of October 31, 2016 | ||||||||||||||||
(in millions) | Quoted Prices In Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total Carrying Value | ||||||||||||
Cash and cash equivalents | $ | 1.2 | $ | — | $ | — | $ | 1.2 | ||||||||
Mutual funds | 27.6 | — | — | 27.6 | ||||||||||||
Total assets at fair value | $ | 28.8 | $ | — | $ | — | $ | 28.8 |
Other Benefits as of October 31, 2015 | ||||||||||||||||
(in millions) | Quoted Prices In Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total Carrying Value | ||||||||||||
Cash and cash equivalents | $ | 1.1 | $ | — | $ | — | $ | 1.1 | ||||||||
Mutual funds | 26.4 | — | — | 26.4 | ||||||||||||
Total assets at fair value | $ | 27.5 | $ | — | $ | — | $ | 27.5 |
(in millions) | 2016 | 2015 | 2014 | |||||||||
401(k) matching contributions | $ | 6.9 | $ | 6.6 | $ | 6.1 |
December 15, 2014 vesting (20% of the grant) | December 15, 2015 vesting (30% of the grant) | Accelerated RSU settled on December 15, 2015 (50% of the grant) | |||||||||||
Shares of common stock issued, including accrued dividends, net of shares withheld for taxes | 7,231 | 11,732 | 19,554 | ||||||||||
NYSE composite closing price | $ | 37.89 | (1) | $ | 56.85 | (2) | $ | 56.85 | (2) | ||||
(1) Closing price on December 12, 2014. | |||||||||||||
(2) Closing price on December 14, 2015. |
(in millions) | 2016 | 2015 | 2014 | |||||||||
Compensation expense | $ | 16.1 | (1) | $ | 14.2 | $ | 8.5 | |||||
Tax benefit | 6.1 | 4.0 | 2.5 | |||||||||
Liability | — | 22.0 | ||||||||||
(1) Includes $5.3 million incremental expense related to the accelerated ICP and RSU awards, and the conversion of the 2018 plan to a Duke Energy RSU Award. See Note 2 for further information. |
2016 | 2015 | 2014 | ||||||||||||||||||||||
(in millions) | Federal | State | Federal | State | Federal | State | ||||||||||||||||||
Charged (Credited) to income: | ||||||||||||||||||||||||
Current | $ | 27.2 | $ | 11.8 | $ | (0.7 | ) | $ | 1.1 | $ | 2.5 | $ | 1.8 | |||||||||||
Deferred (1) (2) | 79.6 | 5.8 | 77.9 | 12.1 | 76.5 | 14.2 | ||||||||||||||||||
Tax Credits: | ||||||||||||||||||||||||
Amortization | (0.2 | ) | — | (0.2 | ) | — | (0.2 | ) | — | |||||||||||||||
Total | $ | 106.6 | $ | 17.6 | $ | 77.0 | $ | 13.2 | $ | 78.8 | $ | 16.0 | ||||||||||||
(1) Includes benefits from net operating loss (NOL) and tax carryforwards of $91.4 million and $64.3 million for the years ended October 31, 2016 and 2015, respectively. | ||||||||||||||||||||||||
(2) Includes the anticipated utilization of NOL and tax carryforwards of $19.8 million and $28.6 million for the years ended October 31, 2015 and 2014, respectively. |
(in millions) | 2016 | 2015 | 2014 | |||||||||
Federal taxes at 35% | $ | 111.1 | $ | 79.5 | $ | 83.5 | ||||||
State income taxes, net of federal benefit | 11.4 | 8.6 | 10.4 | |||||||||
Amortization of investment tax credits | (0.2 | ) | (0.2 | ) | (0.2 | ) | ||||||
Other, net | 1.9 | 2.3 | 1.1 | |||||||||
Total | $ | 124.2 | $ | 90.2 | $ | 94.8 | ||||||
Effective Tax Rate | 39.1 | % | 39.7 | % | 39.7 | % |
(in millions) | 2016 | 2015 | ||||||
Deferred tax assets: | ||||||||
Benefit of tax carryforwards | $ | 175.4 | $ | 84.0 | ||||
Revenues and cost of natural gas | — | 3.5 | ||||||
Employee benefits and compensation | 28.6 | 22.1 | ||||||
Revenue requirement | 30.1 | 26.1 | ||||||
Property, plant and equipment | 5.3 | 7.5 | ||||||
Regulatory asset - gas supply derivative contracts held for utility operations | 70.6 | — | ||||||
Other | 13.8 | 10.5 | ||||||
Total deferred tax assets | 323.8 | 153.7 | ||||||
Valuation allowance | (0.8 | ) | (0.8 | ) | ||||
Total deferred tax assets, net | 323.0 | 152.9 | ||||||
Deferred tax liabilities: | ||||||||
Property, plant and equipment | 1,010.8 | 849.8 | ||||||
Revenues and cost of natural gas | 20.0 | — | ||||||
Investments in equity method unconsolidated affiliates | 34.8 | 44.8 | ||||||
Deferred costs | 85.0 | 73.9 | ||||||
Gas supply derivative liabilities | 70.6 | — | ||||||
Other | 5.9 | 13.6 | ||||||
Total deferred tax liabilities | 1,227.1 | 982.1 | ||||||
Net deferred income tax liabilities | $ | 904.1 | $ | 829.2 |
(in millions) | 2016 | 2015 | 2014 | |||||||||
Balance at beginning of year | $ | 0.8 | $ | 0.5 | $ | 0.5 | ||||||
Charged to income tax expense | — | 0.3 | — | |||||||||
Balance at end of year | $ | 0.8 | $ | 0.8 | $ | 0.5 |
(in millions) | Amount | Expiration Year | ||||
Federal NOL | $ | 163.5 | 2020 | – | 2036 | |
State NOL | 8.4 | 2027 | – | 2036 | ||
Capital loss carryforward | 0.3 | 2017 | ||||
Charitable carryforward | 3.2 | 2016 | – | 2019 | ||
Total NOL and charitable carryforwards | $ | 175.4 |
North Carolina Corporate Income Tax Rate * | Tax Year Rate is Effective | |
6.9% | Prior to November 1, 2014 | |
6.0% | November 1, 2014 to October 31, 2015 | |
5.0% | November 1, 2015 to October 3, 2016 | |
4.0% | October 4, 2016 to December 31, 2016 | |
3.0% | Beginning January 1, 2017 | |
* We record deferred income taxes using the income tax rate in effect when the temporary difference is expected to reverse. |
Entity Name | Interest | Activity | ||
Cardinal Pipeline Company, LLC (Cardinal) | 21.49% | Intrastate pipeline located in North Carolina; regulated by the NCUC | ||
Pine Needle LNG Company, LLC (Pine Needle) | 45% | Interstate LNG storage facility located in North Carolina; regulated by the FERC | ||
SouthStar * | —% | Energy services company primarily selling natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily Georgia and Illinois | ||
Hardy Storage Company, LLC (Hardy Storage) | 50% | Underground interstate storage facility located in Hardy and Hampshire Counties, West Virginia; regulated by the FERC | ||
Constitution Pipeline Company LLC (Constitution) | 24% | To develop, construct, own and operate 124 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York; regulated by the FERC | ||
Atlantic Coast Pipeline, LLC (ACP) ** | 7% | To develop, construct, own and operate 564 miles of interstate natural gas pipeline with associated compression from West Virginia through Virginia into eastern North Carolina in order to provide interstate natural gas transportation services of Marcellus and Utica gas supplies into southeastern markets; regulated by the FERC | ||
* On October 3, 2016, we sold our 15% interest in SouthStar, effective with the consummation of the Acquisition. | ||||
** On October 3, 2016, as a result of the Acquisition, we sold 3% of our interest, reducing our ownership from 10% to 7%. |
(in millions) | 2016 | 2015 | ||||||
Cardinal | $ | 14.2 | $ | 15.1 | ||||
Pine Needle | 16.6 | 18.4 | ||||||
SouthStar | — | 41.3 | ||||||
Hardy Storage | 42.1 | 39.7 | ||||||
Constitution | 93.1 | 82.4 | ||||||
ACP | 33.2 | 10.1 | ||||||
Total investments in equity method unconsolidated affiliates | $ | 199.2 | $ | 207.0 |
(in millions) | 2016 | 2015 | 2014 | |||||||||
Cardinal | $ | 1.5 | $ | 1.7 | $ | 1.7 | ||||||
Pine Needle | 2.8 | 2.7 | 2.7 | |||||||||
SouthStar | 18.8 | 19.4 | 20.4 | |||||||||
Hardy Storage | 5.1 | 5.2 | 5.3 | |||||||||
Constitution | (1.3 | ) | 6.1 | 2.7 | ||||||||
ACP | 1.7 | (0.6 | ) | — | ||||||||
Equity in earnings of unconsolidated affiliates | $ | 28.6 | $ | 34.5 | $ | 32.8 |
Related Party | Type of Expense | Cost of Natural Gas (1) | Accounts Payable to Affiliated Companies (2) | |||||||||||||||||||
(in millions) | 2016 | 2015 | 2014 | 2016 | 2015 | |||||||||||||||||
Cardinal | Transportation costs | $ | 8.7 | $ | 8.8 | $ | 8.8 | $ | 0.7 | $ | 0.7 | |||||||||||
Pine Needle | Gas storage costs | 10.7 | 11.4 | 11.4 | 0.9 | 1.0 | ||||||||||||||||
Hardy Storage | Gas storage costs | 9.3 | 9.3 | 9.5 | 0.8 | 0.8 | ||||||||||||||||
Totals | $ | 28.7 | $ | 29.5 | $ | 29.7 | $ | 2.4 | $ | 2.5 | ||||||||||||
(1) In the Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||||
(2) In the Consolidated Balance Sheets. |
Operating Revenues (1) | Receivables from Affiliated Companies (2) | |||||||||||||||||||
(in millions) | 2016 | 2015 | 2014 | 2016 | 2015 | |||||||||||||||
Operating revenues | $ | 0.3 | $ | 1.6 | $ | 3.5 | $ | — | $ | 0.2 | ||||||||||
(1) In the Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||
(2) In the Consolidated Balance Sheets. |
(in millions) | 2016 | 2015 | 2014 | ||||||
Current assets | $ | 10.3 | $ | 9.5 | |||||
Noncurrent assets | 101.5 | 106.4 | |||||||
Current liabilities | 46.0 | 1.2 | |||||||
Noncurrent liabilities | 0.3 | 45.4 | |||||||
Revenues | 16.6 | 16.6 | $ | 16.7 | |||||
Gross profit | 16.6 | 16.6 | 16.7 | ||||||
Income before income taxes | 7.7 | 7.7 | 8.0 |
(in millions) | 2016 | 2015 | 2014 | ||||||
Current assets | $ | 7.7 | $ | 9.9 | |||||
Noncurrent assets | 68.1 | 71.6 | |||||||
Current liabilities | 3.0 | 5.4 | |||||||
Noncurrent liabilities | 35.2 | 35.1 | |||||||
Revenues | 17.1 | 16.9 | $ | 18.0 | |||||
Gross profit | 15.4 | 15.3 | 15.3 | ||||||
Income before income taxes | 6.8 | 6.0 | 6.0 |
(in millions) | 2016 | 2015 | 2014 | ||||||
Current assets | $ | 212.2 | $ | 204.2 | |||||
Noncurrent assets | 126.8 | 132.3 | |||||||
Current liabilities | 47.1 | 46.0 | |||||||
Noncurrent liabilities | — | — | |||||||
Revenues | 638.3 | 769.3 | $ | 845.7 | |||||
Gross profit | 216.4 | 244.6 | 234.6 | ||||||
Income before income taxes | 125.5 | 129.3 | 136.6 |
(in millions) | 2016 | 2015 | 2014 | ||||||
Current assets | $ | 6.6 | $ | 11.7 | |||||
Noncurrent assets | 151.8 | 156.8 | |||||||
Current liabilities | 14.4 | 19.1 | |||||||
Noncurrent liabilities | 59.1 | 70.0 | |||||||
Revenues | 23.5 | 23.4 | $ | 23.8 | |||||
Gross profit | 23.5 | 23.4 | 23.8 | ||||||
Income before income taxes | 11.0 | 10.4 | 10.5 |
(in millions) | 2016 | 2015 | 2014 | ||||||
Current assets | $ | 6.6 | $ | 6.2 | |||||
Noncurrent assets | 380.9 | 330.2 | |||||||
Current liabilities | 1.2 | 4.4 | |||||||
Noncurrent liabilities | — | — | |||||||
Revenues | — | — | $ | — | |||||
Gross profit | — | — | — | ||||||
Income (Loss) before income taxes | (3.4 | ) | 24.6 | 10.1 |
(in millions) | 2016 | 2015 | ||||
Current assets | $ | 134.3 | $ | 23.4 | ||
Noncurrent assets | 376.3 | 86.1 | ||||
Current liabilities | 47.9 | 9.1 | ||||
Noncurrent liabilities | — | — | ||||
Revenues | — | — | ||||
Gross profit | — | — | ||||
Income (Loss) before income taxes | 17.3 | (5.2 | ) |
Year Ended October 31, 2016 | ||||||||||||
Gas | ||||||||||||
Utilities and | ||||||||||||
(in millions) | Infrastructure | Other | Total | |||||||||
Unaffiliated revenues | $ | 1,141.7 | $ | — | $ | 1,141.7 | ||||||
Related party revenue from Duke Energy | 7.0 | — | 7.0 | |||||||||
Total Revenues | $ | 1,148.7 | $ | — | $ | 1,148.7 | ||||||
Interest Expense | $ | 68.6 | $ | — | $ | 68.6 | ||||||
Depreciation and amortization | 137.3 | — | 137.3 | |||||||||
Equity in earnings of unconsolidated affiliates | 9.8 | 18.8 | 28.6 | |||||||||
Gain on sale of unconsolidated affiliates | — | 132.8 | 132.8 | |||||||||
Income tax expense | 85.2 | 39.0 | 124.2 | |||||||||
Segment income | 143.3 | 49.9 | 193.2 | |||||||||
Capital investments and expenditures and acquisitions | $ | 569.2 | $ | — | $ | 569.2 | ||||||
Segment Assets | 5,691.0 | — | 5,691.0 | |||||||||
Year Ended October 31, 2015 | ||||||||||||
Gas | ||||||||||||
Utilities and | ||||||||||||
(in millions) | Infrastructure | Other | Total | |||||||||
Unaffiliated Revenues | $ | 1,383.1 | $ | — | $ | 1,383.1 | ||||||
Interest Expense | 68.6 | — | 68.6 | |||||||||
Depreciation and amortization | 128.7 | — | 128.7 | |||||||||
Equity in earnings of unconsolidated affiliates | 15.1 | 19.4 | 34.5 | |||||||||
Income tax expense | 85.9 | 4.3 | 90.2 | |||||||||
Segment Income | 131.1 | 5.9 | 137.0 | |||||||||
Capital investments and expenditures and acquisitions | $ | 473.4 | $ | — | $ | 473.4 | ||||||
Segment Assets | 5,045.0 | 41.3 | 5,086.3 | |||||||||
Year Ended October 31, 2014 | ||||||||||||
Gas | ||||||||||||
Utilities and | ||||||||||||
(in millions) | Infrastructure | Other | Total | |||||||||
Unaffiliated Revenues | $ | 1,479.5 | $ | — | $ | 1,479.5 | ||||||
Interest Expense | 54.7 | — | 54.7 | |||||||||
Depreciation and amortization | 119.0 | — | 119.0 | |||||||||
Equity in earnings of unconsolidated affiliates | 12.3 | 20.5 | 32.8 | |||||||||
Income tax expense | 87.0 | 7.8 | 94.8 | |||||||||
Segment Income | 131.2 | 12.6 | 143.8 | |||||||||
Capital investments and expenditures and acquisitions | $ | 498.1 | $ | — | $ | 498.1 | ||||||
Segment Assets | 4,678.8 | 41.0 | 4,719.8 |
(in millions) | 2016 | 2015 | 2014 | |||||||||
Retail Natural Gas | $ | 1,066.3 | $ | 1,237.4 | $ | 1,300.5 | ||||||
Wholesale Natural Gas | 72.3 | 134.3 | 169.5 | |||||||||
Other | 10.1 | 11.4 | 9.5 | |||||||||
Total Revenues | $ | 1,148.7 | $ | 1,383.1 | $ | 1,479.5 |
(in millions) | 2016 | 2015 | 2014 | ||||||||
Revenue from Duke Energy (1) | $ | 80.8 | $ | 83.2 | $ | 86.2 | |||||
Corporate governance and shared service expenses (2) | 0.2 | ||||||||||
(1) We provide long-term natural gas delivery service to several of Duke Energy's subsidiaries' natural gas-fired power generation facilities in our market area. This intercompany profit on sales is not eliminated in accordance with accounting regulations prescribed under rate-based regulation, as discussed in Note 1. | |||||||||||
(2) We are charged our proportionate share of corporate governance and other shared services costs, primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. Certain Piedmont executives are responsible for all of Duke Energy's natural gas operations and related infrastructure. A proportionate share of these individuals' payroll and employee benefits is charged to Duke Energy's subsidiary registrants. These amounts are recorded in "Operations, maintenance and other" in the Consolidated Statements of Operations and Comprehensive Income. |
Operating | Net | ||||||||||||
Operating | Income | Income | |||||||||||
Revenues | (Loss) | (Loss) | |||||||||||
Fiscal Year 2016 | |||||||||||||
January 31 | $ | 463.5 | $ | 171.3 | $ | 97.8 | |||||||
April 30 | 352.9 | 103.9 | 63.4 | ||||||||||
July 31 | 160.4 | 0.5 | (6.7 | ) | |||||||||
October 31 | 171.9 | (50.3 | ) | (1) | 38.7 | (2) | |||||||
Fiscal Year 2015 | |||||||||||||
January 31 | $ | 609.5 | $ | 162.2 | $ | 93.0 | |||||||
April 30 | 427.3 | 111.1 | 66.4 | ||||||||||
July 31 | 162.2 | (1.7 | ) | (8.3 | ) | ||||||||
October 31 | 184.1 | (8.8 | ) | (14.1 | ) | ||||||||
(1) The quarter loss is primarily due to Acquisition and integration-related expenses incurred in 2016. See Note 2 for further information. | |||||||||||||
(2) The increase is primarily due to the gain on the sale of our 15% ownership interest in SouthStar, partially offset by Acquisition and integration-related expenses. See Note 11 for further information on the sale of SouthStar. |
(in millions) | 2016 | 2015 | ||||||
Fees for Services | ||||||||
Audit Fees | $ | 1.3 | $ | 1.1 | ||||
Audit-Related Fees | 0.1 | (a) | 0.2 | (b) | ||||
Tax Fees | — | — | ||||||
All Other Fees | — | — | ||||||
Total Fees | $ | 1.4 | $ | 1.3 | ||||
(a) Consists of services related to the issuance by Deloitte of comfort and bring-down letters in relation to our 2016 debt offering and at-the-market (ATM) offering and consultation services. | ||||||||
(b) Consists of services related to the issuance by Deloitte of comfort and bring-down letters in relation to our 2015 debt offering and ATM offering, our registration statement on Form S-8 and consultation services. |
(a) | 1. | Financial Statements | ||
The following Consolidated Financial Statements for the year ended October 31, 2016, are included in Item 8 of this report as follows: | ||||
Consolidated Statements of Operations and Comprehensive Income – Years Ended October 31, 2016, 2015 and | ||||
2014 | ||||
Consolidated Balance Sheets – October 31, 2016 and 2015 Consolidated Statements of Cash Flows – Years Ended October 31, 2016, 2015 and 2014 Consolidated Statements of Changes in Equity – Years Ended October 31, 2016, 2015 and 2014 Notes to Consolidated Financial Statements Report of Independent Registered Public Accounting Firm | ||||
(a) | 2. | Supplemental Consolidated Financial Statement Schedules | ||
None Schedules and certain other information are omitted for the reason that they are not required or are not applicable, or the required information is shown in the Consolidated Financial Statements or notes thereto. | ||||
(a) | 3. | Exhibits | ||
Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses. Upon written request of a shareholder, we will provide a copy of the exhibit at a nominal charge. | ||||
2.1 | Agreement and Plan of Merger, dated as of October 24, 2015, by and among Duke Energy Corporation, Forest Subsidiary, Inc. and Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 2.1, Form 8-K dated October 26, 2015). | |||
3.1 | Amended and Restated Articles of Incorporation of Piedmont Natural Gas Company, Inc., dated as of October 3, 2016. | |||
3.2 | Bylaws of Piedmont Natural Gas Company, Inc., as amended and restated effective October 3, 2016 (incorporated by reference to Exhibit 3.2, Form 8-K dated October 3, 2016). | |||
4.1 | Note Agreement, dated as of September 21, 1992, between Piedmont and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.30, Form 10-K for the fiscal year ended October 31, 1992). | |||
4.2 | Amendment to September 1992 Note Agreement, dated as of September 16, 2005, by and between Piedmont and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.2, Form 10-K for the fiscal year ended October 31, 2007). | |||
4.3 | Indenture, dated as of April 1, 1993, between Piedmont and The Bank of New York Mellon Trust Company, N.A. (as successor to Citibank, N.A.), Trustee (incorporated by reference to Exhibit 4.1, Form S-3 Registration Statement No. 33-59369). | |||
4.4 | Medium-Term Note, Series A, dated as of October 6, 1993 (incorporated by reference to Exhibit 4.8, Form 10-K for the fiscal year ended October 31, 1993). | |||
4.5 | First Supplemental Indenture, dated as of February 25, 1994, between PNG Acquisition Company, Piedmont Natural Gas Company, Inc., and Citibank, N.A., Trustee (incorporated by reference to Exhibit 4.2, Form S-3 Registration Statement No. 33-59369). | |||
4.6 | Medium-Term Note, Series A, dated as of September 19, 1994 (incorporated by reference to Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994). | |||
4.7 | Form of Master Global Note (incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 33-59369). | |||
4.8 | Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995 (incorporated by reference to Exhibit 4.10, Form 10-K for the fiscal year ended October 31, 1995). | |||
4.9 | Pricing Supplement of Medium-Term Notes, Series B, dated October 4, 1996 (incorporated by reference to Exhibit 4.11, Form 10-K for the fiscal year ended October 31, 1996). | |||
4.10 | Form of Master Global Note (incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 333-26161). | |||
4.11 | Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (incorporated by reference to Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement Nos. 33-59369 and 333-26161). | |||
4.12 | Second Supplemental Indenture, dated as of June 15, 2003, between Piedmont and Citibank, N.A., Trustee (incorporated by reference to Exhibit 4.3, Form S-3 Registration Statement No. 333-106268). | |||
4.13 | Form of 6% Medium-Term Note, Series E, dated as of December 19, 2003 (incorporated by reference to Exhibit 99.2, Form 8-K, dated December 23, 2003). | |||
4.14 | Third Supplemental Indenture, dated as of June 20, 2006, between Piedmont Natural Gas Company, Inc. and Citibank, N.A., as trustee (incorporated by reference to Exhibit 4.1, Form 8-K dated June 20, 2006). | |||
4.15 | Agreement of Resignation, Appointment and Acceptance dated as of March 29, 2007, by and among Piedmont Natural Gas Company, Inc., Citibank, N.A., and The Bank of New York Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 10-Q for quarter ended April 30, 2007). | |||
4.16 | Note Purchase Agreement, dated as of May 6, 2011, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (incorporated by reference to Exhibit 10, Form 8-K, dated May 12, 2011). | |||
4.17 | Form of 4.24% Series B Senior Notes due June 6, 2021 (incorporated by reference to Exhibit 4.2, Form 8-K dated May 12, 2011). | |||
4.18 | Fourth Supplemental Indenture, dated as of May 6, 2011, between Piedmont Natural Gas Company, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2, Form S-3-ASR Registration Statement No. 333-175386). | |||
4.19 | Amendment to September 1992 Note Agreement dated as of April 15, 2011 by and between Piedmont Natural Gas Company, Inc., and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2011). | |||
4.20 | Note Purchase Agreement, dated as of March 27, 2012, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (incorporated by reference to Exhibit 10.1, Form 8-K dated March 29, 2012). | |||
4.21 | Form of 3.47% Series A Senior Notes due July 16, 2027 (incorporated by reference to Exhibit 4.1, Form 8-K dated March 29, 2012). | |||
4.22 | Form of 3.57% Series B Senior Notes due July 16, 2027 (incorporated by reference to Exhibit 4.2, Form 8-K dated March 29, 2012). | |||
4.23 | Corporate Commercial Paper Master Note dated March 1, 2012 between U.S. Bank National Association as Paying Agent and Piedmont Natural Gas Company, Inc. as Issuer (incorporated by reference to Exhibit 4.1, Form 10-Q for the quarter ended April 30, 2012). | |||
4.24 | Fifth Supplemental Indenture, dated August 1, 2013, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated August 1, 2013). | |||
4.25 | Form of 4.65% Senior Notes due 2043 (incorporated by reference to Exhibit 4.2, Form 8-K dated August 1, 2013). | |||
4.26 | Sixth Supplemental Indenture, dated September 18, 2014, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated September 18, 2014). | |||
4.27 | Form of 4.10% Senior Notes due 2034 (incorporated by reference to Exhibit 4.2, Form 8-K dated September 18, 2014). | |||
4.28 | Third Amendment to September 1992 Note Agreement, dated as of October 15, 2014, between the Company and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.29, Form 10-K for the fiscal year ended October 31, 2014). | |||
4.29 | Seventh Supplemental Indenture, dated September 14, 2015, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated September 14, 2015). | |||
4.30 | Form of 3.60% Senior Notes due 2025 (incorporated by reference to Exhibit 4.2, Form 8-K dated September 14, 2015). | |||
4.31 | Eighth Supplemental Indenture, dated July 28, 2016, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated July 28, 2016). | |||
4.32 | Form of 3.64% Senior Notes due 2046 (incorporated by reference to Exhibit 4.2, Form 8-K dated July 28, 2016). | |||
10.1 | Form of Commercial Paper Dealer Agreement between Piedmont Natural Gas Company, Inc. and Dealers party thereto (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2012). | |||
10.2 | Amended and Restated Credit Agreement dated as of October 1, 2012 among Piedmont Natural Gas Company, Inc., Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender, L/C Issuer and a Lender, and Branch Banking and Trust Company, Bank of America, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each a Lender (incorporated by reference to Exhibit 10.34, Form 10-K for the fiscal year ended October 31, 2012). | |||
10.3 | Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC dated April 9, 2012, by and among Williams Partners Operating LLC and Cabot Pipeline Holdings LLC (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2013). | |||
10.4 | First Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of November 9, 2012, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, and Piedmont Constitution Pipeline Company, LLC (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended January 31, 2013). | |||
10.5 | Second Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of May 29, 2013, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, Piedmont Constitution Pipeline Company, LLC, and Capitol Energy Ventures Corp. (incorporated by reference to Exhibit 99.1, Form 8-K filed September 4, 2013). | |||
10.6 | Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 1, 2013, by and between Georgia Natural Gas Company and Piedmont Energy Company (incorporated by reference to Exhibit 10.39, Form 10-K for the fiscal year ended October 31, 2013). | |||
10.7 | Increasing Lender Agreement dated as of November 1, 2013 among Wells Fargo Bank, National Association, Bank of America, N.A., Branch Banking and Trust Company, JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each as a Lender (incorporated by reference to Exhibit 10.1, Form 8-K dated November 4, 2013). | |||
10.8 * | Limited Liability Company Agreement of Atlantic Coast Pipeline, LLC, dated as of September 2, 2014, by and between Dominion Atlantic Coast Pipeline, LLC, Duke Energy ACP, LLC, Piedmont ACP Company, LLC, and Maple Enterprise Holdings, Inc. (incorporated by reference to Exhibit 10.35, Form 10-K for the fiscal year ended October 31, 2014). | |||
10.9 | ATM Equity Offering Sales Agreement dated January 7, 2015 between the Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated (incorporated by reference to Exhibit 1.1, Form 8-K dated January 7, 2015). | |||
10.10 | ATM Equity Offering Sales Agreement dated January 7, 2015 between the Company and J.P. Morgan Securities LLC (incorporated by reference to Exhibit 1.2, Form 8-K dated January 7, 2015). | |||
10.11 | Second Amended and Restated Credit Agreement, dated as of December 14, 2015, among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender, L/C Issuer and a Lender, and Bank of America, N.A, Branch Banking and Trust Company, JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each a Lender (incorporated by reference to Exhibit 10.1, Form 8-K dated December 16, 2015). | |||
10.12 | Letter Agreement between Georgia Natural Gas Company and Piedmont Energy Company dated February 12, 2016 (incorporated by reference to Exhibit 10.1, Form 8-K dated February 18, 2016). | |||
10.13 | Assignment of Membership Interests dated as of October 3, 2016 between Piedmont ACP Company, LLC and Dominion Atlantic Coast Pipeline, LLC, (incorporated by reference to Exhibit 10.1, Form 8-K dated October 7, 2016). | |||
10.14 | Conveyance and Assignment Agreement, dated as of October 3, 2016, by and between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.1, Form 8-K dated October 3, 2016). | |||
12 | Computation of Ratio of Earnings to Fixed Charges. | |||
23.1 | Consent of Independent Registered Public Accounting Firm. | |||
31.1 | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer. | |||
31.2 | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer. | |||
32.1 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer. | |||
32.2 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer. | |||
101.INS | XBRL Instance Document | |||
101.SCH | XBRL Taxonomy Extension Schema | |||
101.CAL | XBRL Taxonomy Calculation Linkbase | |||
101.DEF | XBRL Taxonomy Definition Linkbase | |||
101.LAB | XBRL Taxonomy Extension Label Linkbase | |||
101.PRE | XBRL Taxonomy Extension Presentation Linkbase | |||
* | Certain portions of this Exhibit have been omitted pursuant to a request for confidential treatment. The non-public information has been filed separately with the SEC pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended. | |||
Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Statements of Operations and Comprehensive Income for the years ended October 31, 2016, 2015 and 2014; (3) Consolidated Balance Sheets as of October 31, 2016 and 2015; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2016, 2015 and 2014; (5) Consolidated Statements of Changes in Equity for the years ended October 31, 2016, 2015 and 2014; and Notes to Consolidated Financial Statements. |
Date: | December 22, 2016 | |
PIEDMONT NATURAL GAS COMPANY, INC. | ||
(Registrant) | ||
By: | /s/ LYNN J. GOOD | |
Lynn J. Good | ||
Chief Executive Officer | ||
Signature | |||
(i) | /s/ LYNN J. GOOD | ||
Lynn J. Good | |||
Chief Executive Officer (Principal Executive Officer) | |||
(ii) | /s/ STEVEN K. YOUNG | ||
Steven K. Young | |||
Executive Vice President and Chief Financial Officer (Principal Financial Officer) | |||
(iii) | /s/ WILLIAM E. CURRENS JR. | ||
William E. Currens Jr. | |||
Chief Accounting Officer and Controller (Principal Accounting Officer) | |||
(iv) | Directors: | ||
/s/ LYNN J. GOOD | |||
Lynn J. Good | |||
/s/ FRANKLIN H. YOHO | |||
Franklin H. Yoho | |||
/s/ DHIAA M. JAMIL | |||
Dhiaa M. Jamil | |||
Date: December 22, 2016 |
Piedmont Natural Gas Company, Inc. | ||
Form 10-K | ||
For the Fiscal Year Ended October 31, 2016 | ||
Exhibits | ||
3.1 | Amended and Restated Articles of Incorporation of Piedmont Natural Gas Company, Inc., dated as of October 3, 2016 | |
12 | Computation of Ratio of Earnings to Fixed Charges | |
23.1 | Consent of Independent Registered Public Accounting Firm | |
31.1 | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer | |
31.2 | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer | |
32.1 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer | |
32.2 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer |
Exhibit 12 | ||||||||||||||||||||
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES | ||||||||||||||||||||
Computation of Ratio of Earnings to Fixed Charges | ||||||||||||||||||||
For Fiscal Years Ended October 31, 2012 through 2016 | ||||||||||||||||||||
(in millions except ratio amounts) | ||||||||||||||||||||
2016 | 2015 | 2014 | 2013 | 2012 | ||||||||||||||||
Earnings: | ||||||||||||||||||||
Pre-tax income from continuing operations | $ | 153.5 | $ | 191.9 | $ | 205.1 | $ | 193.1 | $ | 171.7 | ||||||||||
Distributed income of unconsolidated affiliates | 43.8 | 26.4 | 28.8 | 26.8 | 25.0 | |||||||||||||||
Fixed charges | 82.4 | 81.3 | 72.6 | 57.5 | 47.0 | |||||||||||||||
Total Adjusted Earnings | $ | 279.7 | $ | 299.6 | $ | 306.5 | $ | 277.4 | $ | 243.7 | ||||||||||
Fixed Charges: | ||||||||||||||||||||
Interest | $ | 79.4 | $ | 78.4 | $ | 69.9 | $ | 54.8 | $ | 43.9 | ||||||||||
Amortization of debt expense | 1.4 | 1.3 | 1.2 | 1.0 | 1.4 | |||||||||||||||
Amortization of loss - reacquired debt | 0.2 | 0.2 | 0.2 | 0.2 | 0.2 | |||||||||||||||
One-third of rental expense | 1.4 | 1.4 | 1.3 | 1.5 | 1.5 | |||||||||||||||
Total Fixed Charges | $ | 82.4 | $ | 81.3 | $ | 72.6 | $ | 57.5 | $ | 47.0 | ||||||||||
Ratio of Earnings to Fixed Charges | 3.40 | 3.68 | 4.22 | 4.82 | 5.19 |
1. | I have reviewed this Annual Report on Form 10-K of Piedmont Natural Gas Company, 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: |
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: | December 22, 2016 | ||
/s/ LYNN J. GOOD | |||
Lynn J. Good | |||
Chief Executive Officer |
1. | I have reviewed this Annual Report on Form 10-K of Piedmont Natural Gas Company, 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: |
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: | December 22, 2016 | ||
/s/ STEVEN K. YOUNG | |||
Steven K. Young | |||
Executive Vice President and Chief Financial Officer |
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ LYNN J. GOOD | ||
Lynn J. Good | ||
Chief Executive Officer | ||
December 22, 2016 |
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ STEVEN K. YOUNG | ||
Steven K. Young | ||
Executive Vice President and Chief Financial Officer | ||
December 22, 2016 |
Document And Entity Information - USD ($) |
12 Months Ended | ||
---|---|---|---|
Oct. 31, 2016 |
Oct. 03, 2016 |
Apr. 30, 2016 |
|
Document And Entity Information [Abstract] | |||
Entity Registrant Name | PIEDMONT NATURAL GAS CO INC | ||
Entity Central Index Key | 0000078460 | ||
Current Fiscal Year End Date | --10-31 | ||
Entity Filer Category | Non-accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Oct. 31, 2016 | ||
Document Fiscal Period Focus | FY | ||
Document Fiscal Year Focus | 2016 | ||
Amendment Flag | false | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Common Stock, Shares Outstanding | 0 | ||
Entity Public Float | $ 0 |
Consolidated Statements of Operations and Comprehensive Income (Parentheticals) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
|
Statement of Comprehensive Income [Abstract] | |||
Unrealized (loss) gain from hedging activities, tax | $ (2.5) | $ (1.0) | $ 0.2 |
Reclassification adjustment of realized loss (gain) from hedging activities of equity method investments included in net income, tax | $ 2.0 | $ 0.7 | $ (0.2) |
Consolidated Balance Sheets - USD ($) $ in Millions |
Oct. 31, 2016 |
Oct. 31, 2015 |
|||||
---|---|---|---|---|---|---|---|
Current Assets | |||||||
Cash and cash equivalents | $ 16.6 | $ 13.7 | |||||
Receivables (less allowance for doubtful accounts of $1.9 in 2016 and $1.6 in 2015) | 75.2 | 86.9 | |||||
Receivables from affiliated companies (1) (2) | [1],[2] | 7.0 | 0.2 | ||||
Inventory | 55.6 | 69.5 | |||||
Regulatory assets | 113.7 | 19.1 | |||||
Prepaids | 27.2 | 28.9 | |||||
Other | 12.0 | 12.8 | |||||
Total current assets | 307.3 | 231.1 | |||||
Investments and Other Assets | |||||||
Investments in equity method unconsolidated affiliates | 199.2 | 207.0 | |||||
Goodwill | 48.9 | 48.9 | |||||
Other | 10.9 | 53.1 | |||||
Total investments and other assets | 259.0 | 309.0 | |||||
Property, Plant and Equipment | |||||||
Cost | 6,079.1 | 5,601.3 | |||||
Accumulated depreciation and amortization | (1,329.5) | (1,252.9) | |||||
Net property, plant and equipment | 4,749.6 | 4,348.4 | |||||
Regulatory Assets and Deferred Debits | |||||||
Regulatory assets | 373.3 | 196.7 | |||||
Other | 1.8 | 1.1 | |||||
Total regulatory assets and deferred debits | 375.1 | 197.8 | |||||
Total Assets | 5,691.0 | 5,086.3 | |||||
Current Liabilities | |||||||
Accounts payable | 130.5 | 120.3 | |||||
Accounts payable to affiliated companies (1) (2) | [1],[2] | 8.7 | 2.5 | ||||
Notes payable and commercial paper | 145.0 | 340.0 | |||||
Taxes accrued | 68.4 | 30.3 | |||||
Interest accrued | 29.3 | 29.5 | |||||
Current maturities of long-term debt | 35.0 | 40.0 | |||||
Regulatory liabilities | 0.0 | 21.5 | |||||
Gas supply derivative liabilities, at fair value | 41.5 | 0.0 | |||||
Other | 61.7 | 59.3 | |||||
Total current liabilities | 520.1 | 643.4 | |||||
Long-Term Debt | 1,786.0 | 1,523.7 | |||||
Deferred Credits and Other Liabilities | |||||||
Deferred income taxes | 904.1 | 829.2 | |||||
Investment tax credits | 0.9 | 1.0 | |||||
Accrued pension and other post-retirement benefit costs | 23.4 | 15.1 | |||||
Asset retirement obligations | 14.1 | 19.7 | |||||
Regulatory liabilities | 617.0 | 590.3 | |||||
Other | 180.5 | 37.6 | |||||
Total deferred credits and other liabilities | 1,740.0 | 1,492.9 | |||||
Commitments and Contingencies | |||||||
Equity | |||||||
Common stock, no par value: 100 shares authorized and outstanding in 2016 and 200.0 million authorized and 80.9 million outstanding in 2015 | 859.8 | 721.4 | |||||
Retained earnings | 785.3 | 705.7 | |||||
Accumulated other comprehensive loss | (0.2) | (0.8) | |||||
Total equity | 1,644.9 | 1,426.3 | |||||
Total Liabilities and Equity | $ 5,691.0 | $ 5,086.3 | |||||
|
Consolidated Balance Sheets (Parentheticals) - USD ($) $ in Millions |
Oct. 31, 2016 |
Oct. 31, 2015 |
---|---|---|
Allowance for doubtful accounts | $ 1.9 | $ 1.6 |
Common stock par value | $ 0 | $ 0 |
Common stock shares authorized | 200,000,000 | |
Common stock shares outstanding | 80,900,000 | |
Successor | ||
Common stock shares authorized | 100 | |
Common stock shares outstanding | 100 |
Consolidated Statements of Cash Flows - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
|
CASH FLOWS FROM OPERATING ACTIVITES | |||
Net income | $ 193.2 | $ 137.0 | $ 143.8 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation and amortization | 148.3 | 140.2 | 129.3 |
Provision for doubtful accounts | 4.9 | 5.1 | 7.0 |
Impairment charges | 0.0 | 0.0 | 2.0 |
Net gain on sale of property | 0.0 | 0.0 | (0.8) |
Net gain on sale of interests in unconsolidated affiliates, net of tax | (80.9) | 0.0 | 0.0 |
Deferred income taxes, net | 74.2 | 73.0 | 87.2 |
Equity in earnings of unconsolidated affiliates | (28.6) | (34.5) | (32.8) |
Distributions of earnings from unconsolidated affiliates | 25.8 | 24.9 | 24.8 |
Accrued/deferred postretirement benefit costs | 12.4 | 2.2 | 5.9 |
Contributions to benefit plans | (14.0) | (12.7) | (22.5) |
Settlement of legal asset retirement obligations | (6.4) | (5.6) | (3.5) |
Receivables, net | 6.9 | (2.6) | 9.7 |
Receivables from affiliated companies | (7.0) | ||
Inventory | 13.9 | 16.3 | (10.1) |
Regulatory assets | (291.6) | (24.0) | 21.2 |
Other current assets | 2.4 | 38.4 | (12.0) |
Accounts payable | 6.2 | (5.1) | (4.7) |
Accounts payable to affiliated companies | 6.3 | ||
Taxes accrued | (13.7) | 3.8 | 3.6 |
Gas supply derivatives, at fair value | 187.9 | 0.0 | 0.0 |
Other current liabilities | (13.5) | (20.5) | 51.1 |
Other assets | 58.2 | 7.4 | 20.7 |
Other liabilities | 23.5 | 28.3 | 10.7 |
Net cash provided by operating activities | 308.4 | 371.6 | 430.6 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Capital expenditures | (521.8) | (443.7) | (460.5) |
Allowance for borrowed funds used during construction | (12.3) | (11.1) | (16.4) |
Investment expenditures | (47.4) | (29.7) | (37.6) |
Distributions of capital from unconsolidated affiliates | 18.0 | 1.5 | 3.9 |
Net proceeds from the sales of interests in unconsolidated affiliates and other assets | 174.5 | 0.7 | 1.9 |
Other | 15.3 | 3.9 | 4.2 |
Net cash used in investing activities | (373.7) | (478.4) | (504.5) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Issuance of long-term debt | 299.6 | 149.9 | 249.6 |
Issuance of common stock related to employee benefit plans | 17.0 | 27.0 | 25.6 |
Issuance of common stock, net of expense | 104.6 | 53.7 | 47.3 |
Redemptions of long-term debt | (40.0) | 0.0 | (100.0) |
Expenses related to issuance of debt | (4.3) | (1.3) | (2.9) |
Notes payable and commercial paper | (195.0) | (15.0) | (45.0) |
Dividends paid | (113.7) | (103.4) | (99.2) |
Net cash provided by financing activities | 68.2 | 110.9 | 75.4 |
Net increase in cash and cash equivalents | 2.9 | 4.1 | 1.5 |
Cash and cash equivalents at beginning of period | 13.7 | 9.6 | 8.1 |
Cash and cash equivalents at end of period | 16.6 | 13.7 | 9.6 |
Supplemental Disclosures: | |||
Cash paid for interest, net of amount capitalized | 81.4 | 71.5 | 64.3 |
Cash (received from) paid for income taxes | (24.5) | 3.2 | 10.8 |
Significant non-cash transactions: | |||
Accrued capital expenditures | $ 62.8 | $ 58.9 | $ 38.9 |
Consolidated Statements of Changes in Equity - USD ($) $ in Millions |
Total |
Common Stock |
Retained Earnings |
Accumulated Other Comprehensive Income (Loss) |
---|---|---|---|---|
Stockholders' Equity, beginning balance at Oct. 31, 2013 | $ 1,188.6 | $ 561.6 | $ 627.2 | $ (0.2) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Net income | 143.8 | 143.8 | ||
Other comprehensive income (loss), net of tax | 0.0 | 0.0 | ||
Common stock issuances, including dividend reinvestment and employee benefits | 75.2 | 75.2 | ||
Expenses from Issuance of Common Stock | 0.0 | 0.0 | ||
Tax Benefit from Dividends Paid on ESOP Shares | 0.2 | 0.2 | ||
Common stock dividends | (99.2) | (99.2) | ||
Stockholders' Equity, ending balance at Oct. 31, 2014 | 1,308.6 | 636.8 | 672.0 | (0.2) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Net income | 137.0 | 137.0 | ||
Other comprehensive income (loss), net of tax | (0.6) | (0.6) | ||
Common stock issuances, including dividend reinvestment and employee benefits | 85.0 | 85.0 | ||
Expenses from Issuance of Common Stock | (0.4) | (0.4) | ||
Tax Benefit from Dividends Paid on ESOP Shares | 0.1 | 0.1 | ||
Common stock dividends | (103.4) | (103.4) | ||
Stockholders' Equity, ending balance at Oct. 31, 2015 | 1,426.3 | 721.4 | 705.7 | (0.8) |
Income Loss Hedging Activities Of Equity Method Investments [Abstract] | ||||
Hedging activities of equity method investments | (0.8) | |||
Net income | 193.2 | 193.2 | ||
Other comprehensive income (loss), net of tax | 0.6 | 0.6 | ||
Common stock issuances, including dividend reinvestment and employee benefits | 138.5 | 138.5 | ||
Expenses from Issuance of Common Stock | (0.1) | (0.1) | ||
Tax Benefit from Dividends Paid on ESOP Shares | 0.1 | 0.1 | ||
Common stock dividends | (113.7) | (113.7) | ||
Stockholders' Equity, ending balance at Oct. 31, 2016 | 1,644.9 | $ 859.8 | $ 785.3 | $ (0.2) |
Income Loss Hedging Activities Of Equity Method Investments [Abstract] | ||||
Hedging activities of equity method investments | $ (0.2) |
Summary of Significant Accounting Policies |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Nature of Operations and Basis of Consolidation Piedmont Natural Gas Company, Inc. is an energy services company primarily engaged in the distribution of natural gas to residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee. We are invested in joint venture, energy-related businesses, including regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation. With the October 3, 2016 sale of our 15% membership interest in SouthStar Energy Services, LLC (SouthStar), we are no longer invested in the unregulated retail natural gas marketing business; see Note 11 for further information on this sale. Our utility operations are regulated by three state regulatory commissions; see Note 3 for further information on regulatory matters. Unless the context requires otherwise, references to "we," "us," "our," "the Company" or "Piedmont" means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries. The Consolidated Financial Statements of Piedmont have been prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) and under the rules of the Securities and Exchange Commission (SEC). The Consolidated Financial Statements reflect the accounts of Piedmont and its wholly owned subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation. Investments in non-utility activities, or joint ventures, are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. Our ownership interest in each entity is recorded in "Investments in equity method unconsolidated affiliates" within "Investments and Other Assets" on the Consolidated Balance Sheets at cost plus post-acquisition contributions and earnings based on our share in each of the joint ventures less any distributions received from the joint venture, and if applicable, less any impairment in value of the investment. Earnings or losses from equity method investments are recorded in "Equity in earnings of unconsolidated affiliates" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. Gain from the sale of membership interests in our joint ventures are recorded in "Gain on sale of unconsolidated affiliates" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. See Note 11 for further information on investments in unconsolidated affiliates and related party transactions with these affiliates. On October 24, 2015, we entered into an Agreement and Plan of Merger (Merger Agreement) with Duke Energy Corporation (Duke Energy). On October 3, 2016, the merger was consummated between Duke Energy and Piedmont and Forest Subsidiary, Inc. (Merger Sub), a new wholly owned subsidiary of Duke Energy. The Merger Agreement provided for the merger of the Merger Sub with and into Piedmont, with Piedmont surviving as a wholly owned subsidiary of Duke Energy (the Acquisition). The Acquisition was recorded using the acquisition method of accounting. Under SEC regulations, Duke Energy elected to not apply push down accounting to the stand alone Piedmont financial statements. These adjustments will be recorded by Duke Energy. See Note 2 for further information. The information presented in this Form 10-K for the fiscal years ended October 31, 2016, 2015 and 2014 are presented solely for the registrant Piedmont on a stand-alone basis. The Consolidated Financial Statements for the 2015 and 2014 periods have been reclassified to conform to Duke Energy's financial statement format. See Note 16 for further information on the reclassification of our Consolidated Financial Statements. Also, Duke Energy and Piedmont performed a comparative analysis of accounting policies with no significant differences except for actuarial assumptions for pension and other postretirement benefit plans. See Note 8 for the discussion of the change of the discount rate in actuarial assumptions. Use of Estimates In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets, liabilities, revenues and expenses and the related disclosures, using historical experience and other assumptions that we believe are reasonable at the time. Our estimates may involve complex situations requiring a high degree of judgment in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities as of the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis. Rate-Regulated Basis of Accounting Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by the regulatory commissions in the states in which we operate. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods. Generally, regulatory assets are amortized to expense and regulatory liabilities are amortized to income over the period authorized by our regulators. Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commissions during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that would result in an adjustment to net income or accumulated other comprehensive income (OCI). Our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment of similar costs in our jurisdictions, recent rate orders to other regulated entities and the status of any pending or potential legislation that would affect the regulatory environment. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. Based on our assessment that reflects the current political and regulatory climate at the state and federal levels, we believe that all of our regulatory assets are probable of recovery in current rates or in future rate proceedings. Net Property, Plant and Equipment Utility plant is stated at original cost, including direct labor and materials, contractor costs, allocable overhead charges, such as engineering, supervision, corporate office salaries and expenses, pensions and insurance, and an allowance for funds used during construction (AFUDC) that is calculated under a formula prescribed by our state regulators. We apply the group method of accounting, where the costs of homogeneous assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. Major expenditures that last longer than a year and improve or lengthen the expected useful life of the overall property from original expectations that are recoverable in regulatory rate base are capitalized while expenditures not meeting these criteria are expensed as incurred. The costs of property retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery or refund through future rates. On certain assets, like land, that are nondepreciable, we record a gain or loss upon the disposal of the property that is recorded in "Other expense, net" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. The classification of net property, plant and equipment for the years ended October 31, 2016 and 2015 is presented below.
Contributions in aid of construction represent nonrefundable donations or contributions received from third-parties for partial or full reimbursement for construction expenditures for utility plant in service. AFUDC represents the estimated costs of funds from both debt and equity sources used to finance the construction of major projects and is capitalized for ratemaking purposes when the completed projects are placed in service. The portion of AFUDC attributable to borrowed funds reduces "Interest Expense" on the Consolidated Statements of Operations and Comprehensive Income. Any portion of AFUDC attributable to equity funds would be included in "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. For the three years ended October 31, 2016, 2015 and 2014, all of our AFUDC was attributable to borrowed funds. AFUDC for the years ended October 31, 2016, 2015 and 2014 is presented below.
In accordance with utility accounting practice, we classify costs incurred for utility plant that is not in service to be "Plant held for future use" in "Cost" within "Property, Plant and Equipment" on the Consolidated Balance Sheets. Since March 2009 when construction was suspended, we classified real estate and development costs associated with a liquefied natural gas (LNG) peak storage facility in the eastern part of North Carolina as "Plant held for future use." As of 2012, approximately $3.2 million of the "Plant held for future use" related to land costs and approximately $3.5 million related to non-real estate costs. In May 2013, we filed a general rate application with the North Carolina Utilities Commission (NCUC) requesting rate recovery of the non-real estate costs. Under the settlement of the 2013 North Carolina general rate proceeding approved by the NCUC in December 2013, we agreed to the amortization and collection of $1.2 million of non-real estate costs that are recorded as a regulatory asset with amortization over 38 months beginning January 1, 2014 through February 2017. During fiscal 2016, we reclassified $4.6 million of project costs recorded as "Construction work in progress" to "Plant held for future use." We intend to resume the project when future economic conditions become more favorable. We compute depreciation expense using the straight-line method over periods ranging from 5 to 80 years. The composite weighted average depreciation rates were 2.44% for 2016, 2.48% for 2015 and 2.54% for 2014. Depreciation rates for utility plant are approved by our regulatory commissions. In North Carolina, we are required to conduct a depreciation study every five years and file the results with the regulatory commission. No such requirement exists in South Carolina or Tennessee; however, we periodically propose revised rates in those states based on depreciation studies. Our last system-wide depreciation study based on fiscal year 2009 data was completed in 2011 and filed with the appropriate regulatory commission in all jurisdictions. New depreciation rates were approved effective November 1, 2011 for South Carolina, March 1, 2012 for Tennessee and January 1, 2014 for North Carolina. As authorized by our regulatory commissions, the estimated costs of removal on certain regulated properties are collected through depreciation expense through rates with a corresponding credit to accumulated depreciation. Our approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal for certain regulated properties. Therefore, through depreciation expense, we collect and record estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate. Because the estimated removal costs are a non-legal obligation, we account for them as a regulatory liability and present the accumulated removal costs in "Regulatory Liabilities;" see Note 3 for the amount of these removal costs in "Rate-Regulated Basis of Accounting." See "Asset Retirement Obligations" in this Note 1 for further discussion of this regulatory liability. Cash and Cash Equivalents We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents. We have no material restrictions on our cash balances as of October 31, 2016 and 2015. Receivables and Allowance for Doubtful Accounts Receivables consist of natural gas sales and transportation services, unbilled revenues, and other miscellaneous receivables, including merchandise and service work, construction related receivables and other miscellaneous receivables. We bill customers monthly with payment due within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, based on the aging of receivables and our historical and projected charge-off activity. Our estimate of recoverability could differ from actual experience based on customer credit issues, the level of natural gas prices and general economic conditions. We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the NCUC, the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA), we are authorized to recover actual uncollected gas costs through the purchased gas adjustment (PGA). As a result, only the portion of accounts written off relating to the non-gas costs, or regulated margin, is included in base rates and, accordingly, only this portion is included in the provision for uncollectibles expense. Non-regulated merchandise and service work receivables due beyond one year are included in "Other" within "Investments and Other Assets" on the Consolidated Balance Sheets. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 2016 and 2015, our receivables and allowance for doubtful accounts consisted of the following.
A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2016, 2015 and 2014 is presented below.
See Note 6 for further information on credit risk in "Credit and Counterparty Risk." Inventory We maintain gas inventories on the basis of average cost. Injections into storage are priced at the purchase cost at the time of injection, and withdrawals from storage are priced at the weighted average purchase price in storage. The cost of gas in storage is recoverable under rate schedules approved by state regulatory commissions. Inventory activity is subject to regulatory review on an annual basis in gas cost recovery proceedings. We enter into service contracts, or asset management arrangements (AMAs), with counterparties to efficiently manage portions of our gas supply, transportation capacity and storage capacity to serve our customers. These AMAs are structured in compliance with Federal Energy Regulatory Commission (FERC) Order 712. Generally, under an AMA, we receive a fixed monthly payment which is set at inception of the arrangement, and in return, we release the transportation capacity and storage capacity to the asset manager and may assign the gas supply and/or storage inventory for the term of the agreement. The inventory is assigned at no cost, and the same quantities are required to be returned at the expiration of the agreements. One agreement allows us to call on inventory during the summer months to satisfy operational requirements, if needed. The inventory that is assigned to the asset manager is available for our use during the winter heating season, November through March. We account for these amounts on the Consolidated Balance Sheets as a current asset in "Inventory." From the period of April through October, the inventory that is not available for our use is reclassified on the Consolidated Balance Sheets in "Prepaids," and the inventory that is available for our use remains in "Inventory." As of October 31, 2016 and 2015, such counterparties held natural gas storage assets as recorded in "Prepaids," with a value of $21.3 million and $24.8 million, respectively, through such asset management relationships. Under the terms of the agreements, we receive asset management fees, which are recorded as secondary market transactions and shared between our utility customers and us. The AMAs expire at various times through January 31, 2026. See Note 3 for further information on the revenue sharing of secondary market transactions. Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost. Fair Value Measurements We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value in the Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and purchased call option derivative assets and liabilities, if any, that are held for our utility operations. The carrying values of receivables, short-term debt, accounts payable, accrued interest and other current assets and liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our nonfinancial assets and liabilities include our qualified pension and postretirement plan assets and liabilities that are recorded at fair value in the Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans. As discussed below, beginning with the year ended October 31, 2016, we have certain forward gas supply derivative contracts that are nonfinancial assets and liabilities requiring fair value treatment. Fair value is 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, or exit date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for fair value measurements and endeavor to utilize the best available information for the specific instrument, location or commodity being valued. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value of our financial assets and liabilities are subject to potentially significant volatility based on changes in market prices, the maturity and settlement of our contracts, and subsequent newly originated transactions, each of which directly affects the estimated fair value of our financial instruments. We are able to classify fair value balances based on the observance of those inputs at the lowest level that is significant to the fair value measurement, in its entirety, in the following fair value hierarchy levels as set forth in the fair value guidance. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets have sufficient frequency and volume to provide pricing information for the asset or liability on an ongoing basis. Our Level 1 items consist of financial instruments of exchange-traded derivatives, investments in marketable securities and benefit plan assets held in registered investment companies and individual stocks. Level 2 inputs are inputs other than quoted prices in active markets included in Level 1 and are either directly or indirectly corroborated or observable as of the reporting date, generally using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Our Level 2 items include non-exchange-traded derivative instruments, such as some qualified pension plan assets held in common trust funds, collateralized mortgage obligations, swaps, futures, currency forwards, corporate bonds and government and agency obligations that are valued at the closing price reported in the active market for similar assets in which the individual securities are traded or based on yields currently available on comparable securities of issuers with similar credit ratings or based on the most recent available financial information for the respective funds and securities. For some qualified pension plan assets, the determination of Level 2 assets was completed through a process of reviewing each individual security while consulting research and other metrics provided by investment managers, including a pricing matrix detailing the pricing source and security type, annual audited financial statements and a review of valuation policies and procedures used by the investment managers as well as our investment advisor. Level 3 inputs include significant pricing inputs that are generally less observable from objective sources and may be used with internally developed methodologies that result in management’s best estimate of fair value. Our Level 3 inputs include cost estimates for removal (contract fees or manpower/equipment estimates), inflation factors, risk premiums, the remaining life of long-lived assets, the credit adjusted risk free rate to discount for the time value of money over an appropriate time span, and the most recent available financial information of an investment in a diversified private equity fund of funds for some of our qualified pension plan assets. Beginning with the year ended October 31, 2016, we have long-dated, fixed quantity natural gas supply contracts for our regulated utility operations which are accounted for as derivatives. We have classified these contracts as Level 3 in the fair value hierarchy, as the inputs are generally unobservable due to the tenure of the contracts and the absence of market quoted observable data. In the absence of actively quoted prices or if we believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In determining the fair value, we use a discounted cash flow technique to calculate our valuation. We incorporate the following inputs and assumptions in our model: contract volume, forward market prices from third-party pricing services with an evaluation of pricing information on active and inactive markets, price correlations, pricing projections, time value, fuel assumptions and credit adjusted risk free rate of return. See Note 6 for further information on our fair value measurements of our derivatives and marketable securities. See Note 8 for further information for the fair value measurements of our benefit plan assets. In determining whether to categorize the fair value measurement of an instrument as Level 2 or Level 3, we must use judgment to assess whether we have the ability as of the measurement date to redeem an investment at its net asset value per share (NAV) in the near term. We consider when we might have the ability to redeem the investment by reviewing contractual restrictions in effect as of the investment date as well as any potential restrictions that the investee may impose. Regarding our benefit plans’ investments, "near term" is the ability to redeem an investment in no more than 180 days. Transfers between different levels of the fair value hierarchy may occur based on the level of observable inputs used to value the instruments for the period. These transfers represent existing assets or liabilities previously categorized as Level 1 or Level 2 for which the inputs to the estimate became less observable or assets and liabilities previously classified as Level 2 or Level 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the actual date of the event or change in circumstances causing the transfer. Goodwill, Equity Method Investments and Long-Lived Assets Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment, or more frequently if impairment indicators arise during the year. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. When we test goodwill, we use a fair value approach at a reporting unit level, generally equivalent to our operating segment as discussed in Note 13. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. All of our goodwill is attributable to our regulated utility operations. Our annual goodwill impairment assessment as of October 31, 2016 was performed using a qualitative approach. As part of our qualitative assessment, we considered macroeconomic conditions such as general deterioration in economic condition, limitations on accessing capital and other developments in equity and credit markets. We evaluated industry and market considerations for any deterioration in the environment in which we operate, the increased competitive environment, a decline (both absolute and relative to our peers) in market-dependent multiples or metrics, any changes in the market for our products or services, and regulatory and political development. We assessed our overall financial performance and considered cost factors, such as increases in utility construction expenditures, labor or other costs, that would have a negative effect on earnings. We determined the relevance of any entity-specific events or events affecting our regulated utility operations which would have a negative effect on the carrying value of the reporting unit. Based on our qualitative assessment, we have determined that it is not necessary to perform a quantitative goodwill impairment test of our 2016 goodwill. The annual goodwill impairment assessments performed have indicated that it is more likely than not that the fair value of the reporting unit is substantially in excess of carrying value and not at risk of failing step one of the quantitative goodwill impairment test. No impairment was recognized during the years ended October 31, 2016, 2015 and 2014. On a quarterly basis, or when events or changes in circumstances indicate, we evaluate our investments in our unconsolidated affiliates and long-lived assets for impairment. Each equity method investment is recorded at cost plus its post-acquisition contributions and earnings based on our ownership share less any distributions as received from the joint venture investment, and if applicable, less any impairment in value of the investment. Given the nature of our equity method investment, our assessment may include a discounted cash flow income approach, including consideration of qualitative factors or events or circumstances which could affect the fair value. To the extent the analysis indicates a decline in fair value, we consider both the severity and duration of any decline in our evaluation as to whether an other-than-temporary impairment (OTTI) has occurred. Our key inputs involve significant management judgments and estimates, including projections of the entity’s cash flows, selection of a discount rate and probability weighting of potential outcomes of any legal or regulatory proceedings or other events affecting the investment. See Note 11 for further information on our OTTI assessment of one of our equity method investments. In April 2014, we recorded a $2.0 million write-off for an investment that was accounted for on the cost basis. The write-off was recorded to "Other expense, net" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. There were no events or circumstances during the years ended October 31, 2016 and 2015 that resulted in any impairment charges. Marketable Securities We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in rabbi trusts established for our deferred compensation plans. See Note 8 for further information on the deferred compensation plans. We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value on the Consolidated Balance Sheets in "Other" within "Investments and Other Assets" with any gains or losses recognized currently in earnings. We do not intend to engage in active trading of the securities, and participants in the deferred compensation plans may redirect their deemed investments at any time. The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of October 31, 2016 and 2015 is as follows.
Issuances and Repurchases of Common Stock As discussed in Note 4, prior to the consummation of the Acquisition on October 3, 2016, from time to time, we have repurchased shares on the open market and such shares were then canceled and became authorized but unissued shares. It was our policy to issue new shares for share-based employee awards and shareholder and employee investment plans. In anticipation of the Acquisition by Duke Energy, we suspended new investments in our employee plans effective July 31, 2016. We present net shares issued under these awards and plans in "Common stock issuances, including dividend reinvestment and employee benefits" in the Consolidated Statements of Changes in Equity. Upon consummation of the Acquisition, our common stock was delisted from the New York Stock Exchange (NYSE). Asset Retirement Obligations The accounting guidance for asset retirement obligations (AROs) addresses the financial accounting and reporting for AROs associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the assets. The accounting guidance requires the recognition of the fair value of a liability for AROs in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that conditional AROs exist for our underground mains and services. We have costs of removal that are non-legal obligations as defined by the accounting guidance. The costs of removal are a component of our depreciation rates in accordance with long-standing regulatory treatment. Because these estimated removal costs meet the requirements of rate-regulated accounting guidance, we have accounted for these non-legal AROs in "Regulatory Liabilities" as presented in Note 3. In the rate setting process, the liability for non-legal costs of removal is treated as a reduction to the net rate base upon which our regulated utility operations have the opportunity to earn its allowed rate of return. See "Net Property, Plant and Equipment" in this Note 1, for further discussion of these costs of removal as a component of depreciation. We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated. The NCUC, the PSCSC and the TRA have approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs; therefore, accretion is not reflected in the Consolidated Statements of Operations and Comprehensive Income as the regulatory treatment provides for deferral of the accretion as a regulatory asset with a corresponding deferral of the accretion recorded as a regulatory liability. AROs are capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the regulatory liability. In periods subsequent to the initial measurement, any changes in the liability resulting from the passage of time (accretion) or due to the revisions of either timing or the amount of the originally estimated cash flows to settle conditional AROs must be recognized. The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate, which ranged from 4.62% to 5.89% with a time value weighted average of 5.69% for the twelve months ended October 31, 2016. We have recorded a liability on our distribution and transmission mains and services. The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 2016 and 2015 are presented below.
A reconciliation of the changes in conditional AROs for the year ended October 31, 2016 and 2015 is presented below.
Unamortized Debt Expense Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, accountant fees, registration fees and rating agency fees, related to issuing long-term debt and the short-term syndicated revolving credit facility. We amortize long-term debt expense on a straight-line basis, which approximates the effective interest method, over the life of the related debt with lives ranging from 5 to 30 years. Long-term debt is presented net of unamortized debt expenses in the accompanying Consolidated Balance Sheets. For further information on the effects on regulatory assets and our long-term debt, see Note 3 and Note 5, respectively. We amortize bank debt expense over the life of the syndicated revolving credit facility, which is 5 years. Should we reacquire long-term debt prior to its term date and simultaneously issue new debt, we defer the gain or loss resulting from the transaction, essentially the remaining unamortized debt expense, and amortize it over the life of the new debt in accordance with established regulatory practice. Where the refunding of the debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt as a regulatory asset or liability and amortize it over the remaining life of the redeemed debt in accordance with established regulatory practice. For income tax purposes, any gain or loss would be recognized as incurred. Revenue Recognition and Unbilled Revenue We record revenues when services are provided to our distribution service customers. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to jurisdictional customers may not be changed without approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA provisions. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers on an annual basis independent of weather and consumption patterns. The margin decoupling mechanism provides for semi-annual rate adjustments to refund any over-collection of margin or to recover any under-collection of margin. In South Carolina, a rate stabilization adjustment (RSA) mechanism achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the RSA mechanism, we reset our rates in South Carolina based on updated costs and revenues on an annual basis. In South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter heating season November through March, and in Tennessee, the months of October through April. The WNA mechanisms are designed to partially offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter heating season. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the WNA factors. In all states, the gas cost portion of our costs is recoverable through PGA procedures and is not affected by the margin decoupling mechanism or the WNA mechanism. We have integrity management riders (IMRs) in our tariffs in North Carolina, effective February 1, 2014, and in Tennessee, effective January 1, 2014, related to our ongoing system integrity programs. These IMRs provide for rate adjustments to allow us to recover and earn on those investments without the necessity of filing general rate cases. The North Carolina IMR was initially approved in December 2013 in the settlement of our 2013 general rate case and subsequently revised in November 2015. Under the revised North Carolina IMR tariff, we make filings semi-annually each October 31 and April 30 for certain costs closed to plant through September and March, respectively, with revised rates effective the following December 1 and June 1, respectively. Under the Tennessee IMR, we file to adjust rates to be effective each January 1 based on capital expenditures related to mandated safety and integrity programs that were incurred by the previous October 31. See Note 3 for further discussion of the IMRs. Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanisms, as applicable. As of October 31, 2016 and 2015, unbilled revenues of $13.4 million and $17.4 million, respectively, are included within "Receivables" on the Consolidated Balance Sheets. Secondary market revenues associated with the commodity are recognized when the physical sales are delivered based on contract or market prices. Asset management fees for storage and transportation remitted on a monthly basis are recognized as earned given the monthly capacity costs associated with the contracts involved. Asset management fees remitted in a lump sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. See Note 3 regarding revenue sharing of secondary market transactions. Utility sales, transportation and secondary market revenues are reported net of excise taxes, sales taxes and franchise fees. See "Taxes" in this Note 1 for further information regarding taxes. Non-regulated merchandise and service work includes the sale, installation and/or maintenance of natural gas appliances and gas piping beyond the meter. Revenue is recognized when the sale is made or the work is performed. If the customer is eligible for and elects financing through us, the finance fee income is recognized on a monthly basis based on principal, rate and term. Cost of Natural Gas and Deferred Purchased Gas Adjustments We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms as set by the regulatory commissions in states in which we operate. Rate schedules for utility sales and transportation customers include PGA provisions that provide for the recovery of prudently incurred gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. We charge our secondary market customers for natural gas based on negotiated contract terms. Under PGA provisions, charges to cost of gas are based on the amount recoverable under approved rate schedules. Within our cost of natural gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives. By jurisdiction, differences between gas costs incurred and gas costs billed to customers, such that no operating regulated margin is recognized related to these costs, are deferred and included in "Amounts due from customers" in "Current Regulatory Assets" or "Amounts due to customers" in "Current Regulatory Liabilities" as presented in Note 3 in "Rate-Regulated Basis of Accounting." We review gas costs and deferral activity periodically, including deferrals under the margin decoupling and WNA mechanisms, and with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period. Taxes We have two categories of income taxes in the Consolidated Statements of Operations and Comprehensive Income: current and deferred. Current income tax expense consists of federal and state income taxes less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year. Deferred taxes are primarily attributable to utility plant, deferred gas costs, revenues and cost of natural gas, equity method investments, benefit of loss carryforwards and employee benefits and compensation. The determination of our provision for income taxes requires judgment, the use of estimates and the interpretation and application of complex tax laws. Judgment is required in assessing the timing and amounts of deductible and taxable items. Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred in accordance with rate-regulated accounting provisions, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders. Deferred investment tax credits, including energy credits, associated with our utility operations are presented in the Consolidated Balance Sheets. We amortize these deferred investment and energy tax credits to income over the estimated useful lives of the property to which the credits relate. We recognize accrued interest and penalties, if any, related to uncertain tax positions as operating expenses in the Consolidated Statements of Operations and Comprehensive Income. This is consistent with the recognition of these items in prior reporting periods. Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions. All other taxes other than income taxes are recorded within "Property and other taxes" on the Consolidated Statements of Operations and Comprehensive Income. Property and other taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use and other miscellaneous taxes. Consolidated Statements of Cash Flows With respect to cash, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows. Accounting Standards Update (ASU) We early adopted ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes in our first fiscal quarter 2016. The core principle of this revised accounting guidance is that all deferred tax assets and liabilities should be classified as noncurrent. Due to the adoption of the new accounting guidance, the balance sheet classification of deferred tax assets and liabilities were retrospectively classified as noncurrent. See Note 16 for the effect of the reclassification of deferred income taxes on the presentation on our Consolidated Balance Sheets. See Note 10 for information related to the presentation of deferred tax assets and liabilities. We prospectively adopted ASU 2015-05 Intangibles - Goodwill and Other (Topic 350) Internal-Use Software: Customer's Accounting for Fees Paid in a Cloud Computing Arrangement in our fourth fiscal quarter 2016. The core principle of this revised accounting guidance is determining the accounting for internal-use software for cloud computing arrangements containing a software license. The adoption of this guidance had no impact on our financial position, results of operations or cash flows. Recently Issued Accounting Guidance
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Acquisition by Duke Energy Corporation |
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Acquisition by Duke Energy Corporation | Acquisition by Duke Energy Corporation On October 3, 2016, the Acquisition of Piedmont by Duke Energy was consummated. Under the terms of the Merger Agreement, each share of Piedmont common stock issued and outstanding immediately prior to the closing (other than shares owned by Duke Energy or its wholly owned subsidiaries) was converted automatically into the right to receive $60 in cash per share, without interest, less any applicable withholding taxes. Each share of the Merger Sub's issued and outstanding stock was converted into one share of no par value common stock for a total of 100 shares owned by Duke Energy. As a result of the merger, the legacy Piedmont common stock outstanding was canceled, and Piedmont's common stock was delisted from the NYSE. Acquisition-related Regulatory Matters In January 2016, we and Duke Energy filed a joint application with the NCUC seeking regulatory approval of the Acquisition. Subsequently, we, Duke Energy and the NCUC Public Staff reached an agreement of stipulation and settlement setting forth stipulations and conditions for approval of the proposed Acquisition, which was originally filed with the NCUC in June 2016. Among the stipulations contained in the agreement are:
A hearing was held on July 18 and 19, 2016. In September 2016, the NCUC approved the Acquisition pursuant to the terms of the stipulation and settlement agreement. In October 2016, we reduced customers' bills by $4.7 million as a result of the one-time bill credit with the remainder to be reflected on November bills. Also in January 2016, we and Duke Energy discussed the Acquisition of Piedmont by Duke Energy with the PSCSC pursuant to its procedures for an allowable ex-parte communication briefing in accordance with state statute. The PSCSC's approval of the Acquisition was not required. In January 2016, we and Duke Energy filed a joint application with the TRA seeking approval to transfer Piedmont's Tennessee operating license effective at the closing of the Acquisition pursuant to state statute due to the change in control. In March 2016, the TRA approved the transfer contingent upon NCUC approval of the Acquisition. Costs to Achieve the Acquisition The following table summarizes pre-tax acquisition consummation costs, integration and other related costs (collectively referred to as costs to achieve) that we recorded in connection with the Acquisition and are included in "Operations, maintenance and other" within "Operating Expenses" in the Consolidated Statements of Operations and Comprehensive Income for the years ended October 31, 2016 and 2015.
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Regulatory Matters |
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Public Utilities, Rate Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters | Regulatory Matters Rate-Regulated Basis of Accounting Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2016 and 2015 are as follows.
As of October 31, 2016, we have $14.1 million of AROs and $344.9 million of other regulatory assets on which we do not earn a return. Included in deferred pension and other retirement costs are amounts related to pension funding for our Tennessee jurisdiction. The recovery of these amounts is authorized by the TRA on a deferred cash basis. Regulatory Oversight and Rate and Regulatory Actions Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt securities. The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a gas supply incentive program which compares our actual costs to market pricing benchmarks. As part of this jurisdictional oversight, all three regulatory commissions address our gas supply hedging activities. Additionally, all three regulatory commissions allow for recovery of uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or regulated margin, portion of uncollectibles is included in base rates and uncollectibles expense. See Note 2 for further information on our regulatory filings and hearings related to the Acquisition. North Carolina The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200.0 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding Eastern North Carolina Natural Gas Company (EasternNC) an exclusive franchise to provide natural gas service to 14 counties in the eastern-most part of North Carolina that had not been able to obtain gas service because of the relatively small population of those counties and the resulting economic infeasibility of providing service and granted $38.7 million in state bond funding. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of $188.3 million. With the 2003 acquisition and subsequent merger of EasternNC into our regulated utility operations, we are required to provide an accounting of the operational feasibility of this area to the NCUC every two years. Should this operational area become economically feasible and generate a profit, which we believe is unlikely, we would begin to repay the state bond funding. The NCUC had allowed EasternNC to defer its operation and maintenance (O&M) expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with the deferred amounts accruing interest per annum. In December 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred O&M expenses of $9.0 million as of October 31, 2008 was to be amortized over a twelve year period beginning November 1, 2008, with interest accruing at 7.84% per annum. Under the settlement of the 2013 general rate proceeding, the unamortized balance of the EasternNC deferred O&M expenses was $6.3 million as of December 31, 2013. This balance is accruing interest at a rate of 6.55% per annum with amortization beginning January 1, 2014 over an 82-month period ending October 31, 2020. As of October 31, 2016 and 2015, we had unamortized balances, including accrued interest, of $4.0 million and $4.8 million, respectively. We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and certain regulations of the United States Department of Transportation. The NCUC approved deferral treatment of the O&M costs applicable to certain incremental pipeline integrity external expenditures beginning November 1, 2004. The approved balance for recovery of actual pipeline integrity management O&M costs incurred between July 1, 2008 through August 31, 2013 as established in the settlement of the 2013 general rate proceeding was $17.3 million to be amortized over a five-year period from January 1, 2014 through December 31, 2018. As of October 31, 2016 and 2015, we had unamortized regulatory asset balances for deferred pipeline integrity expenses of $35.9 million and $33.3 million, respectively. The existing regulatory asset treatment for ongoing pipeline integrity management costs is expected to continue until another recovery mechanism is established in a future rate proceeding. As approved in the settlement of the 2013 NCUC general rate proceeding, certain capital expenditures that are incurred to comply with federal pipeline safety and integrity requirements are separately tracked and recovered on an annual basis through an IMR, as revised by a subsequent settlement approved by the NCUC in November 2015. The settlement of the 2013 NCUC general rate proceeding also approved recovery of $6.3 million of deferred North Carolina environmental costs over a five-year period from January 2014 through December 2018. In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Our gas costs have never been disallowed on the basis of prudence. In November 2014, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2014. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery. In November 2015, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2015. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery. In November 2016, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2016. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery. Our gas cost hedging plan for North Carolina is designed to provide a level of protection against significant price increases, targets a percentage range up to 45% of annual normalized sales volumes for North Carolina and operates using historical pricing indices that are tied to future projected gas prices as traded on a national exchange. Unlike South Carolina as discussed below, recovery of costs associated with the North Carolina hedging plan is not pre-approved by the NCUC, and the costs are treated as gas costs subject to the annual gas cost prudence review. Any gain or loss recognition under the hedging program is a reduction in or an addition to gas costs, respectively, which, along with any hedging expenses, are flowed through to North Carolina customers in rates. The gas cost review orders issued November 2014, November 2015 and November 2016 found our hedging activities during the review periods to be reasonable and prudent. In January 2014, we filed a petition with the NCUC seeking authority to adjust rates effective February 1, 2014 under the IMR mechanism approved in the 2013 general rate case proceeding as discussed above. The IMR provided for annual adjustments to our rates every February 1 for capital investments in integrity and safety projects as of October 31 of the preceding year. In February 2014, the NCUC approved as filed the initial IMR adjustment totaling $0.8 million in annual margin revenues that we reflected in our rates to customers beginning that month. In December 2014, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $26.6 million in annual IMR margin revenues effective February 1, 2015 based on capital investments in integrity and safety projects through October 31, 2014. In January 2015, the NCUC issued an order authorizing the requested IMR rate adjustments, subject to further review and determination of the reasonableness and prudence of the capital investments and associated costs reflected in the adjustments in our annual IMR adjustment proceedings or next general rate case, with any adjustments to be implemented through a prospective rate adjustment at or after the time such adjustment is approved by the NCUC. We subsequently engaged in discussions with the NCUC Public Staff regarding the completion of their review of the IMR costs and the development of a future procedural schedule for the IMR audit and rate approval process. In September 2015, we and the NCUC Public Staff filed an agreement with the NCUC seeking approval of the following stipulations regarding the operation of the IMR:
Based on the IMR agreement, in November 2015, we filed a petition with the NCUC seeking authority to adjust our rates effective December 1, 2015 to collect an additional $13.4 million in annual IMR margin revenues, based on IMR-eligible capital investments in integrity and safety projects through September 30, 2015. In November 2015, the NCUC approved the IMR settlement agreement and the requested December 2015 IMR rate increase. In February 2016, the NCUC Public Staff filed their IMR audit report for the capital investment period through September 30, 2015, proposing an immaterial reduction in IMR margin for refund to customers, which we began recording in January 2016. In May 2016, we filed a petition to adjust our rates effective June 1, 2016 to collect an additional $7.4 million in annual IMR margin revenues from that approved by the NCUC in December 2015. The June 2016 rate adjustment was based on IMR-eligible capital investments in integrity and safety projects through March 31, 2016. In May 2016, the NCUC approved the requested rate increase. In October 2016, we filed a petition to adjust our rates effective December 1, 2016 to collect an additional $8.2 million in annual IMR margin revenues from that approved by the NCUC in May 2016. The December 2016 rate adjustment was based on IMR-eligible capital investments in integrity and safety projects through September 30, 2016, which total $513.1 million since inception of the IMR mechanism. In November 2016, the NCUC approved the requested rate increase. In April 2014, the NCUC issued an order granting us the authority to issue up to $1.0 billion in the aggregate of senior or subordinated debt securities or equity securities under our open shelf registration statement. This request was made by us to allow flexibility to access the capital markets as needed for business purposes, including for capital investments and to fund the operations of our subsidiaries. See Note 5 for further information on this shelf registration statement. In March 2015, we filed a petition with the NCUC seeking authority for a one-time gas cost bill credit, including applicable sales taxes, for our retail sales and transportation customers in North Carolina to reduce the balance of our amounts due to customers. In March 2015, the NCUC issued an order approving our request. The bill credit of $45.5 million was reflected on customers' April 2015 bills, reducing amounts due to customers in North Carolina. In March 2016, we filed a petition with the NCUC requesting approval of deferred accounting treatment for certain distribution integrity management program expenses. We proposed this accounting treatment as an extension of the regulatory asset accounting treatment approved by the NCUC in December 2004 for our transmission integrity management program expenses. In June 2016, we agreed to withdraw this deferral request upon the NCUC’s approval of the agreement of stipulation and settlement in the proceeding seeking approval of the Acquisition as discussed above, contingent upon the closing of the Acquisition. In October 2016, we withdrew the petition pursuant to the terms of the NCUC-approved agreement of stipulation and settlement for the Acquisition. South Carolina We currently operate under the Natural Gas Rate Stabilization Act of 2005 in South Carolina. If a utility elects to operate under this act, the annual cost and revenue filing will provide that the utility’s rate of return on equity will remain within a 50-basis point band above or below the last approved allowed rate of return on equity. In June 2014, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2014 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in October 2013. In October 2014, the PSCSC issued an order approving a settlement agreement between the Office of Regulatory Staff (ORS) and us that resulted in a $2.9 million annual decrease in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2014. Also in this proceeding, the PSCSC approved the recovery of $0.1 million of our deferred South Carolina environmental costs and $0.5 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility located in North Carolina, both with amortization periods of one year beginning November 2014 and ending October 2015. In June 2015, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2015 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2014 order. In October 2015, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $1.65 million annual increase in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2015. In June 2016, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2016 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2015 order. In October 2016, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in an $8.3 million annual increase in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2016. Also in this proceeding, the PSCSC approved the use of revised depreciation rates effective November 1, 2016. In South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Costs have never been disallowed on the basis of prudence. The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan targets a percentage range up to 45% of annual normalized sales volumes for South Carolina and operates using historical pricing indices tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan are deemed to be prudently incurred and recovered in rates as gas costs. Any gain or loss recognized under the hedging program is a reduction in or an addition to gas costs, respectively, and flows through to South Carolina customers in rates. In August 2014, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2014. In September 2015, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2015. In August 2016, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2016. Tennessee In Tennessee, we operate under the Tennessee Incentive Plan (TIP) that benchmarks gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. Under the TIP, the TRA established an allocation of secondary marketing gains and losses to ratepayers and shareholders with a uniform 75/25 sharing ratio with a $1.6 million annual incentive cap for us on these gains and losses. The TIP includes procedures for asset management transactions and provides for a triennial review of TIP operations by an independent consultant. Although the TIP replaced annual prudence reviews of our gas purchasing activities, we undergo an annual compliance audit on the accuracy of our calculations and compliance with all TRA orders and directives regarding the calculation of our deferred gas cost account balances under the Actual Cost Adjustment (ACA) mechanism. In August 2013, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2013 under the TIP. In February 2014, the Audit Staff submitted their report with which we concurred. In March 2014, the TRA approved and adopted the Audit Staff’s report. The TRA’s written order was issued in April 2014. In August 2014, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2014 under the TIP. In March 2015, the Audit Staff submitted their report with which we concurred. In April 2015, the TRA approved and adopted the Audit Staff's report. The TRA's written order was issued in May 2015. In August 2015, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2015 under the TIP. In March 2016, the TRA’s audit staff submitted their report, including immaterial adjustments, with which we concurred. In April 2016, the TRA approved and adopted the audit staff’s report. In August 2016, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2016 under the TIP. We are waiting on a ruling from the TRA at this time. In November 2015, we filed an annual report for the twelve months ended June 30, 2014 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In February 2016, the TRA approved the deferred gas cost account balances and issued its written order. In February 2016, we filed an annual report for the twelve months ended June 30, 2015 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In June 2016, the TRA approved the deferred gas cost account balances and issued its written order. In August 2016, we filed an annual report for the twelve months ended June 30, 2016 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are waiting on a ruling from the TRA at this time. In August 2013, we filed a petition with the TRA seeking authority to implement an IMR to recover the costs of our capital investments that are made in compliance with federal and state safety and integrity management laws or regulations. We proposed that the rider be effective October 1, 2013 with an initial adjustment on January 1, 2014 of $13.1 million in annual margin revenue from tariff customers based on capital expenditures of $100.4 million incurred through October 2013 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In September 2013, the TRA issued an order suspending this proposed tariff through December 30, 2013. In November 2013, we and the Tennessee Attorney General's Consumer Advocate and Protection Division (CAD) filed an IMR settlement with the TRA. A hearing on this matter was held in December 2013, and the TRA approved the IMR settlement as filed for $13.1 million with the IMR rate adjustments beginning January 2014. A written order was issued in May 2014. In December 2014, we filed a petition with the TRA seeking authority to collect an additional $6.5 million in annual IMR margin revenues effective January 2015 based on $54.0 million of capital investments in integrity and safety projects over the twelve-month period ended October 31, 2014. In January 2015, the TRA accepted and approved the requested IMR rate adjustment and issued its written order in February 2015. In November 2015, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue effective January 2016 based on $18.4 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2015. In December 2015, the TRA approved the IMR rate increase to be effective January 2016 and issued its written order in February 2016. In November 2016, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue effective January 2017 based on $20.1 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2016. We are waiting on a ruling from the TRA at this time. In February 2014, we filed a petition with the TRA to authorize us to amortize and refund $4.7 million to customers for recorded excess deferred taxes. We proposed to refund this amount to customers over three years. In November 2015, we filed a settlement agreement with the CAD stipulating that Piedmont refund the $4.7 million to customers over a twelve month period. In December 2015, the TRA approved the settlement agreement, and we began refunding the $4.7 million to customers through a rate decrement over the twelve month period beginning January 2016. The TRA’s written order was issued in February 2016. In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas (CNG) infrastructure rider to recover the costs of our capital investments in infrastructure and equipment associated with this alternative motor vehicle transportation fuel. We proposed that the tariff rider be effective October 1, 2014 with an initial rate adjustment on November 1, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In November 2014, the TRA consolidated this docket with a separate petition we filed seeking modifications to our tariff regarding service to customers using natural gas as a motor fuel. A hearing on this matter was held in January 2015. In February 2015, the TRA (1) denied approval of the proposed tariff rider, (2) ruled that our retail CNG motor fuel service should be unregulated and no longer provided under our regulated tariff, and (3) approved the proposed modification to our tariff providing natural gas for motor fuel purposes at customer premises. The TRA indicated that we may seek recovery of our prior investments in CNG equipment of $4.7 million since our last rate proceeding in utility rate base in our next general rate case proceeding as the investments were made in good faith under the assumption retail CNG motor fuel would be a regulated service. The TRA's written order was issued in October 2015. In July 2016, the TRA Staff filed its compliance audit report for operation of our WNA rider during the 2015 – 2016 heating season, concluding that we had correctly implemented the WNA rider in all material aspects. The TRA Staff identified an immaterial error that resulted in an under-collection of our WNA revenues and recommended a correcting adjustment through the ACA mechanism which we recorded in August 2016. In August 2016, the TRA approved and adopted the TRA Staff’s compliance audit report. The TRA’s written order was issued in September 2016. All States Due to the seasonal nature of our business and as approved by our state regulatory commissions, we contract with customers in the secondary market to sell supply and capacity assets when market conditions permit. These sales normally contribute smaller per-unit margins to earnings; however, the programs allow us to act as a wholesale marketer of natural gas and transportation capacity when market conditions are favorable and when the supply and capacity are not required to serve our retail distribution system. In North Carolina and South Carolina, we operate under sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions where 75% of the net margins are flowed through to jurisdictional customers in rates and 25% is retained by us. In Tennessee, we operate under the TIP where gas purchase benchmarking gains and losses are combined with secondary market transaction gains and losses and shared 75% by customers and 25% by us. Effective October 3, 2016, secondary market margins generated through off-system sales and capacity release activity to Duke Energy are 100% credited to customers. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million. This sharing mechanism for secondary market activity in all three jurisdictions for the twelve months ended October 31, 2016, 2015, and 2014 is presented below.
We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system in order to mitigate the risk exposure to the financial condition of the marketers. |
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Stockholders' Equity Note [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Common Stock | Common Stock With the consummation of the Acquisition on October 3, 2016, each share of Piedmont's outstanding common stock (other than shares owned by Duke Energy and its wholly owned subsidiaries) was converted into the right to receive $60 in cash per share, and all of Piedmont's outstanding common stock was canceled and delisted from the NYSE. Our Restated Articles of Incorporation were amended on the consummation date to change the number of authorized shares to 100 shares of common stock, no par value. The issued and outstanding shares of the Merger Sub became the issued and outstanding shares of Piedmont, a wholly owned subsidiary of Duke Energy. Common Stock Changes in common stock for the years ended October 31, 2016, 2015 and 2014 are as follows.
Under our effective combined debt and equity shelf registration statement, we established an at-the-market (ATM) equity sales program, including a forward sale component. On January 7, 2015, we entered into separate ATM Equity Offering Sales Agreements (Sales Agreements) with Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, in their capacity as agents and/or as principals (Agents). Under the terms of the Sales Agreements, we could issue and sell, through either of the Agents, shares of our common stock, up to an aggregate sales price of $170.0 million (subject to certain exceptions) during the period beginning January 7, 2015 and ending October 31, 2016. In addition to the issuance and sale of shares by us through the Agents, we could also enter into FSAs with affiliates of the Agents as Forward Purchasers. In connection with each FSA, the Forward Purchasers would, at our request, borrow from third parties and, through the Agents, sell a number of shares of our common stock equal to the number of shares underlying the FSA as its hedge. Under the Sales Agreements, we specified the maximum number of our shares to be sold and the minimum price per share. We paid each Agent (or, in the case of a FSA, the Forward Purchaser through a reduced initial forward sale price) a commission of 1.5% of the sales price of all shares sold through it as sales agent under the applicable Sales Agreement. The shares offered under the Sales Agreements could be offered, issued and sold in ATM sales through the Agents or offered in connection with one or more FSAs. The table below presents equity transactions that were settled in shares under the open registration statements over the two-year period ended October 31, 2016.
In accordance with accounting guidance, we classified the FSAs as equity transactions because the forward sale transactions were indexed to our own stock and the physical settlement was within our control. As a result of this classification, no amounts were recorded in the Consolidated Financial Statements until the final settlement of the FSAs, which were all physically settled. We recorded the FSA amounts in "Equity" as an addition to "Common stock" on the Consolidated Balance Sheets. Upon settlement, we used the net proceeds from the FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our commercial paper (CP) program and for general corporate purposes. As a result of the Acquisition, Piedmont's shelf registration statement is no longer valid for future issuances. Other Comprehensive Income (Loss) Our OCIL is a part of our accumulated OCIL and is comprised of hedging activities and retirement benefits from our investments in unconsolidated affiliates. See Note 11 for further information on our investments in unconsolidated affiliates. Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2016 and 2015.
A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended October 31, 2016 and 2015.
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Debt and Credit Facilities |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt and Credit Facilities | Debt and Credit Facilities Summary of Long-Term Debt Our long-term debt consists of privately placed senior notes issued under note purchase agreements, as well as publicly issued medium-term and senior notes issued under an indenture. All of our long-term debt is unsecured and is issued at fixed rates. None of our debt is actively traded. The tables below reflect the detail of this presentation for our long-term debt as of October 31, 2016 and 2015.
Current maturities for the next five years ending October 31 and thereafter are as follows.
In June 2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on June 6, 2014. The NCUC approved debt and equity issuances under this shelf registration statement up to $1.0 billion during its three-year life. As a result of the Acquisition, Piedmont's shelf registration statement is no longer valid for future issuances. On September 14, 2015, we issued $150.0 million of ten-year, unsecured senior notes with an interest rate of 3.60% and at a discount of .065% or $0.1 million under the registration statement in effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to June 1, 2025, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 25 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after June 1, 2025, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $148.9 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes. On June 6, 2016, we repaid $40.0 million of our 2.92% senior notes at maturity. On July 28, 2016, we issued $300.0 million of unsecured senior notes maturing November 1, 2046 with an interest rate of 3.64% and at a discount of .122% or $0.4 million under the registration statement in effect noted above. We have the option to redeem all or part of the notes before May 1, 2046, at a redemption price equal to the greater of a) 100% of the principal amount of the notes to be redeemed, and b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, as supplemented, plus 25 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes on or after May 1, 2046, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $297.0 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes. The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being "restricted payments"), except out of net earnings available for restricted payments. As of October 31, 2016, our net earnings available for restricted payments were $1.3 billion. We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross default provisions in all of our debt agreements. As of October 31, 2016, we are in compliance with all default provisions. The default provisions of some or all of our senior debt include:
The Acquisition constituted a change in control under the note agreements under which our 4.24% Senior Notes due 2021, 3.47% Senior Notes due 2027 and 3.57% Senior Notes due 2027 were issued. While the Acquisition did not constitute an event of default, upon the closing of the Acquisition, we were required to offer to prepay 100% of the principal amounts plus accrued interest to these noteholders. None of the noteholders exercised the prepayment option. Available Credit Facilities At October 31, 2016, we have an $850.0 million five-year revolving syndicated credit facility that expires on December 14, 2020 that has an option to request an expansion up to an additional $200.0 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The facility provides a line of credit for letters of credit of $10.0 million, of which $1.7 million and $1.6 million were issued and outstanding as of October 31, 2016 and 2015, respectively. These letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. The credit facility bears interest based on the 30-day London Interbank Offered Rate (LIBOR) plus from 75 to 112.5 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2020 provided that we are in compliance with all terms of the agreement. The facility expressly permitted the Acquisition by Duke Energy. We have an $850.0 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850.0 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. Any borrowings under the CP program rank equally with our other unsecured debt. The notes under the CP program are not registered and are offered and issued pursuant to an exemption from registration. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year. As of October 31, 2016, we had $145.0 million of notes outstanding under the CP program, as included in "Notes payable and commercial paper" within "Current Liabilities" on the Consolidated Balance Sheets, with original maturities ranging from 1 to 6 days from their dates of issuance at a weighted average interest rate of .64%. As of October 31, 2015, our outstanding notes under the CP program, included on the Consolidated Balance Sheets as stated above, were $340.0 million at a weighted average interest rate of .22%. Other than outstanding CP balances, we did not have any borrowings under the revolving syndicated credit facility for the twelve months ended October 31, 2016. A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2016 is as follows.
Our five-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 55% at October 31, 2016. |
Financial Instruments & Related Fair Value |
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Financial Instruments & Related Fair Value [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Financial Instruments and Related Fair Value | Financial Instruments and Related Fair Value Derivative Assets and Liabilities under Master Netting Arrangements We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans with the purchase of financial gas call option derivative instruments (gas purchase options). The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our gas purchase options. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of October 31, 2016 and 2015, we had long gas purchase options providing total coverage of 15.4 million dekatherms and 34.7 million dekatherms, respectively. The long gas purchase options held as of October 31, 2016 are for the period from December 2016 through May 2017. Derivative Assets and Liabilities - Gas Supply Contracts We enter into forward gas supply contracts to provide diversification, reliability and gas cost benefits to our customers as part of our diversified gas supply portfolio. We evaluate all of our gas supply contracts at inception to determine if they meet the definition of a derivative in accordance with accounting guidance, whether any derivative contracts qualify as "normal purchases and normal sales" and would not be subject to fair value accounting requirements, or if they can be designated for hedge accounting purposes. Beginning with the year ended October 31, 2016, we have certain long-dated, fixed quantity forward gas supply contracts that meet the definition of derivative instruments that should be recorded at fair value. We have included gas supply contracts requiring fair value accounting in "Other" in "Current Liabilities" and "Deferred Credits and Other Liabilities" in the Consolidated Balance Sheets. As these contracts have been entered into for our regulated utility operations, and as commodity costs are recoverable through our PGA clauses in the jurisdictions in which we operate, we have recorded the offset to an applicable regulatory asset. Fair Value Measurements and Quantitative and Qualitative Disclosures We use gas purchase options as financial instruments that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. Based on our continual evaluation under derivative accounting standards of contracts added to our supply portfolio, we have determined that certain of these long-dated, fixed quantity gas supply contracts that became effective beginning with the year ended October 31, 2016 should be recorded at fair value. The costs of our gas cost hedging plans for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions, and thus are not accounted for as designated hedging instruments under derivative accounting standards. As required by the accounting guidance, we present our derivative positions at fair value on a gross basis and have only asset positions for all periods presented for the fair value of our gas purchase options held for our utility operations. There are no gas purchase options in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements. Therefore, we have no offsetting disclosures for financial assets or liabilities for our gas purchase options held for utility operations. Our gas purchase options held for utility operations are held with one broker as our counterparty. We have only liability positions for our gas supply derivative contracts presented at fair value that are held for our utility operations. We also have trading securities that are held in rabbi trusts established for certain deferred compensation plans and are included in "Other" within "Investments and Other Assets" on the Consolidated Balance Sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges. In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in "Fair Value Measurements" in Note 1. The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of October 31, 2016 and 2015. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their consideration within the fair value hierarchy levels. We have had no transfers between any level during the years ended October 31, 2016 and 2015.
In our discounted cash flow valuation, our unobservable input was the price of natural gas in future periods past the observable market price, commencing in the middle of the contract terms. The unobservable prices of our gas supply derivative contracts in the mid to later years of contract terms ranged from $2.60 to $4.47 per dekatherm. The fair value of our gas supply derivative contracts is sensitive to the pricing differential of various natural gas indexes relevant to those particular contracts. An increased market price spread between the indexes would increase the fair value of the derivative and result in an unrealized loss, while conversely, a decreased market price spread would decrease the fair value of the derivative and result in an unrealized gain. The following is a reconciliation of the gas supply derivative liabilities that are classified as Level 3 in the fair value hierarchy for the twelve months ended October 31, 2016.
We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs are to use these financial instruments to reduce gas cost volatility for our customers. Our regulated utility operations gas purchase options are used in accordance with programs filed with or approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These gas purchase options are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these gas purchase options are reflected in purchased gas costs and ultimately passed through to customers through our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the operation of the hedging programs of the regulated utility operations as a result of the use of these gas purchase options is initially deferred as amounts due from customers included as "Current Regulatory Assets" or amounts due to customers included as "Current Regulatory Liabilities" in Note 3 and recognized on the Consolidated Statements of Operations and Comprehensive Income as a component of "Cost of natural gas" when the related costs are recovered through our rates. These gas purchase options are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1. Our gas supply derivatives are generally based on unobservable inputs and are classified within Level 3. In accordance with regulatory provisions for rate-regulated activities, any gains and losses associated with these derivatives are reflected as a regulatory asset or liability, as appropriate, in "Derivatives - gas supply contracts held for utility operations" in Note 3. The following table presents the fair value and balance sheet classification of our gas purchase options and gas supply derivative contracts for natural gas as of October 31, 2016 and 2015.
The following table presents the impact that our gas purchase options not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended October 31, 2016 and 2015, absent the regulatory treatment under our approved PGA procedures.
In Tennessee, the cost of gas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP as approved by the TRA. In South Carolina, the costs of gas purchase options are subject to and are approved for recovery under the terms and conditions of our gas hedging plan as approved by the PSCSC. In North Carolina, the costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC. We would have recorded an unrealized loss of $187.9 million related to our gas supply derivative contracts in the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended October 31, 2016, absent regulatory provisions for rate-regulated activities. We recognize the actual costs of our gas supply derivative contracts in the Consolidated Statements of Operations and Comprehensive Income as a component of "Cost of natural gas" in the month purchased. Our long-term debt is presented at net cost. In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury benchmark with consideration given to maturities, redemption terms and credit ratings. The principal and fair value of our long-term debt, which is classified within Level 2, are shown below.
Credit and Counterparty Risk We are exposed to credit risk as a result of transactions for the purchase and sale of natural gas and related products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, power generation, residential and municipal energy consumers. These transactions have historically occurred in the gulf coast and mid-west regions of the United States, but our portfolio is being rebalanced and diversified by adding gas supply from northeastern United States gas supply basins. Credit risk associated with receivables for the natural gas distribution operations is mitigated by the large number of individual customers and diversity in our customer base. We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers. The amount included in "Receivables" within "Current Assets" on the Consolidated Balance Sheets attributable to these entities amounted to $14.2 million, or approximately 31% of our gross receivables as of October 31, 2016. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, our policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly. We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party. We believe, based on our credit policies as of October 31, 2016, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty. Natural gas distribution operating revenues and related receivables are generated from state-regulated utility natural gas sales and transportation to over one million residential, commercial and industrial customers, including power generation and municipal customers, located in North Carolina, South Carolina and Tennessee. A change in economic conditions may affect the ability of customers to meet their obligations. We have mitigated our exposure to the risk of non-payment of utility bills by our customers. Gas costs related to uncollectible accounts are recovered through PGA procedures in all jurisdictions. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas and colder-than-normal weather can slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal receivables; however, we believe that our provision for possible losses on uncollectible receivables are adequate for our credit loss exposure. Risk Management Our financial derivative instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments. We seek to identify, assess, monitor and manage risk in accordance with established comprehensive risk management policies under the direction of Duke Energy’s Chief Executive Officer (CEO) and Chief Financial Officer. The Finance and Risk Management Committee of Duke Energy's Board of Directors receives periodic updates from Duke Energy's Chief Risk Officer and other members of management on market risk positions, corporate exposures, and overall risk management activities. The Chief Risk Officer is responsible for the overall governance of managing commodity price risk, including monitoring exposure limits. |
Commitments & Contingencies |
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies | Commitments and Contingencies Leases We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance. Operating lease payments for the years ended October 31, 2016, 2015 and 2014 are as follows.
Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.
Long-term contracts We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. Costs arising from the gas supply commodity and capacity commitments, while significant, are pass-through costs to our customers and are fully recoverable subject to our PGA procedures and prudence reviews in North Carolina and South Carolina and under the TIP in Tennessee. The time periods for fixed payments under pipeline and storage capacity contracts are up to nineteen years. The time periods for fixed payments of reservation fees under gas supply contracts are up to two years. The time period for the gas supply purchase commitments is up to fifteen years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service are up to five years. Other purchase obligations consist primarily of commitments for pipeline products, equipment and contractors. Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the FERC in order to maintain our right to access the natural gas storage or the pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized on the Consolidated Statements of Operations and Comprehensive Income as part of gas purchases and included within "Cost of natural gas." As of October 31, 2016, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.
Legal We have only routine litigation in the normal course of business. We do not expect any of these routine litigation matters to have a material effect, either individually or in the aggregate, on our financial position, results of operations or cash flows. Letters of Credit We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $1.7 million in letters of credit that were issued and outstanding as of October 31, 2016. See Note 5 for additional information concerning letters of credit. Surety Bonds In the normal course of business, we are occasionally required to provide financial commitments in the form of surety bonds to third parties as a guarantee of our performance on commercial obligations. We have agreements that indemnify certain issuers of surety bonds against losses that they may incur as a result of executing surety bonds on our behalf. If we were to fail to perform according to the terms of the underlying contract, any draws upon surety bonds issued on our behalf would then trigger our payment obligation to the surety bond issuer. As of October 31, 2016, we had open surety bonds with a total contingent obligation of $6.4 million. Environmental Matters Our three regulatory commissions have authorized us to utilize deferral accounting in connection with costs for environmental assessments and cleanups. Accordingly, we have established regulatory assets for actual environmental costs incurred and have recorded estimated environmental liabilities, including those for our manufactured gas plant (MGP) sites, LNG facilities and underground storage tanks (USTs). We share environmental responsibility for various MGP sites with Duke Energy, and one of its subsidiaries. In 1997, we entered into a settlement with Duke Energy with respect to nine MGP sites that we have owned, leased or operated that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources. In connection with our 2003 North Carolina Natural Gas Corporation (NCNG) acquisition and prior to its closing, several MGP sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc. (Progress), a subsidiary of Duke Energy since July 2012. Progress has complete responsibility for performing all of the former NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the costs of such testing and clean-up and the implementation of any affirmative remediation obligations that were related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage, and diminution of property value or natural resources. We know of no such pending or threatened claims. As of October 31, 2016, our estimated undiscounted environmental liability totaled $1.0 million, and consisted of $0.8 million for MGP sites for which we retain responsibility and $0.2 million for USTs, our Huntersville LNG facility and other environmental costs. The costs we reasonably expect to incur are estimated using assumptions based on actual costs incurred, the timing of future payments and inflation factors, among others. For the period ending October 31, 2016, we incurred $0.1 million of remediation costs related to our MGP sites and Huntersville LNG facility. We continue to expand our sampling of our pipelines for coatings containing asbestos. Additionally, we continue to educate our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose portions of the pipeline. As of October 31, 2016, our regulatory assets for unamortized environmental costs in our three-state territory totaled $5.1 million. We received approval from the TRA to recover $2.0 million of our deferred Tennessee environmental costs over an eight-year period beginning March 2012, pursuant to the 2012 general rate case proceeding in Tennessee. We will seek recovery of the remaining Tennessee balance in future rate proceedings. The approval by the NCUC in December 2013 of the settlement of the general rate proceeding allowed recovery of $6.3 million of our deferred North Carolina environmental costs over a five-year period beginning January 2014. Further evaluation of the MGP, LNG and UST sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material effect on our financial position, results of operations or cash flows. |
Employee Benefit Plans |
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General Discussion of Pension and Other Postretirement Benefits [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Employee Benefit Plans | Employee Benefit Plans We recognize all obligations related to our defined benefit pension and other postretirement employee benefits (OPEB) plans and quantify the plans’ funded status as an asset or liability on the Consolidated Balance Sheets. We measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. Our plans’ assets are recorded at fair value. In accordance with accounting guidance, we are required to recognize as a component of OCI the changes in the funded status that occurred during the year that are not recognized as part of net periodic benefit cost; however, in 2006, we obtained regulatory treatment from the NCUC, the PSCSC and the TRA to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability as the future recovery of pension and OPEB costs is probable. To date, our regulators have allowed future recovery of our pension and OPEB costs. For the impact of this regulatory treatment, see the following table of actuarial plan information that specifies the amounts not yet recognized as a component of cost and recognized as a regulatory asset or liability. Pension Benefits We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan) for our eligible employees. A defined benefit plan specifies the amount of benefit that an eligible participant eventually will receive upon retirement using information about that participant. An employee is eligible on the January 1 or July 1 following either the date on which he or she attained age 30 or attained age 21 and completed 1,000 hours of service during an applicable year. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement or termination during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes. The qualified pension plan is closed to employees hired after December 31, 2007. Employees hired prior to January 1, 2008 continue to participate in the qualified pension plan. Employees are vested after five years of service and can be credited with up to a total of 35 years of service. When a vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007 under a specific formula plus the accrued benefit calculated under a second formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the second formula. The investment objectives of the qualified pension plan are oriented to meet both the current ongoing and future commitments to the participants and designed to grow at an acceptable rate of return for the risks permitted under the investment policy guidelines. Assets are structured to provide for both short-term and long-term needs and to meet the objectives of the qualified pension plan. Our primary investment objective of the qualified pension plan is to generate sufficient assets to meet plan liabilities. The plan’s assets will therefore be invested to maximize long-term returns in a manner that is consistent with the plan’s liabilities, cash flow requirements and risk tolerance. The plan’s liabilities are defined in terms of participant salaries. Given the nature of these liabilities and recognizing the long-term benefits of investing in return-generating assets, the qualified pension plan seeks to invest in a diversified portfolio to:
•Control year-to-year fluctuations in pension expense that is created by asset and liability volatility. We consider the current and targeted allocation of our plan assets and the expected long-term rates of return. Investment advisors assist us in deriving expected long-term rates of return. These rates are generally based on a 20-year horizon for various asset classes, our expected investments of plan assets and active asset management, where applicable. The investment philosophy of the qualified pension plan is to maintain a balanced portfolio which is diversified across asset classes. The portfolio is primarily composed of equity and fixed income investments in order to provide diversification as to issuers, economic sectors, markets and investment instruments. Risk and quality are viewed in the context of the diversification requirements of the aggregate portfolio. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund. The qualified pension plan maintains the following types of investments:
The target and actual allocations of the qualified pension plan's assets are as follows.
Employees hired or rehired after December 31, 2007 cannot participate in the qualified pension plan but are participants in the Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee to direct the investments and assume the risk of investment returns. A defined contribution plan specifies the amount of the employer’s annual contribution to individual participant accounts established for the retirement benefit. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Under the MPP plan, we annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after three years of service. During the year ended October 31, 2016, 2015 and 2014, we contributed $1.8 million, $1.4 million and $0.9 million, respectively, to the MPP plan. OPEB Plan We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees hired prior to January 1, 2008 are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees hired after January 1, 2008 have to complete ten years of service after age 50 to be eligible for benefits, and no benefits are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to cover health costs. Employees who meet the eligibility requirements to retire also receive a life insurance benefit of $15,000. Prior to January 1, 2016, employees who met the eligibility requirement noted above or were part of a "grandfathered" group received either full or partial retiree coverage paid by us, subject to certain participation limits. Retirees were responsible for the full cost of dependent coverage. Effective January 1, 2016, we replaced the existing retiree medical and dental group coverage for eligible retirees with a tax-free Health Reimbursement Arrangement (HRA). Under the new HRA, participating eligible retirees and their dependents may qualify for a subsidy each year through the HRA account to help purchase medical and dental coverage available on public and private health care exchanges using a tax-advantaged account funded by us to pay for allowable medical and dental expenses. OPEB plan assets are comprised of mutual funds within a 401(h) account and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is similar to the investment philosophy of the qualified pension plan as discussed above, except the OPEB fixed income portfolio does not include derivatives. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund. The target and actual allocations of the OPEB plan's assets are as follows.
Supplemental Executive Retirement Plans We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or surviving spouses. There are no assets related to these SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year. Actuarial information for these nonqualified plans is presented below. We have a non-qualified defined contribution restoration plan (DCR plan) for certain officers at the vice president level and above where benefits payable under the plan are informally funded annually through a rabbi trust with a bank as the trustee. We contribute 13% of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each covered executive. Participants may not contribute to the DCR plan. In accordance with the Merger Agreement, the account balances were subject to accelerated vesting effective with the consummation of the Acquisition with distribution occurring upon the participant's separation of service from the Company. Prior to the Acquisition, we had a voluntary deferred compensation plan for the benefit of all director-level employees and officers, where we made no contributions to this plan. Participants could defer a percentage of their base salary and annual incentive pay in accordance with the plan. Benefits under this plan, known as the Voluntary Deferral Plan, were informally funded monthly through a rabbi trust with a bank as the trustee. In accordance with the Merger Agreement, the account balances were subject to accelerated distribution effective with the consummation of the Acquisition. Our funding to the DCR plan account for the years ended October 31, 2016 and 2015, and the amounts recorded as liabilities for these two deferred compensation plans as of October 31, 2016 and 2015, are presented below.
We provide term life insurance policies for certain officers at the vice president level and above who were former participants in a terminated SERP; the level of the insurance benefit is dependent upon the level of the benefit provided under the terminated SERP. These life insurance policies are owned exclusively by each officer. Premiums on these policies are paid and expensed. We also provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the cost of the policies. The cost of these premiums was $0.1 million for the years ended October 31, 2016, 2015 and 2014. Actuarial Plan Information A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2016 and 2015, a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2016 and 2015, and the weighted average assumptions used in the measurement of the benefit obligations as of October 31, 2016 and 2015 are presented below.
Net periodic benefit cost components for the years ended October 31, 2016, 2015 and 2014 and the weighted average assumptions used to determine net period benefit cost as of October 31, 2016, 2015 and 2014 are presented below.
The 2017 estimated amortization of the following items for our plans, which are recorded as a regulatory asset or liability instead of accumulated OCIL discussed above, are as follows.
Equity market performance has a significant effect on our market-related value of plan assets. In determining the market-related value of plan assets, we use the following methodology: The asset gain or loss is determined each year by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Such asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of year end is determined by adjusting the market value of assets by the portion of the prior five years’ gains or losses that has not yet been recognized, meaning that 20% of the prior five years’ asset gains and losses are recognized each year. This method has been applied consistently in all years presented in the Consolidated Financial Statements. We amortize unrecognized prior-service cost over the average remaining service period for active employees. We amortize the unrecognized transition obligation over the average remaining service period for active employees expected to receive benefits under the plan as of the date of transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation and the market-related value of assets over the average remaining service period for active employees. The amortization period used for the purposes mentioned above for the NCNG SERP and the Piedmont SERP is an expected future lifetime as there are no active members in these plans. The method of amortization in all cases is straight-line. In addition to the assumptions in the above table, we also use subjective factors such as withdrawal and mortality rates in determining benefit obligations for all of our benefit plans. Our assumed mortality rates incorporate the new set of mortality tables issued by the Society of Actuaries in October 2014. We also applied the updated projection scale issued by the Society of Actuaries in October 2016. We anticipate that we will contribute the following amounts to our plans during the twelve month period ending October 31, 2017.
The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. We are in compliance with the 100% funding target established in the PPA. Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.
Based on the retiree medical and dental group coverage changing to a HRA where the retiree subsidy provided by Piedmont is fixed and assumed to not increase, we are no longer impacted by the health care cost component (projected health care cost trend rates) for our accumulated postretirement benefit obligation as of October 31, 2016 and 2015. In fiscal year 2016, we changed the methodology we use to calculate the periodic net benefit cost for our plans. We replaced the zero-coupon spot rate yield curve as the basis to estimate the service and interest cost components with a full yield curve methodology. This methodology applies specific spot rates along the yield curve to determine the benefit obligations of the relevant projected cash flows. This change improved the correlation between projected benefit cash flows and the corresponding yield curve spot rates and provided a more precise measurement of service and interest costs. This change did not affect the measurement of our total benefit obligation as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We accounted for this change as a change in estimate and, accordingly, accounted for it prospectively beginning in 2016. Effective with the consummation of the Acquisition, we changed the methodology we use to calculate the discount rate for the current year benefit obligation and next year's periodic net benefit cost for our plans. We replaced our full yield curve methodology with a bond selection-settlement portfolio approach used by Duke Energy. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or higher. After the bond portfolio is selected, a single interest rate, which was 3.80% as of October 31, 2016, is determined that equates the present value of the plan's projected benefit payments discounted at this rate with the market value of the bonds selected. This change decreased our total benefit obligations on our plans as of October 31, 2016 by $2.4 million. Fair Value Measurements Following is a description of the valuation methodologies used for assets measured at fair value in our qualified pension plan. Cash and cash equivalents – These are Level 1 assets valued at face value as they are primarily cash or cash equivalents. The assets that are Level 2 assets are valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund. Fixed income securities – These assets include:
Equity securities – These are level 1 assets valued at the market price of the active market on which the individual security is traded. Mutual funds – These are Level 1 assets valued at the publicly quoted NAV per share computed as of the close of business on our balance sheet date. Mutual funds with a NAV per share that is not publicly available are classified as Level 2. Common trust fund – These are Level 2 assets held in a common trust fund in which we own interests that are valued at the NAV of the funds as traded on international exchanges. Currently, there are no restrictions on redemptions for the fund. Private equity fund of funds – This is a Level 3 asset invested in hedge fund of funds valued based on a quarterly compilation of the financial statements from the underlying partnerships in which the fund invests. There are currently redemption restrictions for this fund. The target allocation for this investment is 3.5% but is still being funded through capital calls; $2.6 million of the original $12.0 million subscription remains unfunded. Until a 3.5% allocation can be achieved, the balance of the 3.5% allocation is invested in a low-cost equity index fund that tracks the Standard & Poor's 500 Stock Index. Our investment is in various funds that invest in North American companies, allocate capital to private equity funds, invest in venture capital partnerships and private equity partnerships in emerging markets. The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance. Hedge fund of funds – These investments are across a variety of markets through investment funds or managed accounts that invest in equities, equity-related instruments, fixed income and other debt-related instruments. Currently, there are no restrictions on redemptions for the fund. Commodities fund of funds – These investments are in commodities fund of funds that are actively managed through a well-diversified group of underlying managers. Currently, there are no restrictions on redemptions for the fund. High yield debt (bank loans) – These assets are held in a common trust fund that invest in global bank loans. Currently, there are no restrictions on redemption for the fund. As stated above, some of our investments for the qualified pension plan have redemption limitations, restrictions and notice requirements which are further explained below.
(1) The investment cannot be redeemed. We receive distributions only through the liquidation of the underlying assets. The assets are expected to be liquidated over the next 8 to 10 years. The qualified pension plan’s asset allocations by level within the fair value hierarchy as of October 31, 2016 and 2015 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their consideration within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see "Fair Value Measurements" in Note 1.
The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.
During the year, the qualified pension plan raises cash from various plan assets in order to fund periodic and lump sum benefit payments. Cash is raised as needed primarily from investments that have exceeded their target allocation and is dependent upon the number of retirees seeking lump sum distributions. There are significant unobservable inputs used in the fair value measurements of our investment in the private equity fund of funds’ limited partnerships. We are subject to the business risks inherent in the markets in which the partnerships are invested. The success or failure of the underlying businesses of the various partnerships that have been funded would result in a higher or lower fair value measurement. Following is a description of the valuation methodologies used for assets measured at fair value in our OPEB plan. Cash and cash equivalents – These are Level 1 assets having maturities of three months or less when purchased and are considered to be cash equivalents. Mutual funds – These are Level 1 assets valued at the publicly quoted NAV per share computed as of the close of business on our balance sheet date. The OPEB plan’s asset allocations by level within the fair value hierarchy as of October 31, 2016 and 2015 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see "Fair Value Measurements" in Note 1.
401(k) Plan We maintain a 401(k) plan that is a profit-sharing plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plan is subject to the provisions of the Employee Retirement Income Security Act. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary and cash incentive payments to the plan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service. Employees receive a company match of 100% up to the first 5% of eligible pay contributed. Employees may contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution and compensation limits. We automatically enroll all eligible non-participating employees in the 401(k) plan at a 2% contribution rate unless the employee chooses not to participate by notifying our record keeper. For employees who are automatically enrolled in the 401(k) plan, we automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our record keeper. If the employee does not make an investment election, employee contributions and matches are automatically invested in a diversified portfolio of stocks and bonds. Prior to the Acquisition, participants could direct up to 20% of their contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time. For the years ended October 31, 2016, 2015 and 2014, we made matching contributions to participant accounts as follows.
As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into the participants’ 401(k) accounts. Prior to the Acquisition, former ESOP participants could remain invested in Piedmont common stock in their 401(k) plan or could sell the common stock at any time and reinvest the proceeds in other available investment options. The tax benefit of any dividends paid on ESOP shares still in participants’ accounts is reflected in the Consolidated Statements of Changes in Equity as an increase in retained earnings. |
Employee Share Based Plans |
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Employee Share-Based Plans | Employee Share-Based Plans Prior to the Acquisition, under our shareholder approved ICP, eligible officers and other participants were awarded units that paid out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards were made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans required that a minimum threshold performance level be achieved in order for any award to be distributed. During 2016, we had three series of awards that were outstanding under the approved ICP, with a three-year performance period that ended October 31, 2016 (2016 plan), October 31, 2017 (2017 plan) and October 31, 2018 (2018 plan). For the years ended October 31, 2016, 2015 and 2014, we recorded compensation expense, and prior to the Acquisition, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. We re-measured the liability to market value each quarter and at the settlement date of the award. The Merger Agreement provided for the conversion of the 2016 and 2017 plans shares subject to the ICP awards at the performance level specified in the Merger Agreement into the right to receive $60 cash per share upon the closing of the transactions contemplated in the Merger Agreement. In November and December 2015, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the ICP awards under the 2016 plan and the 2017 plan (accelerated ICP awards) at the target level of performance to participants, at their election to accelerate, in the form of restricted shares of our common stock, net of shares withheld for applicable taxes. The acceleration and payout of the ICP awards, at a 96% election rate by the participants, was done for tax planning purposes and occurred on December 15, 2015. In connection with the election to accelerate the ICP awards, each respective participant executed a share repayment agreement dated December 15, 2015 that placed certain restrictions on the accelerated ICP awards. With the consummation of the Acquisition, all restrictions were lifted. The accelerated ICP awards were priced at the NYSE composite closing price of $56.85 on December 14, 2015. Under the accelerated ICP awards, 162,390 restricted nonvested shares of our common stock were issued to participants, net of shares withheld for applicable federal and state income taxes. Upon consummation of the Acquisition, the participants that did not accelerate their ICP awards, as discussed above, received $60 per share under the 2016 and 2017 plans, or $0.3 million in cash, net of applicable income taxes withheld. The 2018 plan was approved subsequent to the execution of the Merger Agreement with Duke Energy. Under the Merger Agreement, the 2018 plan performance awards were fully converted into Duke Energy restricted stock unit awards (Duke Energy RSU Award) upon consummation of the Acquisition. Vesting under the Duke Energy RSU Award will be subject to the participant remaining continuously employed by Duke Energy or its affiliates through October 31, 2018. The Duke Energy RSU Award will be subject to 100% accelerated vesting upon certain types of terminations of employment and prorated accelerated vesting upon retirement. The Duke Energy RSU Award is recorded as an equity award on Duke Energy's balance sheet. As of October 31, 2016, our liability related to this plan is $6.1 million as reflected in "Accounts payable to affiliated companies" within "Current Liabilities" on the Consolidated Balance Sheets. Also under our approved ICP, 64,700 nonvested restricted stock units (RSUs) were granted to our President and CEO prior to the consummation of the merger (former CEO) in December 2011. During the vesting period, any dividend equivalents were accrued on these stock units and converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The vested RSUs were payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, only if he remained an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vested on December 15, 2014 and 30% of the units vested on December 15, 2015. The remaining 50% of the units were scheduled to vest on December 15, 2016 (2016 RSU). The Merger Agreement provided for the conversion of the 2016 RSU into the right to receive $60 cash per share upon closing of the transaction contemplated in the Merger Agreement. Similar to the accelerated ICP awards discussed above, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the 2016 RSU (accelerated RSU) in the form of restricted shares of our common stock, net of shares withheld for applicable taxes. Our former CEO executed a share repayment agreement dated December 15, 2015 that placed certain restrictions on the accelerated RSU. The acceleration and payout of the accelerated RSU occurred on December 15, 2015. With the consummation of the Acquisition, all restrictions were lifted. For the twelve months ended October 31, 2016, 2015 and 2014, we recorded compensation expense, and prior to the Acquisition, we accrued a liability for nonvested RSUs as applicable, based on the fair market value of our common stock at the end of each quarter. The liability was re-measured to market value each quarter and at the settlement date of the award. The following table summarizes the settlement of the RSUs.
At the time of distribution of any award under the ICP, the number of shares of common stock issuable was reduced by the withholdings for payment of applicable income taxes for each participant. The participant could elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. We present the net shares issued in the Consolidated Statements of Changes in Equity and in Note 4. The compensation expense related to the awards under the ICP for the years ended October 31, 2016, 2015 and 2014, and the amounts recorded as liabilities in "Other deferred credits and other liabilities" within "Deferred Credits and Other Liabilities" with the current portion recorded in "Other current liabilities" within "Current Liabilities" on the Consolidated Balance Sheets as of October 31, 2016 and 2015 are presented below.
Equity Plan Prior to the Acquisition, on a quarterly basis, we issued shares of common stock under the ESPP and accounted for the issuance as an equity transaction. The exercise price was calculated as 95% of the fair market value on the purchase date of each quarter where the fair value was determined by calculating the average of the high and low trading prices on the purchase date. In anticipation of the Acquisition, we suspended new investments in our ESPP and resulting issuances of common stock under this plan, effective July 31, 2016. The ESPP was terminated at the closing date of the Acquisition on October 3, 2016. |
Income Taxes |
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Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Taxes | Income Taxes The components of income tax expense for the years ended October 31, 2016, 2015 and 2014 are presented below.
The Protecting Americans from Tax Hikes Act of 2015 enacted in December 2015 and the Tax Increase Prevention Act of 2014, enacted in December 2014, retroactively extended the 50% bonus depreciation which had expired the December of the year preceding the enactments. As a result of the retroactive extensions of bonus depreciation, we were able to claim additional depreciation deductions on our tax returns for the years ended October 31, 2015 and 2014. Prior to the retroactive extensions, we had anticipated utilizing NOL and tax carryforwards to offset taxable income generated in our fiscal years 2015 and 2014 as discussed in note (2) in the table above. The benefits from NOL and tax carryforwards in note (1) in the table above include $46.8 million and $61.1 million to record the retroactive impact of the passage of bonus depreciation for the years ended October 31, 2016 and 2015, respectively. A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2016, 2015 and 2014 is presented below.
We and our wholly owned subsidiaries file a consolidated federal income tax return and various state income tax returns. Effective with the Acquisition, our tax year end will change to December 31, 2016, and we and our wholly owned subsidiaries will be included in the Duke Energy consolidated income tax returns. Accordingly, Piedmont and its subsidiaries will file final consolidated income tax returns for the short tax year November 1, 2015 through October 3, 2016. We and our wholly owned subsidiaries will be included in the Duke Energy consolidated income tax returns for the period October 4, 2016 through December 31, 2016. Piedmont and each of our subsidiaries have entered into a tax sharing agreement with Duke Energy and subsidiaries. The tax sharing agreement provides allocation of consolidated tax liabilities and benefits based on amounts participants would incur as separate C-Corporations. Income taxes recorded for the period October 4, 2016 through October 31, 2016 are based on amounts we and our subsidiaries would incur as separate C-Corporations. Current and deferred income tax expense (benefit) of $40.4 million and $(8.7) million, respectively, was recorded for the period October 4 through October 31, 2016. "Taxes accrued" on the Consolidated Balance Sheets as of October 31, 2016 includes $31.5 million payable to Duke Energy for federal income taxes due under the tax sharing agreement. In accordance with IRS regulations, we and our subsidiaries are jointly and severally liable for the federal tax liability. As of October 31, 2016 and 2015, deferred income taxes consists of the following temporary differences. As discussed in Note 1 and Note 16, Piedmont early adopted ASU 2015-17, providing guidance that deferred tax assets and liabilities be classified as noncurrent. With this retrospective adoption, the balance sheet classification of deferred tax assets and liabilities were classified as noncurrent.
As of October 31, 2016 and 2015, total net deferred income tax assets were net of a valuation allowance to reduce amounts to the amounts that we believe will be more likely than not realized. A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2016, 2015 and 2014 is presented below.
The following table presents the expiration of tax carryforwards.
Following the Acquisition, utilization of our tax carryforwards is subject to various limitations. The primary limitation is federal NOL carryforwards of $159.6 million are subject to an effective annual limitation of $31.8 million. There were no unrecognized tax benefits for the years ended October 31, 2016 and 2015. During our 2016 fiscal year, we finalized the federal income tax examinations for tax years ended October 31, 2010, 2011 and 2012. We are no longer subject to federal examination and with few exceptions, state income tax examinations by tax authorities for years ended before and including October 31, 2012. The statute of limitations for the tax year ending October 31, 2012 expires February 28, 2017. During fiscal year 2016, we recognized $0.5 million in net interest income related to income taxes. In July 2013, legislation was passed in North Carolina affecting corporate taxation. The following table presents the corporate income tax rates resulting from this legislation, including subsequent reductions based on certain tax collections exceeding certain thresholds under North Carolina tax statutes.
As a result of the state income tax rate reductions, we adjusted our deferred income tax balances during fiscal year 2016 and 2015 by approximately $15.7 million and $17.5 million, respectively, for temporary differences expected to reverse at the lower future rate. We recognized a tax benefit during fiscal years 2016 and 2015 in net income of approximately $0.6 million and $0.5 million and recorded the remainder of approximately $15.1 million and $17.0 million during fiscal 2016 and 2015, respectively, as regulatory "Deferred income taxes" as presented in "Noncurrent Regulatory Liabilities" in Note 3, reflecting a future benefit to our customers. During fiscal 2014, we recorded an additional $3.0 million for the difference in the tax rate included in our customers' rates and the rate at which the deferred taxes are expected to reverse. As of October 31, 2016, we have approximately $58.6 million related to the North Carolina tax rate change included in our "Deferred income taxes" recorded in "Noncurrent Regulatory Liabilities." The NCUC will determine the recovery period of this regulatory liability in future proceedings. |
Investments in Unconsolidated Affiliates |
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Equity Method Investments and Joint Ventures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Investments in Unconsolidated Affiliates | Investments in Unconsolidated Affiliates The Consolidated Financial Statements include the accounts of our wholly owned subsidiaries who have investments in unconsolidated affiliates. These investments are in joint venture, energy-related businesses that are accounted for under the equity method. Our ownership interest in each entity is included in "Investments in equity method unconsolidated affiliates" within "Investments and Other Assets" on the Consolidated Balance Sheets. Earnings or losses from equity method investments are included in "Equity in earnings of unconsolidated affiliates" within "Other Income and Expense" in the Consolidated Statements of Operations and Comprehensive Income. As of October 31, 2016, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings. Ownership Interests We have the following membership interests in these companies as of October 31, 2016.
As of October 31, 2016 and 2015, our investment balances are as follows.
For the years ended October 31, 2016, 2015 and 2014, we recorded our proportionate share of earnings or losses from these unconsolidated affiliates in "Equity in earnings of unconsolidated affiliates" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income as follows.
Accumulated Other Comprehensive Income (Loss) As an equity method investor, we record the effect of certain transactions in our accumulated OCIL. Cardinal and Pine Needle enter into interest-rate swap agreements to modify the interest expense characteristics of their unsecured long-term debt which is nonrecourse to its members. Until the sale of our interest in SouthStar as discussed above, we recorded OCIL from this investment from financial contracts in the form of futures, options and swaps, all considered to be derivatives, to moderate the effect of price and weather changes on the timing of its earnings; fair value of these financial contracts was based on selected market indices. For these transactions with these unconsolidated affiliates, we record our share of movements in the market value of these hedged agreements and contracts and retirement benefit items in "Accumulated other comprehensive loss" within "Equity" on the Consolidated Balance Sheets; the detail of our share of the market value of the various financial instruments are presented in "Other Comprehensive Income (Loss), net of tax" on the Consolidated Statements of Operations and Comprehensive Income. Related Party Transactions We have related party transactions as a customer of our investments. For the years ended October 31, 2016, 2015 and 2014, these gas costs and the amounts we owed to our unconsolidated affiliates, as of October 31, 2016 and 2015, are as follows.
Through October 3, 2016, we had related party transactions as we sell wholesale gas supplies to SouthStar. For the years ended October 31, 2016, 2015 and 2014, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2016 and 2015, are as follows.
Information on Our Equity Method Investments Cardinal Cardinal is a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc. and SCANA Corporation. Cardinal has firm, long-term service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately 53%. Cardinal is dependent on the Williams – Transco pipeline system to deliver gas into its system for service to its customers. Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.
Pine Needle Pine Needle is a North Carolina limited liability company. The other members are the Municipal Gas Authority of Georgia, and subsidiaries of The Williams Companies, Inc. and SCANA Corporation. Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%. We are dependent on the Williams – Transco pipeline system for redelivery of Pine Needle volumes to our system for service to our customers. Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.
SouthStar SouthStar is a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly owned subsidiary of Southern Company Gas (effective July 1, 2016 following its acquisition of AGL Resources, Inc. (AGL)). In September 2015, under the terms of the SouthStar limited liability company agreement (SSE LLC Agreement) regarding GNGC's change in control, we affirmed our election by written notice to remain a member of SouthStar. In accordance with the SSE LLC Agreement, upon the announcement of the Acquisition, we delivered a notice of change of control to GNGC. In December 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in SouthStar, subject to and effective upon the consummation of the Acquisition. On October 3, 2016, we sold our 15% interest in SouthStar, and at closing, we received $160.0 million from GNGC resulting in an after-tax gain of $80.9 million. Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.
Hardy Storage Hardy Storage is a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission, LLC, an indirect subsidiary of TransCanada Corporation. Hardy Storage has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 40%. We are dependent on Columbia Pipeline Group and the Williams – Transco pipeline system for redelivery of Hardy Storage volumes to our system for service to our customers. Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2016 and 2015, and for the twelve months ended October 31, 2016, 2015 and 2014, is presented below.
Constitution Constitution is a Delaware limited liability company. The other members are subsidiaries of The Williams Companies, Inc., Cabot Oil & Gas Corporation and WGL Holdings, Inc. A subsidiary of The Williams Companies will be the operator of the pipeline. In December 2014, the FERC issued an order granting Constitution a certificate of public convenience and necessity. On April 22, 2016, the New York State Department of Environmental Conservation (NYSDEC) denied Constitution’s application for a necessary water quality certification for the New York portion of the Constitution pipeline. Constitution filed legal actions in the U.S District Court for the Northern District of New York and in the U.S Court of Appeals for the Second Circuit (U.S. Court of Appeals) challenging the legality and appropriateness of the NYSDEC’s decision. Both courts granted Constitution's motions to expedite the schedules for the legal actions. On November 16, 2016, oral arguments were heard in the U.S. Court of Appeals. Constitution has stated that it remains steadfastly committed to pursuing the project and that it intends to pursue all available options to challenge the NYSDEC's decision. In light of the denial of the certification, Constitution revised its target in-service date of the project to be as early as the second half of 2018, assuming that the challenge process is satisfactorily and promptly concluded. In July 2016, Constitution requested and the FERC approved an extension of the construction period and in-service deadline of the project to December 2018. Also in July, the FERC denied the New York Attorney General's (NYAG) complaint and request for a stay of the certificate order authorizing the project on the grounds that Constitution had improperly cut trees along the proposed route. The FERC found the complaint procedurally deficient and that there was no justification for a stay; it did find the filing constituted a valid request for investigation and thus referred the matter to FERC staff for further examination as may be appropriate. On November 22, 2016, the FERC denied the NYAG's request for reconsideration of this order. As a result of the NYSDEC's actions, beginning in April 2016, Constitution stopped construction and discontinued capitalization of future development costs until the project's uncertainty is resolved. We evaluated our investment in the Constitution project for OTTI. Our impairment assessment uses a discounted cash flow income approach, including consideration of the severity and duration of any decline in fair value of our investment in the project. Our key inputs involve significant management judgments and estimates, including projections of the project’s cash flows, selection of a discount rate and probability weighting of potential outcomes of legal and regulatory proceedings. At this time, we believe we do not have an OTTI and have not recorded any impairment charge to reduce the carrying value of our investment. Our evaluation considered that the pending legal and regulatory proceedings are in early stages given the actions of the NYSDEC in late April 2016. Further, the courts have granted Constitution's motions to expedite the schedules for the legal actions. However, to the extent that the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is not viable or does not go forward as legal and regulatory actions progress, our conclusions with respect to OTTI could change and may require that we recognize an impairment charge of up to our recorded investment in the project, net of any cash and working capital returned. We will continue to monitor and update our OTTI analysis as required. Different assumptions could affect the timing and amount of any charge recorded in a period. See Note 1 for information on our fair value evaluation process. Pending the outcome of the matters described above, and when construction proceeds, we remain committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $955.0 million, excluding AFUDC, subject to the terms of the LLC agreement. Our total anticipated contributions are approximately $229.3 million. As of October 31, 2016, our fiscal year contributions were $12.1 million, with our total equity contributions for the project totaling $84.8 million to date. The capacity of the pipeline is 100% subscribed under fifteen-year service agreements with two Marcellus producer-shippers with a negotiated rate structure. Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.
ACP On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL announced the formation of ACP, a Delaware limited liability company. A Dominion subsidiary is the operator of the pipeline. The pipeline is being designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date sometime in the second half of 2019, subject to state and other federal approvals. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty-year contracts. The total cost for the project is expected to be between $4.5 billion to $5.0 billion, excluding financing costs. Members anticipate obtaining project financing for 60% of the total costs during the construction period, and a project capitalization ratio of 50% debt and 50% equity when operational. As of October 31, 2016, our fiscal year contributions were $35.3 million, with our total equity contributions for the project totaling $46.0 million to date. In November 2014, the FERC authorized the ACP pre-filing process under which environmental review for the natural gas pipeline will commence. In February 2015, ACP, along with Dominion Transmission, Inc. (DTI), filed a notice of intent to prepare its environmental impact statement for the project and DTI’s supply header project affecting ACP. ACP filed its FERC application in September 2015 to request FERC authorization to construct and operate the project facilities under the previously FERC-approved pre-filing process, including the environmental review for the natural gas pipeline. FERC approval of the application of the certificate of public convenience and necessity is expected in late 2017 with construction projected to begin thereafter. On April 15, 2016, Dominion, on behalf of ACP, filed an updated application with the FERC. The filing included, among other items, updated alignment sheets, tables and information regarding the alternative routes adopted by the partners since filing a certificate application in September. On August 12, 2016, the FERC issued its notice of schedule for environmental review of the project. Under the notice of schedule, we anticipate that the FERC will issue its final environmental impact statement by June 30, 2017. On March 2, 2015, ACP entered into a Precedent Agreement with DTI for supply header transportation services. Under the Precedent Agreement, ACP is required to provide assurance of its ability to meet its financial obligations to DTI. DTI informed ACP that ACP, independent of its members, is not currently creditworthy as required by DTI’s FERC Gas Tariff. ACP requested that its members provide proportionate assurance of ACP’s ability to meet its financial obligations under the Precedent Agreement, which the Piedmont member provided through an Equity Contribution Agreement between Piedmont and ACP where Piedmont committed to make funds available to the Piedmont member for it to pay and perform its obligations under the ACP Limited Liability Company Agreement. Based on our reduced ownership percentage, this commitment is capped at $10.6 million. This commitment ceases when DTI acknowledges that ACP is independently creditworthy in accordance with the Precedent Agreement, termination or expiration of the Precedent Agreement, or when we are no longer a member of ACP. On July 13, 2015, the parent companies of the members of ACP entered into an indemnification agreement with an insurance company to secure surety bonds in connection with preparatory and pre-construction activities on the ACP project. Liability under the indemnification agreement is several and is capped at each member’s proportionate share, based on its membership interest in ACP, of losses, if any, incurred by the insurance company. Under a provision in the ACP limited liability company agreement, Dominion had an option to purchase additional ownership interests in ACP to maintain a majority ownership percentage relative to all other members. On October 3, 2016, in connection with the consummation of the Acquisition, Dominion purchased 3% of our 10% membership interest in ACP at book value for $13.9 million, whereby our interest in ACP was reduced to 7%. Summarized financial information provided to us by ACP for 100% of ACP as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016 and 2015, is presented below. Information for 2014 is not applicable as ACP was formed on September 2, 2014.
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Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract] | |
Variable Interest Entities | Variable Interest Entities On a quarterly basis, we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) as defined by the authoritative guidance on consolidation, and if so, which party is the primary beneficiary. As of October 31, 2016, we have determined that we are not the primary beneficiary under VIE accounting guidance in any of our equity method investments, as discussed in Note 11. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance, and we will continue to apply equity method accounting to these investments. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity, as presented in Note 11. We have also reviewed various lease arrangements, contracts to purchase, sell or deliver natural gas and other agreements in which we hold a variable interest. In these cases, we have determined that we are not the primary beneficiary of the related VIE because we do not have the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, or the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. |
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Segments | Business Segments Effective with the consummation of the Acquisition, our reportable segments changed based on information used by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Our sole reportable segment is now Gas Utilities and Infrastructure, which includes local gas distribution as state regulated utilities, gas pipeline investments and other gas investments. We evaluate the performance of the gas distribution business, including the operations of merchandising and its related service work and home service agreements, based on segment income, which is defined as income from continuing operations. Although the state regulated operations of our Gas Utilities and Infrastructure segment are located in three states under the jurisdiction of individual state regulatory commissions, the operations are managed as one unit having similar economic and risk characteristics. The remainder of our operations is presented in Other, which is primarily composed of our equity method investment in SouthStar that was held by a wholly owned subsidiary prior to the sale of our entire membership interest in SouthStar to GNGC on October 3, 2016, contributions to the Piedmont Natural Gas Foundation and certain Acquisition-related expenses. See Note 11 for further information on the sale of SouthStar. All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues. Prior periods' segment information has been reclassified to conform to the current year presentation. None of these segment changes impact our reported consolidated revenues or net income. Segment assets as presented in the tables that follow exclude all intercompany assets. Operations by segment for the years ended October 31, 2016, 2015 and 2014, and related assets as of October 31, 2016, 2015 and 2014, are presented below.
Products and Services The following table summarizes revenues of our Gas Utilities and Infrastructure segment by type.
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Related Party Transactions with Duke Energy |
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Related Party Transactions [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions with Duke Energy | Related Party Transactions with Duke Energy Effective with the consummation of the Acquisition on October 3, 2016, we engage in related party transactions with Duke Energy and its subsidiary registrants in accordance with applicable state and federal regulations. Upon consummation of the Acquisition, our 2018 plan was converted to a Duke Energy RSU Award. Related to this conversion, $6.1 million is included in "Accounts payable to affiliated companies" within "Current Liabilities" on the Consolidated Balance Sheets. See Note 9 for further information. Amounts related to transactions with Duke Energy occurring subsequent to the consummation of the Acquisition are included in the Consolidated Statements of Operations and Comprehensive Income for the year ended October 31, 2016. The following financial information reflects amounts for the years ended October 31, 2016, 2015 and 2014 related to transactions, assuming the Acquisition had taken place November 1, 2013.
See Note 10 for discussion of related party income taxes. |
Severance |
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Oct. 31, 2016 | |
Restructuring Charges [Abstract] | |
Severance | Severance In conjunction with the Acquisition, certain Piedmont senior executives terminated their employment from Piedmont effective with the closing of the Acquisition. The severance benefits owed to these executives were provided under contracts between the individual and Piedmont, effective upon a change in control. These severances will be paid in April 2017. In September 2016, Piedmont announced a severance plan covering certain eligible employees whose employment will be involuntarily terminated without cause during the twelve-month period (or twenty-four months for certain senior level employees) following the close of the Acquisition. Upon the close of the Acquisition, positions within Piedmont began to be eliminated. These reductions are a part of the synergies expected to be realized with the Acquisition. The severance benefit payments will be made in accordance with the severance plan. We recorded $18.7 million severance and related expenses that are included in "Operations, maintenance and other" on the Consolidated Statements of Operations and Comprehensive Income for the year ended October 31, 2016. The severance liability was also $18.7 million as of October 31, 2016 and is included in "Other" within "Current Liabilities" on the Consolidated Balance Sheets. Additional accruals can continue through October 3, 2018 as more positions are eliminated. |
Reclassification of Consolidated Financial Statements |
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Oct. 31, 2016 | |
Accounting Changes and Error Corrections [Abstract] | |
Reclassification of Consolidated Financial Statements | Reclassification of Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows Reclassifications have been made to prior year Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows. In the first quarter of 2016, we early adopted ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. With the retrospective adoption of the new pronouncement, the fiscal year 2015 current line item of "Deferred income taxes" of $32.4 million was reclassified to net with the noncurrent line item "Deferred income taxes," similarly reducing "Total Assets" and "Total Liabilities and Equity." Reclassifications have also been made to conform to the presentation currently used by Piedmont’s new parent company, Duke Energy. None of these reclassifications had a significant effect on the previously reported results of operations, financial position or cash flows of Piedmont but were rather the movement of line items or accounts to conform to Duke Energy’s presentation. The effect on our Consolidated Statements of Operations and Comprehensive Income was largely related to the statement presentation. Piedmont previously used a utility income statement presentation showing a line item of "Margin" on the face of the income statement that is defined as natural gas revenues less natural gas commodity and fixed gas costs. With Duke Energy’s presentation, the line item of "Cost of natural gas" is presented within "Operating Expenses" with no presentation of regulated margin. See the discussion of regulated margin in "Results of Operations" presented in Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in this Form 10-K. Also, we reclassified previously reported utility income taxes of $76.9 million and $83.2 million from line item "Total operating expenses" and non-utility income taxes of $13.3 million and $11.6 million from line item “Total other income (expense)” to the new line item "Income Tax Expense" for the years ended October 31, 2015 and 2014, respectively. These two changes in presentation had no effect on net income. The effect on our Consolidated Statements of Cash Flows for the years ended October 31, 2015 and 2014 reflects the reclassifications of the balance sheet line items. These reclassifications had no effect on previously reported amounts for net cash provided by operating activities and by financing activities or net cash used in investing activities for the periods previously presented. |
Subsequent Events |
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Oct. 31, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. See Note 3 for information on subsequent event disclosure items related to regulatory matters. |
Quarterly Financial Data |
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Quarterly Financial Data | Quarterly Financial Data (In millions except per share amounts) (Unaudited) On October 3, 2016, the Acquisition of Piedmont by Duke Energy was consummated, with Piedmont surviving as a wholly owned subsidiary of Duke Energy. As a result of the Acquisition, the Consolidated Financial Statements for our fiscal year ended October 31, 2015 have been reclassified to conform to the presentation of Duke Energy, our parent. The following table reflects the reclassification of our Consolidated Statements of Operations and Comprehensive Income to conform to Duke Energy's presentation.
The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions and our regulated utility rate designs generally result in greater earnings during the winter months. Basic earnings per share were calculated using the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year. |
Summary Of Significant Accounting Policies (Policies) |
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Oct. 31, 2016 | |
Accounting Policies [Abstract] | |
Consolidation, Policy | The Consolidated Financial Statements of Piedmont have been prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) and under the rules of the Securities and Exchange Commission (SEC). The Consolidated Financial Statements reflect the accounts of Piedmont and its wholly owned subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation. Investments in non-utility activities, or joint ventures, are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. The Acquisition was recorded using the acquisition method of accounting. Under SEC regulations, Duke Energy elected to not apply push down accounting to the stand alone Piedmont financial statements. |
Use of Estimates, Policy | In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets, liabilities, revenues and expenses and the related disclosures, using historical experience and other assumptions that we believe are reasonable at the time. Our estimates may involve complex situations requiring a high degree of judgment in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities as of the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis. |
Rate-Regulated Basis of Accounting, Policy | Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by the regulatory commissions in the states in which we operate. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods. Generally, regulatory assets are amortized to expense and regulatory liabilities are amortized to income over the period authorized by our regulators. Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commissions during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that would result in an adjustment to net income or accumulated other comprehensive income (OCI). Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment of similar costs in our jurisdictions, recent rate orders to other regulated entities and the status of any pending or potential legislation that would affect the regulatory environment. |
Utility Plant and Depreciation, Policy | Utility plant is stated at original cost, including direct labor and materials, contractor costs, allocable overhead charges, such as engineering, supervision, corporate office salaries and expenses, pensions and insurance, and an allowance for funds used during construction (AFUDC) that is calculated under a formula prescribed by our state regulators. We apply the group method of accounting, where the costs of homogeneous assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. Major expenditures that last longer than a year and improve or lengthen the expected useful life of the overall property from original expectations that are recoverable in regulatory rate base are capitalized while expenditures not meeting these criteria are expensed as incurred. The costs of property retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery or refund through future rates. On certain assets, like land, that are nondepreciable, we record a gain or loss upon the disposal of the property Depreciation rates for utility plant are approved by our regulatory commissions. As authorized by our regulatory commissions, the estimated costs of removal on certain regulated properties are collected through depreciation expense through rates with a corresponding credit to accumulated depreciation. Our approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal for certain regulated properties. Therefore, through depreciation expense, we collect and record estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate. We compute depreciation expense using the straight-line method |
Allowance for Funds Used During Construction, Policy | AFUDC represents the estimated costs of funds from both debt and equity sources used to finance the construction of major projects and is capitalized for ratemaking purposes when the completed projects are placed in service. |
Cash and Cash Equivalents, Policy | We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents. With respect to cash, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows. |
Receivables and Allowance For Doubtful Accounts, Policy | Receivables consist of natural gas sales and transportation services, unbilled revenues, and other miscellaneous receivables, including merchandise and service work, construction related receivables and other miscellaneous receivables. We bill customers monthly with payment due within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, based on the aging of receivables and our historical and projected charge-off activity. We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the NCUC, the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA), we are authorized to recover actual uncollected gas costs through the purchased gas adjustment (PGA). |
Inventories, Policy | Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost. We maintain gas inventories on the basis of average cost. Injections into storage are priced at the purchase cost at the time of injection, and withdrawals from storage are priced at the weighted average purchase price in storage. The cost of gas in storage is recoverable under rate schedules approved by state regulatory commissions. Inventory activity is subject to regulatory review on an annual basis in gas cost recovery proceedings. |
Fair Value Measurements, Policy | We are able to classify fair value balances based on the observance of those inputs at the lowest level that is significant to the fair value measurement, in its entirety, in the following fair value hierarchy levels as set forth in the fair value guidance. In determining whether to categorize the fair value measurement of an instrument as Level 2 or Level 3, we must use judgment to assess whether we have the ability as of the measurement date to redeem an investment at its net asset value per share (NAV) in the near term. We consider when we might have the ability to redeem the investment by reviewing contractual restrictions in effect as of the investment date as well as any potential restrictions that the investee may impose. Regarding our benefit plans’ investments, "near term" is the ability to redeem an investment in no more than 180 days. Transfers between different levels of the fair value hierarchy may occur based on the level of observable inputs used to value the instruments for the period. These transfers represent existing assets or liabilities previously categorized as Level 1 or Level 2 for which the inputs to the estimate became less observable or assets and liabilities previously classified as Level 2 or Level 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the actual date of the event or change in circumstances causing the transfer. In the absence of actively quoted prices or if we believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In determining the fair value, we use a discounted cash flow technique to calculate our valuation. We incorporate the following inputs and assumptions in our model: contract volume, forward market prices from third-party pricing services with an evaluation of pricing information on active and inactive markets, price correlations, pricing projections, time value, fuel assumptions and credit adjusted risk free rate of return. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for fair value measurements and endeavor to utilize the best available information for the specific instrument, location or commodity being valued. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The carrying values of receivables, short-term debt, accounts payable, accrued interest and other current assets and liabilities approximate fair value as all amounts reported are to be collected or paid within one year. For some qualified pension plan assets, the determination of Level 2 assets was completed through a process of reviewing each individual security while consulting research and other metrics provided by investment managers, including a pricing matrix detailing the pricing source and security type, annual audited financial statements and a review of valuation policies and procedures used by the investment managers as well as our investment advisor. we have long-dated, fixed quantity natural gas supply contracts for our regulated utility operations which are accounted for as derivatives. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the marketplace. |
Goodwill, Policy | Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment, or more frequently if impairment indicators arise during the year. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. When we test goodwill, we use a fair value approach at a reporting unit level, generally equivalent to our operating segment as discussed in Note 13. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. |
Equity Method Investments, Policy | On a quarterly basis, or when events or changes in circumstances indicate, we evaluate our investments in our unconsolidated affiliates and long-lived assets for impairment. Each equity method investment is recorded at cost plus its post-acquisition contributions and earnings based on our ownership share less any distributions as received from the joint venture investment, and if applicable, less any impairment in value of the investment. Given the nature of our equity method investment, our assessment may include a discounted cash flow income approach, including consideration of qualitative factors or events or circumstances which could affect the fair value. To the extent the analysis indicates a decline in fair value, we consider both the severity and duration of any decline in our evaluation as to whether an other-than-temporary impairment (OTTI) has occurred. Our key inputs involve significant management judgments and estimates, including projections of the entity’s cash flows, selection of a discount rate and probability weighting of potential outcomes of any legal or regulatory proceedings or other events affecting the investment. |
Long-Lived Assets, Policy | On a quarterly basis, or when events or changes in circumstances indicate, we evaluate our investments in our unconsolidated affiliates and long-lived assets for impairment. |
Marketable Securities, Policy | We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value on the Consolidated Balance Sheets in "Other" within "Investments and Other Assets" with any gains or losses recognized currently in earnings. The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. |
Issuances and Repurchases of Common Stock, Policy | we have repurchased shares on the open market and such shares were then canceled and became authorized but unissued shares. It was our policy to issue new shares for share-based employee awards and shareholder and employee investment plans. |
Asset Retirement Obligations, Policy | We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated. The NCUC, the PSCSC and the TRA have approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate |
Unamortized Debt Expense, Policy | Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, accountant fees, registration fees and rating agency fees, related to issuing long-term debt and the short-term syndicated revolving credit facility. We amortize long-term debt expense on a straight-line basis, which approximates the effective interest method, over the life of the related debt We amortize bank debt expense over the life of the syndicated revolving credit facility Should we reacquire long-term debt prior to its term date and simultaneously issue new debt, we defer the gain or loss resulting from the transaction, essentially the remaining unamortized debt expense, and amortize it over the life of the new debt in accordance with established regulatory practice. Where the refunding of the debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt as a regulatory asset or liability and amortize it over the remaining life of the redeemed debt in accordance with established regulatory practice. For income tax purposes, any gain or loss would be recognized as incurred. |
Revenue Recognition, Policy | Under the terms of the agreements, we receive asset management fees, which are recorded as secondary market transactions and shared between our utility customers and us. Non-regulated merchandise and service work includes the sale, installation and/or maintenance of natural gas appliances and gas piping beyond the meter. Revenue is recognized when the sale is made or the work is performed. If the customer is eligible for and elects financing through us, the finance fee income is recognized on a monthly basis based on principal, rate and term. Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. Utility sales, transportation and secondary market revenues are reported net of excise taxes, sales taxes and franchise fees. We record revenues when services are provided to our distribution service customers. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to jurisdictional customers may not be changed without approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA provisions. Secondary market revenues associated with the commodity are recognized when the physical sales are delivered based on contract or market prices. Asset management fees for storage and transportation remitted on a monthly basis are recognized as earned given the monthly capacity costs associated with the contracts involved. Asset management fees remitted in a lump sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. |
Cost of Gas and Deferred Purchased Gas Adjustments, Policy | We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms as set by the regulatory commissions in states in which we operate. Rate schedules for utility sales and transportation customers include PGA provisions that provide for the recovery of prudently incurred gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. We charge our secondary market customers for natural gas based on negotiated contract terms. Under PGA provisions, charges to cost of gas are based on the amount recoverable under approved rate schedules. Within our cost of natural gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives. We review gas costs and deferral activity periodically, including deferrals under the margin decoupling and WNA mechanisms, and with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period. |
Taxes, Policy | We have two categories of income taxes in the Consolidated Statements of Operations and Comprehensive Income: current and deferred. Current income tax expense consists of federal and state income taxes less applicable tax credits related to the current year. We amortize these deferred investment and energy tax credits to income over the estimated useful lives of the property to which the credits relate. We recognize accrued interest and penalties, if any, related to uncertain tax positions as operating expenses in the Consolidated Statements of Operations and Comprehensive Income. Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions. Property and other taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use and other miscellaneous taxes. Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred in accordance with rate-regulated accounting provisions, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders. |
Derivatives, Policy | We evaluate all of our gas supply contracts at inception to determine if they meet the definition of a derivative in accordance with accounting guidance, whether any derivative contracts qualify as "normal purchases and normal sales" and would not be subject to fair value accounting requirements, or if they can be designated for hedge accounting purposes. We have included gas supply contracts requiring fair value accounting in "Other" in "Current Liabilities" and "Deferred Credits and Other Liabilities" in the Consolidated Balance Sheets. As these contracts have been entered into for our regulated utility operations, and as commodity costs are recoverable through our PGA clauses in the jurisdictions in which we operate, we have recorded the offset to an applicable regulatory asset. |
Variable Interest Entities, Policy | On a quarterly basis, we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) as defined by the authoritative guidance on consolidation, and if so, which party is the primary beneficiary. |
Segment Reporting, Policy | Effective with the consummation of the Acquisition, our reportable segments changed based on information used by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Our sole reportable segment is now Gas Utilities and Infrastructure, which includes local gas distribution as state regulated utilities, gas pipeline investments and other gas investments. We evaluate the performance of the gas distribution business, including the operations of merchandising and its related service work and home service agreements, based on segment income, which is defined as income from continuing operations. Although the state regulated operations of our Gas Utilities and Infrastructure segment are located in three states under the jurisdiction of individual state regulatory commissions, the operations are managed as one unit having similar economic and risk characteristics. The remainder of our operations is presented in Other, which is primarily composed of our equity method investment in SouthStar that was held by a wholly owned subsidiary prior to the sale of our entire membership interest in SouthStar to GNGC on October 3, 2016, contributions to the Piedmont Natural Gas Foundation and certain Acquisition-related expenses. |
Subsequent Events, Policy | We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. |
Summary Of Significant Accounting Policies (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Oct. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounting Policies [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Public Utility Property, Plant, and Equipment | The classification of net property, plant and equipment for the years ended October 31, 2016 and 2015 is presented below.
AFUDC for the years ended October 31, 2016, 2015 and 2014 is presented below.
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Schedule of Trade Account Receivables | As of October 31, 2016 and 2015, our receivables and allowance for doubtful accounts consisted of the following.
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Schedule of Changes in Allowance for Doubtful Accounts | A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2016, 2015 and 2014 is presented below.
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Schedule of Marketable Securities | The composition of these securities as of October 31, 2016 and 2015 is as follows.
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Schedule of Asset Retirement Obligations | The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 2016 and 2015 are presented below.
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Schedule of Change in Asset Retirement Obligation | A reconciliation of the changes in conditional AROs for the year ended October 31, 2016 and 2015 is presented below.
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Schedule of New Accounting Pronouncements | Recently Issued Accounting Guidance
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Acquisition by Duke Energy Corporation (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Oct. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Combinations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule Of Merger And Integration Costs | The following table summarizes pre-tax acquisition consummation costs, integration and other related costs (collectively referred to as costs to achieve) that we recorded in connection with the Acquisition and are included in "Operations, maintenance and other" within "Operating Expenses" in the Consolidated Statements of Operations and Comprehensive Income for the years ended October 31, 2016 and 2015.
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Regulatory Matters (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Public Utilities, Rate Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets | Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2016 and 2015 are as follows.
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Schedule of Regulatory Liabilities | Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2016 and 2015 are as follows.
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Schedule of Secondary Market Activity | This sharing mechanism for secondary market activity in all three jurisdictions for the twelve months ended October 31, 2016, 2015, and 2014 is presented below.
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Common Stock (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Stockholders' Equity Note [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Common Stock Outstanding Roll Forward | Changes in common stock for the years ended October 31, 2016, 2015 and 2014 are as follows.
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Schedule of Forward Contracts Indexed to Issuer's Equity | The table below presents equity transactions that were settled in shares under the open registration statements over the two-year period ended October 31, 2016.
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Schedule of Accumulated Other Comprehensive Income (Loss) | Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2016 and 2015.
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Reclassification out of Accumulated Other Comprehensive Income | A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended October 31, 2016 and 2015.
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Debt and Credit Facilities (Tables) |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Long-term Debt Instruments | The tables below reflect the detail of this presentation for our long-term debt as of October 31, 2016 and 2015.
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Schedule of Maturities of Long-term Debt | Current maturities for the next five years ending October 31 and thereafter are as follows.
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Schedule of Short-term Debt Activities | A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2016 is as follows.
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Financial Instruments & Related Fair Value (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Oct. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Financial Instruments & Related Fair Value [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of October 31, 2016 and 2015. We have had no transfers between any level during the years ended October 31, 2016 and 2015.
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Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation | The following is a reconciliation of the gas supply derivative liabilities that are classified as Level 3 in the fair value hierarchy for the twelve months ended October 31, 2016.
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Amount Of Gain Loss Recognized On Derivatives And Deferred Under PGA Procedures | The following table presents the impact that our gas purchase options not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended October 31, 2016 and 2015, absent the regulatory treatment under our approved PGA procedures.
The following table presents the fair value and balance sheet classification of our gas purchase options and gas supply derivative contracts for natural gas as of October 31, 2016 and 2015.
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Fair Value, by Balance Sheet Grouping | The principal and fair value of our long-term debt, which is classified within Level 2, are shown below.
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Commitments & Contingencies (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Oct. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Operating Lease Payments | Operating lease payments for the years ended October 31, 2016, 2015 and 2014 are as follows.
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Schedule of Future Minimum Rental Payments for Operating Leases | Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.
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Schedule of Future Unconditional Purchase Obligations | As of October 31, 2016, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.
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Employee Benefit Plans (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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General Discussion of Pension and Other Postretirement Benefits [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Defined Benefit Plans Disclosures | We anticipate that we will contribute the following amounts to our plans during the twelve month period ending October 31, 2017.
The target and actual allocations of the OPEB plan's assets are as follows.
A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2016 and 2015, a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2016 and 2015, and the weighted average assumptions used in the measurement of the benefit obligations as of October 31, 2016 and 2015 are presented below.
The 2017 estimated amortization of the following items for our plans, which are recorded as a regulatory asset or liability instead of accumulated OCIL discussed above, are as follows.
The target and actual allocations of the qualified pension plan's assets are as follows.
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Supplemental Executive Retirement Plans | Our funding to the DCR plan account for the years ended October 31, 2016 and 2015, and the amounts recorded as liabilities for these two deferred compensation plans as of October 31, 2016 and 2015, are presented below.
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Components Of Net Periodic Benefit Cost | Net periodic benefit cost components for the years ended October 31, 2016, 2015 and 2014 and the weighted average assumptions used to determine net period benefit cost as of October 31, 2016, 2015 and 2014 are presented below.
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Expected Benefit Payments For The Next Ten Years | Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.
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Redemption Limitations, Restrictions and Notice Requirements | As stated above, some of our investments for the qualified pension plan have redemption limitations, restrictions and notice requirements which are further explained below.
(1) The investment cannot be redeemed. We receive distributions only through the liquidation of the underlying assets. The assets are expected to be liquidated over the next 8 to 10 years. |
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The Qualified Pension and The OPEB Plan's Asset Allocations By Level Within the Fair Value Hierarchy |
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Level 3 Qualified Pension Plan Reconciliation | The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.
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401(k) Matching Contributions | For the years ended October 31, 2016, 2015 and 2014, we made matching contributions to participant accounts as follows.
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Employee Share Based Plans (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Oct. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Share-based Compensation, Restricted Stock Units Award Activity | The following table summarizes the settlement of the RSUs.
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Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs | The compensation expense related to the awards under the ICP for the years ended October 31, 2016, 2015 and 2014, and the amounts recorded as liabilities in "Other deferred credits and other liabilities" within "Deferred Credits and Other Liabilities" with the current portion recorded in "Other current liabilities" within "Current Liabilities" on the Consolidated Balance Sheets as of October 31, 2016 and 2015 are presented below.
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Income Taxes (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Income Tax Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Components of Income Tax Expense (Benefit) | The components of income tax expense for the years ended October 31, 2016, 2015 and 2014 are presented below.
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Schedule of Effective Income Tax Rate Reconciliation | A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2016, 2015 and 2014 is presented below.
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Schedule of Deferred Tax Assets and Liabilities | As of October 31, 2016 and 2015, deferred income taxes consists of the following temporary differences.
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Summary of Valuation Allowance | A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2016, 2015 and 2014 is presented below.
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Summary of Operating Loss Carryforwards | The following table presents the expiration of tax carryforwards.
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Schedule of Changes to Corporate State Income Tax Rates | The following table presents the corporate income tax rates resulting from this legislation, including subsequent reductions based on certain tax collections exceeding certain thresholds under North Carolina tax statutes.
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Investments in Unconsolidated Affiliates (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Equity Method Investments and Joint Ventures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Equity Method Investments | For the years ended October 31, 2016, 2015 and 2014, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2016 and 2015, are as follows.
Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.
As of October 31, 2016 and 2015, our investment balances are as follows.
For the years ended October 31, 2016, 2015 and 2014, we recorded our proportionate share of earnings or losses from these unconsolidated affiliates in "Equity in earnings of unconsolidated affiliates" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income as follows.
Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.
For the years ended October 31, 2016, 2015 and 2014, these gas costs and the amounts we owed to our unconsolidated affiliates, as of October 31, 2016 and 2015, are as follows.
Summarized financial information provided to us by ACP for 100% of ACP as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016 and 2015, is presented below. Information for 2014 is not applicable as ACP was formed on September 2, 2014.
We have the following membership interests in these companies as of October 31, 2016.
Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.
Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2016 and 2015, and for the twelve months ended October 31, 2016, 2015 and 2014, is presented below.
Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.
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Business Segments (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Oct. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Segment Data | Operations by segment for the years ended October 31, 2016, 2015 and 2014, and related assets as of October 31, 2016, 2015 and 2014, are presented below.
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Schedule of Revenue, By Products and Services | The following table summarizes revenues of our Gas Utilities and Infrastructure segment by type.
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Related Party Transactions with Duke Energy (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Oct. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Related Party Transactions | The following financial information reflects amounts for the years ended October 31, 2016, 2015 and 2014 related to transactions, assuming the Acquisition had taken place November 1, 2013.
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Quarterly Financial Data (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Oct. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Quarterly Financial Data [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Quarterly Financial Information | The following table reflects the reclassification of our Consolidated Statements of Operations and Comprehensive Income to conform to Duke Energy's presentation.
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Summary Of Significant Accounting Policies (Details) - USD ($) |
1 Months Ended | 12 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|---|
Apr. 30, 2014 |
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
Oct. 31, 2016 |
Oct. 03, 2016 |
Oct. 31, 2015 |
Dec. 31, 2013 |
Oct. 31, 2012 |
|
Public Utilities, Property, Plant and Equipment, Net [Abstract] | |||||||||
Intangible plant | $ 3,400,000 | $ 3,400,000 | |||||||
Other storage plant | 189,100,000 | 181,000,000 | |||||||
Transmission plant | 2,315,800,000 | 2,024,300,000 | |||||||
Distribution plant | 2,864,700,000 | 2,766,900,000 | |||||||
General plant | 469,700,000 | 452,300,000 | |||||||
Asset retirement cost | 0 | 4,100,000 | |||||||
Contributions in aid of construction | (5,600,000) | (5,400,000) | |||||||
Total utility plant in service | 5,837,100,000 | 5,426,600,000 | |||||||
Construction work in progress | 233,000,000 | 170,300,000 | |||||||
Plant held for future use | 7,700,000 | 3,100,000 | |||||||
Other property | 1,300,000 | 1,300,000 | |||||||
Total Cost | 6,079,100,000 | 5,601,300,000 | |||||||
Utility plant in service accumulated depreciation | (1,328,600,000) | (1,252,000,000) | |||||||
Other property accumulated depreciation and amortization | (900,000) | (900,000) | |||||||
Accumulated depreciation and amortization | (1,329,500,000) | (1,252,900,000) | |||||||
Net property, plant and equipment | 4,749,600,000 | 4,348,400,000 | |||||||
Public Utilities, Property, Plant and Equipment [Abstract] | |||||||||
Allowance for borrowed funds used during construction | $ 12,300,000 | $ 11,100,000 | $ 16,400,000 | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||
Plant held for future use | 7,700,000 | 3,100,000 | |||||||
Transfer From Construction Work In Progress to Plant Held For Future Use | $ 4,600,000 | ||||||||
Composite weighted-average depreciation rates | 2.44% | 2.48% | 2.54% | ||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Regulatory Assets | 487,000,000 | 215,800,000 | |||||||
Regulatory Assets, Current | 113,700,000 | 19,100,000 | |||||||
Accounts, Notes, Loans and Financing Receivable, Net, Current [Abstract] | |||||||||
Gas receivables | 43,100,000 | 57,600,000 | |||||||
Unbilled revenues | 13,400,000 | 17,400,000 | |||||||
Other miscellaneous receivables | 20,600,000 | 13,500,000 | |||||||
Allowance for doubtful accounts | $ (1,600,000) | $ (2,200,000) | $ (1,600,000) | (1,900,000) | (1,600,000) | ||||
Receivables and Allowance for Doubtful Accounts | 75,200,000 | 86,900,000 | |||||||
Customers Payment Due Date | 30 days | ||||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||||||||
Balance at beginning of year | $ (1,600,000) | (2,200,000) | (1,600,000) | ||||||
Additions charged to uncollectibles expense | 4,900,000 | 5,100,000 | 7,000,000 | ||||||
Accounts written off, net of recoveries | (4,600,000) | (5,700,000) | (6,400,000) | ||||||
Balance at end of year | (1,900,000) | (1,600,000) | (2,200,000) | ||||||
Inventory, Net [Abstract] | |||||||||
Natural Gas Inventories Not Available For Sale Held by Asset Manager | $ 21,300,000 | 24,800,000 | |||||||
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract] | |||||||||
Near Term Redemption | 180 days | ||||||||
Goodwill and Intangible Assets Disclosure [Abstract] | |||||||||
Goodwill, Impairment Loss | $ 0 | 0 | 0 | ||||||
Impairment charges | $ 2,000,000 | 0 | 0 | ||||||
Schedule of Trading Securities and Other Trading Assets [Line Items] | |||||||||
Total trading securities (cost) | 3,700,000 | 4,300,000 | |||||||
Marketable Securities | 4,200,000 | 4,900,000 | |||||||
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items] | |||||||||
Conditional AROs | 14,100,000 | 19,700,000 | |||||||
Total cost of removal obligations | 552,100,000 | 541,200,000 | |||||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||||||
Beginning of period | 19,700,000 | 14,700,000 | |||||||
Liabilities incurred during the period | 5,500,000 | 4,700,000 | |||||||
Liabilities settled during the period | (6,500,000) | (5,600,000) | |||||||
Accretion | 1,100,000 | 900,000 | |||||||
Adjustment to estimated cash flows | (5,700,000) | 5,000,000 | |||||||
End of period | $ 14,100,000 | $ 19,700,000 | $ 14,700,000 | ||||||
Regulatory Liabilities [Line Items] | |||||||||
Regulatory liabilities | 617,000,000 | 590,300,000 | |||||||
Debt Amortization Period [Abstract] | |||||||||
Long Term Debt Expense Amortization Period | 5 to 30 years | ||||||||
Short Term Debt Expense Amortization Period | 5 years | ||||||||
North Carolina Utilities Commission | |||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||
Depreciation Study Requirement | 5 years | ||||||||
Minimum | |||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||
Property, Plant and Equipment, Useful Life | 5 years | ||||||||
Maximum | |||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||
Property, Plant and Equipment, Useful Life | 80 years | ||||||||
Asset Retirement Obligation | |||||||||
Regulatory Liabilities [Line Items] | |||||||||
Regulatory liabilities | 538,000,000 | 521,500,000 | |||||||
Robeson LNG development costs | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Regulatory Assets, Current | 100,000 | 400,000 | |||||||
Robeson LNG development costs | General Rate Application Settlement 2013 | North Carolina Utilities Commission | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Regulatory Assets | $ 1,200,000 | ||||||||
Regulatory Asset, Amortization Period | 38 months | ||||||||
Regulatory Noncurrent Asset, End Date for Recovery | Feb. 28, 2017 | ||||||||
Land | |||||||||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | |||||||||
Plant held for future use | $ 3,200,000 | ||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||
Plant held for future use | 3,200,000 | ||||||||
Non-real Estate Costs | |||||||||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | |||||||||
Plant held for future use | 3,500,000 | ||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||
Plant held for future use | $ 3,500,000 | ||||||||
Asset Retirement Obligation | Minimum | |||||||||
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items] | |||||||||
Fair Value Assumptions, Risk Free Interest Rate | 4.62% | ||||||||
Asset Retirement Obligation | Maximum | |||||||||
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items] | |||||||||
Fair Value Assumptions, Risk Free Interest Rate | 5.89% | ||||||||
Asset Retirement Obligation | Weighted Average | |||||||||
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items] | |||||||||
Fair Value Assumptions, Risk Free Interest Rate | 5.69% | ||||||||
South Star Energy Services | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Equity Method Investment, Ownership Percentage Sold | 15.00% | ||||||||
Money Market Funds | |||||||||
Schedule of Trading Securities and Other Trading Assets [Line Items] | |||||||||
Total trading securities (cost) | 500,000 | 500,000 | |||||||
Marketable Securities | 500,000 | 500,000 | |||||||
Equity Funds | |||||||||
Schedule of Trading Securities and Other Trading Assets [Line Items] | |||||||||
Total trading securities (cost) | 3,200,000 | 3,800,000 | |||||||
Marketable Securities | $ 3,700,000 | $ 4,400,000 |
Acquisition by Duke Energy Corporation (Details) - USD ($) $ / shares in Units, $ in Millions |
12 Months Ended | |||||
---|---|---|---|---|---|---|
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
Oct. 03, 2016 |
|||
Class of Stock [Line Items] | ||||||
Common stock shares outstanding | 80,900,000 | |||||
Public Utilities, General Disclosures [Line Items] | ||||||
Regulated natural gas revenue | [1] | $ 1,131.6 | $ 1,371.7 | $ 1,470.0 | ||
Business Acquisition, Share Price | $ 60 | |||||
Financial and legal advisory costs | 22.4 | 8.6 | ||||
Severance Charges | 18.7 | |||||
Charitable Contributions and Community Support | 8.8 | |||||
Acceleration of incentive plans | 5.3 | |||||
Key employee retention payments | 3.5 | |||||
Other Integration Related Costs | 2.9 | |||||
Acquisition and Integration Related Costs | $ 61.6 | $ 8.6 | ||||
Successor | ||||||
Class of Stock [Line Items] | ||||||
Common Stock, Shares, Issued | 100 | |||||
Common stock shares outstanding | 100 | |||||
North Carolina Utilities Commission | Approved Stipulation and Settlement Agreement September 2016 [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Annual Charitable Contributions Commitment | $ 17.5 | |||||
Low-Income Household Energy Assistance and Workforce Development Programs Commitment | 7.5 | |||||
One Time Customer Bill Credit | 10.0 | |||||
Regulated natural gas revenue | $ (4.7) | |||||
|
Regulatory Matters - Assets and Liabilities (Details) - USD ($) $ in Millions |
Oct. 31, 2016 |
Oct. 31, 2015 |
---|---|---|
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | $ 113.7 | $ 19.1 |
Regulatory Assets, Noncurrent | 373.3 | 196.7 |
Total Regulatory Assets | 487.0 | 215.8 |
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities, Current | 0.0 | 21.5 |
Regulatory liabilities, Noncurrent | 617.0 | 590.3 |
Regulatory Liabilities, Total | 617.0 | 611.8 |
Other Regulatory Assets On Which We Do Not Earn a Return | 344.9 | |
Amounts due to customers | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities, Current | 0.0 | 21.5 |
Regulatory cost of removal | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities, Noncurrent | 538.0 | 521.5 |
Deferred income taxes | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities, Noncurrent | 78.9 | 68.7 |
Amounts not yet recognized as a component of pension and other retirement benefit costs | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities, Noncurrent | 0.1 | 0.1 |
Unamortized debt expense on reacquired debt | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 0.2 | 0.2 |
Regulatory Assets, Noncurrent | 4.4 | 4.7 |
Amounts due from customers | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 61.9 | 8.2 |
Environmental costs | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 1.5 | 1.5 |
Regulatory Assets, Noncurrent | 3.6 | 5.1 |
Total Regulatory Assets | 5.1 | |
Deferred operations and maintenance expenses | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 0.9 | 0.8 |
Regulatory Assets, Noncurrent | 3.1 | 4.0 |
Deferred pipeline integrity expenses | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 3.5 | 3.5 |
Regulatory Assets, Noncurrent | 32.4 | 29.8 |
Deferred pension and other retirement benefit costs | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 2.8 | 2.8 |
Regulatory Assets, Noncurrent | 16.8 | 17.9 |
Amounts not yet recognized as a component of pension and other retirement benefit costs | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Noncurrent | 151.6 | 114.8 |
Regulatory cost of removal | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Noncurrent | 14.1 | 19.1 |
Amount Of Regulatory Costs Approved To Be Accrued Not Included In Rate Base | 14.1 | |
Robeson LNG development costs | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 0.1 | 0.4 |
Regulatory Assets, Noncurrent | 0.0 | 0.1 |
Derivatives - gas supply contracts held for utility operations | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 41.5 | 0.0 |
Regulatory Assets, Noncurrent | 146.4 | 0.0 |
Other | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | 1.3 | 1.7 |
Regulatory Assets, Noncurrent | $ 0.9 | $ 1.2 |
Regulatory Matters (Details) |
1 Months Ended | 12 Months Ended | 24 Months Ended | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Nov. 30, 2016
USD ($)
|
Oct. 31, 2016
USD ($)
|
Apr. 30, 2015
USD ($)
|
Apr. 30, 2014
USD ($)
|
Oct. 31, 2016
USD ($)
Integer
|
Oct. 31, 2015
USD ($)
|
Oct. 31, 2014
USD ($)
|
Oct. 31, 2013
USD ($)
|
Dec. 31, 2001
USD ($)
|
Dec. 31, 2000
USD ($)
|
Dec. 31, 1998
USD ($)
|
Dec. 31, 2001
USD ($)
|
Dec. 31, 2013
USD ($)
|
Aug. 31, 2013
USD ($)
|
Oct. 31, 2008
USD ($)
|
|
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets | $ 487,000,000 | $ 487,000,000 | $ 215,800,000 | ||||||||||||
Regulatory Assets, Current | $ 113,700,000 | $ 113,700,000 | 19,100,000 | ||||||||||||
Percentage Of Net Secondary Market Margins Flowed Through To Customers | 75.00% | 75.00% | |||||||||||||
Percentage Of Net Secondary Market Margins Retained | 25.00% | 25.00% | |||||||||||||
Allocated to customers as gas cost reductions | $ 52,000,000 | 60,100,000 | $ 72,200,000 | ||||||||||||
Margin allocated to us | 17,700,000 | 21,100,000 | 25,400,000 | ||||||||||||
Margin from secondary market activity | 69,700,000 | 81,200,000 | 97,600,000 | ||||||||||||
Percentage Of Net Secondary Market Margin Credited To Customers for Transactions with Duke Energy | 100.00% | ||||||||||||||
North Carolina Utilities Commission | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Debt Equity Securities Limit, Amount | $ 1,000,000,000 | ||||||||||||||
North Carolina Utilities Commission | Maximum | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Target Percentage Range Normalized Sales | 45.00% | ||||||||||||||
North Carolina Utilities Commission | EasternNC Exclusive Franchise Rights | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
North Carolina Bond Issuance Amount | $ 149,600,000 | $ 38,700,000 | $ 188,300,000 | ||||||||||||
Operational Feasibility Assessment Time Period | 2 years | ||||||||||||||
North Carolina Utilities Commission | North Carolina Public Staff Audit 2014 Gas Cost Review Period | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Percentage Of Allowed Recovery For Gas Costs | 100.00% | ||||||||||||||
North Carolina Utilities Commission | North Carolina Public Staff Audit 2015 Gas Cost Review Period | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Percentage Of Allowed Recovery For Gas Costs | 100.00% | ||||||||||||||
North Carolina Utilities Commission | North Carolina Public Staff Audit 2016 Gas Cost Review Period | Subsequent Event | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Percentage Of Allowed Recovery For Gas Costs | 100.00% | ||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Public Utilities, Disclosure of Rate Matters | In November 2016, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2016. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery. | ||||||||||||||
North Carolina Utilities Commission | North Carolina IMR Adjustment 2014 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 800,000 | ||||||||||||||
North Carolina Utilities Commission | NCUC Petition for IMR Rate Adjustment Filed December 2014 | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 26,600,000 | ||||||||||||||
North Carolina Utilities Commission | NCUC Public Staff Agreement September 2015 | Transmission Integrity | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Recovery Percentage Of System Integrity Expenditures Through IMR | 85.00% | ||||||||||||||
Recovery Percentage Of System Integrity Expenditures Through Rate Case | 15.00% | ||||||||||||||
North Carolina Utilities Commission | NCUC Public Staff Agreement September 2015 | Distribution Integrity | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Recovery Percentage Of System Integrity Expenditures Through IMR | 90.00% | ||||||||||||||
Recovery Percentage Of System Integrity Expenditures Through Rate Case | 10.00% | ||||||||||||||
North Carolina Utilities Commission | NCUC Public Staff Agreement September 2015 | Right Of Way Clearing | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Recovery Percentage Of System Integrity Expenditures Through IMR | 15.00% | ||||||||||||||
Recovery Percentage Of System Integrity Expenditures Through Rate Case | 85.00% | ||||||||||||||
North Carolina Utilities Commission | NCUC Public Staff Agreement September 2015 | Work and Asset Management System | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Recovery Percentage Of System Integrity Expenditures Through IMR | 68.00% | ||||||||||||||
Recovery Percentage Of System Integrity Expenditures Through Rate Case | 32.00% | ||||||||||||||
North Carolina Utilities Commission | IMR Petition Filed May 2016 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 7,400,000 | ||||||||||||||
North Carolina Utilities Commission | IMR Petition Filed October 2016 | Subsequent Event | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 8,200,000 | ||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Public Utilities, Disclosure of Rate Matters | In October 2016, we filed a petition to adjust our rates effective December 1, 2016 to collect an additional $8.2 million in annual IMR margin revenues from that approved by the NCUC in May 2016. The December 2016 rate adjustment was based on IMR-eligible capital investments in integrity and safety projects through September 30, 2016, which total $513.1 million since inception of the IMR mechanism. In November 2016, the NCUC approved the requested rate increase. | ||||||||||||||
North Carolina Utilities Commission | NCUC Open Shelf Registration Statement April 2014 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Debt Equity Securities Limit, Amount | $ 1,000,000,000 | ||||||||||||||
North Carolina Utilities Commission | NCUC Approved Customer Bill Credit March 2015 | Amounts due to customers | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Increase (Decrease) in Regulatory Liabilities | $ (45,500,000) | ||||||||||||||
North Carolina Utilities Commission | IMR Petition Filed November 2015 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 13,400,000 | ||||||||||||||
Public Service Commission of South Carolina | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Maximum Utility Rate of Return Change Allowed Under RSA | Integer | 50 | ||||||||||||||
Public Service Commission of South Carolina | Maximum | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Target Percentage Range Normalized Sales | 45.00% | ||||||||||||||
Public Service Commission of South Carolina | Settlement With Office of Regulatory Staff October 2014 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ (2,900,000) | ||||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 10.20% | ||||||||||||||
Public Service Commission of South Carolina | Settlement With Office Of Regulatory Staff October 2015 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 1,650,000 | ||||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 10.20% | ||||||||||||||
Public Service Commission of South Carolina | Settlement With Office Of Regulatory Staff October 2016 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 8,300,000 | ||||||||||||||
Public Utilities, Approved Return on Equity, Percentage | 10.20% | ||||||||||||||
Tennessee Regulatory Authority | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Annual Incentive Cap On Gains And Losses | $ 1,600,000.0 | ||||||||||||||
Tennessee Regulatory Authority | Tennessee IMR Petition August 2013 | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 13,100,000 | ||||||||||||||
Tennessee Regulatory Authority | Tennessee IMR Settlement 2013 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 13,100,000 | ||||||||||||||
Tennessee Regulatory Authority | TRA IMR Order February 2015 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 6,500,000 | ||||||||||||||
Tennessee Regulatory Authority | TRA IMR Order February 2016 [Member] | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 1,700,000 | ||||||||||||||
Tennessee Regulatory Authority | TRA Petition Filed IMR November 2016 | Subsequent Event | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 1,700,000 | ||||||||||||||
Public Utilities, Disclosure of Rate Matters | In November 2016, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue effective January 2017 based on $20.1 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2016. We are waiting on a ruling from the TRA at this time. | ||||||||||||||
Tennessee Regulatory Authority | TRA Petition to Amortize and Refund Customers for Excess Deferred Taxes | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | (4,700,000) | ||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | (4,700,000) | ||||||||||||||
Tennessee Regulatory Authority | Tennessee CNG Order October 2015 | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Deferral CNG Equipment In Utility Rate Base | 4,700,000 | ||||||||||||||
North Carolina | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
North Carolina Bond Issuance Amount | $ 200,000,000 | ||||||||||||||
Capital Investments in Integrity and Safety Projects I | $ 513,100,000 | 513,100,000 | |||||||||||||
Tennessee | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Capital Investments In Integrity and Safety Projects | 20,100,000 | 18,400,000 | 54,000,000 | $ 100,400,000 | |||||||||||
Deferred operations and maintenance expenses | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets, Current | 900,000 | $ 900,000 | 800,000 | ||||||||||||
Deferred operations and maintenance expenses | North Carolina Utilities Commission | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Deferral Time Period Of Operation And Maintenance Expense | 8 years | ||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets | 4,000,000 | $ 4,000,000 | 4,800,000 | ||||||||||||
Deferred operations and maintenance expenses | North Carolina Utilities Commission | General Rate Case Proceeding 2008 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Regulatory Asset, Amortization Period | 12 years | ||||||||||||||
Interest Accrued On Deferred Expenses | 7.84% | ||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets | $ 9,000,000 | ||||||||||||||
Deferred operations and maintenance expenses | North Carolina Utilities Commission | General Rate Application Settlement 2013 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Regulatory Asset, Amortization Period | 82 months | ||||||||||||||
Interest Accrued On Deferred Expenses | 6.55% | ||||||||||||||
Regulatory Noncurrent Asset, End Date for Recovery | Oct. 31, 2020 | ||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets | $ 6,300,000 | ||||||||||||||
Deferred pipeline integrity expenses | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets, Current | 3,500,000 | $ 3,500,000 | 3,500,000 | ||||||||||||
Deferred pipeline integrity expenses | North Carolina Utilities Commission | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets | 35,900,000 | $ 35,900,000 | 33,300,000 | ||||||||||||
Deferred pipeline integrity expenses | North Carolina Utilities Commission | General Rate Application Settlement 2013 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Regulatory Asset, Amortization Period | 5 years | ||||||||||||||
Regulatory Noncurrent Asset, End Date for Recovery | Dec. 31, 2018 | ||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets | $ 17,300,000 | ||||||||||||||
Environmental costs | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets | 5,100,000 | $ 5,100,000 | |||||||||||||
Regulatory Assets, Current | 1,500,000 | $ 1,500,000 | 1,500,000 | ||||||||||||
Environmental costs | North Carolina Utilities Commission | General Rate Application Settlement 2013 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Regulatory Asset, Amortization Period | 5 years | ||||||||||||||
Regulatory Noncurrent Asset, End Date for Recovery | Dec. 31, 2018 | ||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets | 6,300,000 | ||||||||||||||
Environmental costs | Public Service Commission of South Carolina | Settlement With Office of Regulatory Staff October 2014 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Regulatory Asset, Amortization Period | 1 year | ||||||||||||||
Regulatory Current Asset, End Date for Recovery | October 31, 2015 | ||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets, Current | 100,000 | ||||||||||||||
Robeson LNG development costs | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets, Current | 100,000 | $ 100,000 | 400,000 | ||||||||||||
Robeson LNG development costs | North Carolina Utilities Commission | General Rate Application Settlement 2013 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Regulatory Asset, Amortization Period | 38 months | ||||||||||||||
Regulatory Noncurrent Asset, End Date for Recovery | Feb. 28, 2017 | ||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets | $ 1,200,000 | ||||||||||||||
Robeson LNG development costs | Public Service Commission of South Carolina | Settlement With Office of Regulatory Staff October 2014 | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Regulatory Asset, Amortization Period | 12 months | ||||||||||||||
Regulatory Current Asset, End Date for Recovery | October 31, 2015 | ||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets, Current | $ 500,000 | ||||||||||||||
Other | |||||||||||||||
Public Utilities, Rate Matters, Requested [Abstract] | |||||||||||||||
Regulatory Assets, Current | $ 1,300,000 | $ 1,300,000 | $ 1,700,000 |
Common Stock (Details) - USD ($) |
1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Sep. 30, 2016 |
Oct. 31, 2015 |
Oct. 31, 2016 |
Jul. 31, 2016 |
Apr. 30, 2016 |
Jan. 31, 2016 |
Oct. 31, 2015 |
Jul. 31, 2015 |
Apr. 30, 2015 |
Jan. 31, 2015 |
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
Oct. 03, 2016 |
Jan. 07, 2015 |
|
Stockholders' Equity Note [Abstract] | |||||||||||||||
ATM Sales Agreement Amount Instant | $ 170,000,000 | ||||||||||||||
ATM Sales Agreement Commission Percentage | 1.50% | ||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||||||
Equity in earnings of unconsolidated affiliates | $ (28,600,000) | $ (34,500,000) | $ (32,800,000) | ||||||||||||
Income tax expense | 124,200,000 | 90,200,000 | 94,800,000 | ||||||||||||
Net income | $ (38,700,000) | $ 6,700,000 | $ (63,400,000) | $ (97,800,000) | $ 14,100,000 | $ 8,300,000 | $ (66,400,000) | $ (93,000,000) | (193,200,000) | (137,000,000) | (143,800,000) | ||||
Forward Contract Indexed to Issuer's Equity [Line Items] | |||||||||||||||
Payments of Stock Issuance Costs | $ 100,000 | $ 400,000 | |||||||||||||
Forward Contract Indexed to Issuer's Equity, Shares | 1,800,000 | 1,500,000 | |||||||||||||
Forward Contract Amount Recorded in Consolidated Financial Statements | 0 | 0 | |||||||||||||
Common Stock Issued, Value | $ 104,700,000 | $ 54,100,000 | $ 138,500,000 | $ 85,000,000 | 75,200,000 | ||||||||||
Class of Stock [Line Items] | |||||||||||||||
Business Acquisition, Share Price | $ 60 | ||||||||||||||
Common stock shares authorized | 200,000,000 | 200,000,000 | 200,000,000 | ||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||
Common Stock, Shares, Outstanding, Beginning Balance | 80,900,000 | 80,900,000 | |||||||||||||
Common Stock, Value, Issued, Beginning Balance | $ 721,400,000 | 636,800,000 | $ 721,400,000 | $ 636,800,000 | 561,600,000 | ||||||||||
Issued to participants in the Employee Stock Purchase Plan (ESPP) | 1,000,000 | 1,200,000 | 1,100,000 | ||||||||||||
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP) | 14,500,000 | 24,700,000 | 23,500,000 | ||||||||||||
Issued to participants in the Incentive Compensation Plan (ICP) | 18,300,000 | 5,000,000 | 3,300,000 | ||||||||||||
Issuance of common stock, net | 104,600,000 | $ 53,700,000 | 47,300,000 | ||||||||||||
Common Stock, Shares, Outstanding, Ending Balance | 80,900,000 | 80,900,000 | 80,900,000 | ||||||||||||
Common Stock, Value, Issued, Ending Balance | $ 721,400,000 | 859,800,000 | $ 721,400,000 | 859,800,000 | $ 721,400,000 | 636,800,000 | |||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||||||||||||
Accumulated OCIL beginning balance, net of tax | $ (800,000) | $ (200,000) | (800,000) | (200,000) | |||||||||||
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (2,800,000) | (1,600,000) | |||||||||||||
Amounts reclassified, net of tax | 3,400,000 | 1,000,000 | |||||||||||||
Other Comprehensive Income (Loss), net of tax | 600,000 | (600,000) | 0 | ||||||||||||
Accumulated OCIL ending balance, net of tax | $ (800,000) | $ (200,000) | $ (800,000) | $ (200,000) | $ (800,000) | $ (200,000) | |||||||||
Successor | |||||||||||||||
Class of Stock [Line Items] | |||||||||||||||
Common stock shares authorized | 100 | 100 | |||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||
Common Stock, Shares, Outstanding, Ending Balance | 100 | 100 | |||||||||||||
Predecessor | |||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||
Common Stock, Shares, Outstanding, Beginning Balance | 80,900,000 | 78,500,000 | 80,900,000 | 78,500,000 | 76,100,000 | ||||||||||
Issued to participants in the Employee Stock Purchase Plan (ESPP) (in shares) | 0 | 0 | 0 | ||||||||||||
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP) (in shares) | 300,000 | 700,000 | 700,000 | ||||||||||||
Issued to participants in the Incentive Compensation Plan (ICP) (in shares) | 300,000 | 200,000 | 100,000 | ||||||||||||
Issuance of commons stock shares | 1,800,000 | 1,500,000 | 1,600,000 | ||||||||||||
Stock Delisted During Period, Shares | (83,300,000) | ||||||||||||||
Common Stock, Shares, Outstanding, Ending Balance | 80,900,000 | 0 | 80,900,000 | 0 | 80,900,000 | 78,500,000 | |||||||||
Reclassification out of Accumulated Other Comprehensive Income | |||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||||||
Equity in earnings of unconsolidated affiliates | $ 1,400,000 | $ 1,700,000 | |||||||||||||
Income tax expense | 2,000,000 | (700,000) | |||||||||||||
Net income | $ 3,400,000 | $ 1,000,000 | |||||||||||||
FSA Executed March 2015 | |||||||||||||||
Forward Contract Indexed to Issuer's Equity [Line Items] | |||||||||||||||
Forward Contract Indexed to Issuer's Equity, Shares | 600,000 | ||||||||||||||
Forward Contract Indexed to Issuer's Equity, Settlement Date | Oct. 31, 2015 | ||||||||||||||
Common Stock Issued, Value | $ 21,800,000 | ||||||||||||||
Net Settlement Price Per Share | $ 35.50 | $ 35.50 | $ 35.50 | ||||||||||||
FSA Executed June 2015 | |||||||||||||||
Forward Contract Indexed to Issuer's Equity [Line Items] | |||||||||||||||
Forward Contract Indexed to Issuer's Equity, Shares | 800,000 | ||||||||||||||
Forward Contract Indexed to Issuer's Equity, Settlement Date | Oct. 31, 2015 | ||||||||||||||
Common Stock Issued, Value | $ 28,200,000 | ||||||||||||||
Net Settlement Price Per Share | $ 35.49 | 35.49 | 35.49 | ||||||||||||
FSA Executed September 2015 | |||||||||||||||
Forward Contract Indexed to Issuer's Equity [Line Items] | |||||||||||||||
Forward Contract Indexed to Issuer's Equity, Shares | 100,000 | ||||||||||||||
Forward Contract Indexed to Issuer's Equity, Settlement Date | Oct. 31, 2015 | ||||||||||||||
Common Stock Issued, Value | $ 4,100,000 | ||||||||||||||
Net Settlement Price Per Share | $ 36.03 | $ 36.03 | $ 36.03 | ||||||||||||
FSA Executed January 2016 | |||||||||||||||
Forward Contract Indexed to Issuer's Equity [Line Items] | |||||||||||||||
Forward Contract Indexed to Issuer's Equity, Shares | 400,000 | ||||||||||||||
Forward Contract Indexed to Issuer's Equity, Settlement Date | Sep. 30, 2016 | ||||||||||||||
Common Stock Issued, Value | $ 20,200,000 | ||||||||||||||
Net Settlement Price Per Share | $ 56.25 | ||||||||||||||
FSA Executed March 2016 | |||||||||||||||
Forward Contract Indexed to Issuer's Equity [Line Items] | |||||||||||||||
Forward Contract Indexed to Issuer's Equity, Shares | 600,000 | ||||||||||||||
Forward Contract Indexed to Issuer's Equity, Settlement Date | Sep. 30, 2016 | ||||||||||||||
Common Stock Issued, Value | $ 36,200,000 | ||||||||||||||
Net Settlement Price Per Share | $ 58.35 | ||||||||||||||
FSA Executed June 2016 | |||||||||||||||
Forward Contract Indexed to Issuer's Equity [Line Items] | |||||||||||||||
Forward Contract Indexed to Issuer's Equity, Shares | 800,000 | ||||||||||||||
Forward Contract Indexed to Issuer's Equity, Settlement Date | Sep. 30, 2016 | ||||||||||||||
Common Stock Issued, Value | $ 48,300,000 | ||||||||||||||
Net Settlement Price Per Share | $ 58.87 |
Long Term Debt (Details) - USD ($) |
12 Months Ended | |||||
---|---|---|---|---|---|---|
Jul. 28, 2016 |
Jun. 06, 2016 |
Sep. 14, 2015 |
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
|
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 1,835,000,000 | $ 1,575,000,000 | ||||
Current maturities of long-term debt | 35,000,000 | 40,000,000 | ||||
Long-Term Debt, Gross less current maturities | 1,800,000,000 | 1,535,000,000 | ||||
Long-term debt, net excluding current maturities | 1,786,000,000 | 1,523,700,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 35,000,000 | |||||
Long-term Debt, Maturities, Repayments of Principal in Year Two | 0 | |||||
Long-term Debt, Maturities, Repayments of Principal in Year Three | 0 | |||||
Long-term Debt, Maturities, Repayments of Principal in Year Four | 0 | |||||
Long-term Debt, Maturities, Repayments of Principal in Year Five | 160,000,000 | |||||
Long-term Debt, Maturities, Repayments of Principal after Year Five | 1,640,000,000 | |||||
Total Long-term Debt | 1,835,000,000 | 1,575,000,000 | ||||
Repayments of Long-term Debt | 40,000,000 | 0 | $ 100,000,000 | |||
Net Earnings Available For Restricted Payments | $ 1,300,000,000 | |||||
Debt Instrument, Covenant Description | The default provisions of some or all of our senior debt include: Failure to make principal or interest payments, Bankruptcy, liquidation or insolvency, Final judgment against us in excess of $1.0 million that after 60 days is not discharged, satisfied or stayed pending appeal, Specified events under the Employee Retirement Income Security Act of 1974, Change in control, and Failure to observe or perform covenants, including: Interest coverage of at least 1.75 times. Funded debt cannot exceed 70% of total capitalization. Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. Restrictions on permitted liens; Restrictions on paying dividends on or repurchasing our stock or making investments in subsidiaries; and Restrictions on burdensome agreements. | |||||
Senior Debt Default Provision, Interest Coverage Ratio | 1.75 | |||||
Interest Coverage Ratio | 4.65 | |||||
Senior Debt Default Provision, Ratio of Indebtedness to Net Capital | 0.7 | |||||
Ratio of Indebtedness to Net Capital | 0.55 | |||||
Senior Debt Default Provision, Funded Debt of Subsidiaries | 0.15 | |||||
Funded Debt Of Subsidiaries | $ 0 | |||||
Debt Instrument, Change In Control, Prepayment Percentage | 100.00% | |||||
Debt Instrument, Change In Control, Amount Of Prepayment Options Exercised | $ 0 | |||||
North Carolina Utilities Commission | ||||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Public Utilities, Approved Debt Equity Securities Limit, Amount | $ 1,000,000,000 | |||||
Debt and Equity Shelf Registration, Term | 3 years | |||||
Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 1,835,000,000 | 1,575,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (14,000,000) | (11,300,000) | ||||
Long-term debt, net including current maturities | 1,821,000,000 | 1,563,700,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 1,835,000,000 | 1,575,000,000 | ||||
Senior Notes 2.92% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 2.92% | |||||
Debt Instrument, Maturity Date | Jun. 06, 2016 | |||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Repayments of Long-term Debt | $ 40,000,000 | |||||
Senior Notes 2.92% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | 40,000,000 | |||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (100,000) | |||||
Long-term debt, net including current maturities | 39,900,000 | |||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | 40,000,000 | |||||
Senior Notes 8.51% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.51% | |||||
Debt Instrument, Maturity Date | Sep. 30, 2017 | |||||
Senior Notes 8.51% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 35,000,000 | 35,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | 0 | 0 | ||||
Long-term debt, net including current maturities | 35,000,000 | 35,000,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 35,000,000 | 35,000,000 | ||||
Senior Notes 4.24% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.24% | |||||
Debt Instrument, Maturity Date | Jun. 06, 2021 | |||||
Senior Notes 4.24% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 160,000,000 | 160,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (600,000) | (800,000) | ||||
Long-term debt, net including current maturities | 159,400,000 | 159,200,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 160,000,000 | 160,000,000 | ||||
Senior Notes 3.47% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.47% | |||||
Debt Instrument, Maturity Date | Jul. 16, 2027 | |||||
Senior Notes 3.47% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 100,000,000 | 100,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (600,000) | (600,000) | ||||
Long-term debt, net including current maturities | 99,400,000 | 99,400,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 100,000,000 | 100,000,000 | ||||
Senior Notes 3.57% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.57% | |||||
Debt Instrument, Maturity Date | Jul. 16, 2027 | |||||
Senior Notes 3.57% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 200,000,000 | 200,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (1,200,000) | (1,300,000) | ||||
Long-term debt, net including current maturities | 198,800,000 | 198,700,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 200,000,000 | 200,000,000 | ||||
Senior Notes 4.10% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.10% | |||||
Debt Instrument, Maturity Date | Sep. 18, 2034 | |||||
Senior Notes 4.10% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 250,000,000 | 250,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (2,500,000) | (2,600,000) | ||||
Long-term debt, net including current maturities | 247,500,000 | 247,400,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 250,000,000 | 250,000,000 | ||||
Senior Notes 4.65% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.65% | |||||
Debt Instrument, Maturity Date | Aug. 01, 2043 | |||||
Senior Notes 4.65% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 300,000,000 | 300,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (2,900,000) | (3,000,000) | ||||
Long-term debt, net including current maturities | 297,100,000 | 297,000,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 300,000,000 | 300,000,000 | ||||
Senior Notes 3.60% | ||||||
Debt Instrument [Line Items] | ||||||
Discount on issuance of notes | $ 100,000 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 3.60% | |||||
Debt Instrument, Maturity Date | Sep. 01, 2025 | |||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Debt Instrument, Issuance Date | Sep. 14, 2015 | |||||
Debt Instrument, Face Amount | $ 150,000,000 | |||||
Debt Instrument, Term | 10 years | |||||
Debt Issuance Discount Percentage | 0.065% | |||||
Proceeds from Debt, Net of Issuance Costs | $ 148,900,000 | |||||
Senior Notes 3.60% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 150,000,000 | 150,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (1,400,000) | (1,400,000) | ||||
Long-term debt, net including current maturities | 148,600,000 | 148,600,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 150,000,000 | 150,000,000 | ||||
Senior Notes 3.60% | Debt Instrument, Redemption, Period One | ||||||
Debt Instrument, Redemption [Line Items] | ||||||
Debt Instrument, Redemption, Description | redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 25 basis points and any accrued and unpaid interest to the date of redemption. | |||||
Debt Instrument, Redemption Period, Start Date | Sep. 14, 2015 | |||||
Debt Instrument, Redemption Period, End Date | May 31, 2025 | |||||
Debt Instrument, Redemption Price, Percentage | 100.00% | |||||
Senior Notes 3.60% | Debt Instrument, Redemption, Period One | Base Rate | ||||||
Debt Instrument, Redemption [Line Items] | ||||||
Debt Instrument Redemption Interest Rate | 0.25% | |||||
Senior Notes 3.60% | Debt Instrument, Redemption, Period Two | ||||||
Debt Instrument, Redemption [Line Items] | ||||||
Debt Instrument, Redemption, Description | 100% of the principal amount plus any accrued and unpaid interest to the date of redemption | |||||
Debt Instrument, Redemption Period, Start Date | Jun. 01, 2025 | |||||
Debt Instrument, Redemption Period, End Date | Sep. 01, 2025 | |||||
Debt Instrument, Redemption Price, Percentage | 100.00% | |||||
Senior Notes 3.64% | ||||||
Debt Instrument [Line Items] | ||||||
Discount on issuance of notes | $ 400,000 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 3.64% | |||||
Debt Instrument, Maturity Date | Nov. 01, 2046 | |||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Debt Instrument, Issuance Date | Jul. 28, 2016 | |||||
Debt Instrument, Face Amount | $ 300,000,000 | |||||
Debt Issuance Discount Percentage | 0.122% | |||||
Proceeds from Debt, Net of Issuance Costs | $ 297,000,000 | |||||
Senior Notes 3.64% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 300,000,000 | |||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (3,400,000) | |||||
Long-term debt, net including current maturities | 296,600,000 | |||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 300,000,000 | |||||
Senior Notes 3.64% | Debt Instrument, Redemption, Period One | ||||||
Debt Instrument, Redemption [Line Items] | ||||||
Debt Instrument, Redemption, Description | redemption price equal to the greater of a) 100% of the principal amount of the notes to be redeemed, and b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, as supplemented, plus 25 basis points and any accrued and unpaid interest to the date of redemption. | |||||
Debt Instrument, Redemption Period, Start Date | Jul. 28, 2016 | |||||
Debt Instrument, Redemption Period, End Date | Apr. 30, 2046 | |||||
Debt Instrument, Redemption Price, Percentage | 100.00% | |||||
Debt Instrument Redemption Interest Rate | 0.25% | |||||
Senior Notes 3.64% | Debt Instrument, Redemption, Period Two | ||||||
Debt Instrument, Redemption [Line Items] | ||||||
Debt Instrument, Redemption, Description | 100% of the principal amount plus any accrued and unpaid interest to the date of redemption | |||||
Debt Instrument, Redemption Period, Start Date | May 01, 2046 | |||||
Debt Instrument, Redemption Period, End Date | Oct. 31, 2046 | |||||
Debt Instrument, Redemption Price, Percentage | 100.00% | |||||
Medium Term Notes 6.87% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.87% | |||||
Debt Instrument, Maturity Date | Oct. 06, 2023 | |||||
Medium Term Notes 6.87% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 45,000,000 | 45,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (100,000) | (100,000) | ||||
Long-term debt, net including current maturities | 44,900,000 | 44,900,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 45,000,000 | 45,000,000 | ||||
Medium Term Notes 8.45% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 8.45% | |||||
Debt Instrument, Maturity Date | Sep. 19, 2024 | |||||
Medium Term Notes 8.45% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 40,000,000 | 40,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (100,000) | (100,000) | ||||
Long-term debt, net including current maturities | 39,900,000 | 39,900,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 40,000,000 | 40,000,000 | ||||
Medium Term Notes 7.40% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.40% | |||||
Debt Instrument, Maturity Date | Oct. 03, 2025 | |||||
Medium Term Notes 7.40% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 55,000,000 | 55,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (200,000) | (200,000) | ||||
Long-term debt, net including current maturities | 54,800,000 | 54,800,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 55,000,000 | 55,000,000 | ||||
Medium Term Notes 7.50% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.50% | |||||
Debt Instrument, Maturity Date | Oct. 09, 2026 | |||||
Medium Term Notes 7.50% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 40,000,000 | 40,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (100,000) | (100,000) | ||||
Long-term debt, net including current maturities | 39,900,000 | 39,900,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 40,000,000 | 40,000,000 | ||||
Medium Term Notes 7.95% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.95% | |||||
Debt Instrument, Maturity Date | Sep. 14, 2029 | |||||
Medium Term Notes 7.95% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 60,000,000 | 60,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (200,000) | (300,000) | ||||
Long-term debt, net including current maturities | 59,800,000 | 59,700,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 60,000,000 | 60,000,000 | ||||
Medium Term Notes 6.00% | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.00% | |||||
Debt Instrument, Maturity Date | Dec. 19, 2033 | |||||
Medium Term Notes 6.00% | Unsecured Debt | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt, principal | $ 100,000,000 | 100,000,000 | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | (700,000) | (700,000) | ||||
Long-term debt, net including current maturities | 99,300,000 | 99,300,000 | ||||
Long-term Debt, Fiscal Year Maturity [Abstract] | ||||||
Total Long-term Debt | $ 100,000,000 | $ 100,000,000 |
Available Credit Facilities (Details) |
12 Months Ended | |
---|---|---|
Oct. 31, 2016
USD ($)
|
Oct. 31, 2015
USD ($)
|
|
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 850,000,000 | |
Commercial paper | $ 145,000,000 | $ 340,000,000 |
Ratio of Indebtedness to Net Capital | 0.55 | |
Revolving Credit Facility | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Current Borrowing Capacity | $ 850,000,000 | |
Line of Credit Facility, Expiration Date | Dec. 14, 2020 | |
Line Of Credit Facility, Optional Additional Expansion Amount | $ 200,000,000 | |
Line of Credit Facility, Frequency of Commitment Fee Payment | annual | |
Line of Credit Facility, Commitment Fee Description | $35,000 plus 8.5 basis | |
Line of Credit Facility, Commitment Fee Amount | $ 35,000 | |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.085% | |
Line of Credit Facility, Interest Rate Description | 30-day London Interbank Offered Rate (LIBOR) plus from 75 to 112.5 basis points | |
Minimum Amount Outstanding During Period | $ 0 | |
Maximum Amount Outstanding During Period | $ 0 | |
Line of Credit Facility, Covenant Terms | total debt to total capitalization of no greater than 70% | |
Line of Credit Facility, Covenant Compliance | actual ratio was 55% | |
Debt Covenant Total Debt To Total Capital Ratio | 70.00% | |
Ratio of Indebtedness to Net Capital | 0.55 | |
Revolving Credit Facility | Minimum | London Interbank Offered Rate (LIBOR) [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument Redemption Interest Rate | 0.75% | |
Revolving Credit Facility | Maximum | London Interbank Offered Rate (LIBOR) [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument Redemption Interest Rate | 1.125% | |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Current Borrowing Capacity | $ 10,000,000 | 10,000,000 |
Letters of Credit Outstanding, Amount | 1,700,000 | $ 1,600,000 |
Commercial Paper | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Current Borrowing Capacity | $ 850,000,000 | |
Line of Credit Facility, Interest Rate Description | interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points | |
Maximum Number Of Possible Days Outstanding For Commercial Paper Program | 397 days | |
Short-term Debt, Weighted Average Interest Rate | 0.64% | 0.22% |
Minimum Amount Outstanding During Period | $ 110,000,000 | |
Maximum Amount Outstanding During Period | $ 530,000,000 | |
Commercial Paper | Base Rate | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument Redemption Interest Rate | 0.05% | |
Commercial Paper | Minimum | ||
Line of Credit Facility [Line Items] | ||
Number Days Outstanding From Issuance Until Maturity | 1 day | |
Line of Credit Facility, Interest Rate During Period | 0.20% | |
Commercial Paper | Maximum | ||
Line of Credit Facility [Line Items] | ||
Number Days Outstanding From Issuance Until Maturity | 6 days | |
Line of Credit Facility, Interest Rate During Period | 0.75% | |
Commercial Paper | Weighted Average | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Interest Rate During Period | 0.55% |
Financial Instruments & Related Fair Value (Details) MMBTU in Millions |
12 Months Ended | |
---|---|---|
Oct. 31, 2016
USD ($)
MMBTU
$ / MMBTU
|
Oct. 31, 2015
USD ($)
MMBTU
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Gas Options Total Coverage | MMBTU | 15.4 | 34.7 |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | $ 0 | $ 0 |
Fair Value Measurement Transfers Between Levels Activity | 0 | 0 |
Derivative Liability | 0 | |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 0 | |
Assets [Abstract] | ||
Marketable Securities | 4,200,000 | 4,900,000 |
Gas supply derivative liabilities, at fair value | $ 41,500,000 | 0 |
Percentage Of Annual Gas Purchase Options and All Other Costs Related To Hedging Approved For Recovery Under TIP | 1.00% | |
Long-term debt, principal | $ 1,835,000,000 | 1,575,000,000 |
Concentration Risk [Line Items] | ||
Concentration Risk, Benchmark Description | "Receivables" within "Current Assets" on the Consolidated Balance Sheets | |
Concentration Risk, Customer | We are exposed to credit risk as a result of transactions for the purchase and sale of natural gas and related products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, power generation, residential and municipal energy consumers. These transactions have historically occurred in the gulf coast and mid-west regions of the United States, but our portfolio is being rebalanced and diversified by adding gas supply from northeastern United States gas supply basins. Credit risk associated with receivables for the natural gas distribution operations is mitigated by the large number of individual customers and diversity in our customer base. We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers. | |
Fair Value, Measurements, Recurring | ||
Assets [Abstract] | ||
Total Recurring Fair Value Assets | $ 5,700,000 | 6,200,000 |
Money Market Funds | ||
Assets [Abstract] | ||
Marketable Securities | 500,000 | 500,000 |
Money Market Funds | Fair Value, Measurements, Recurring | ||
Assets [Abstract] | ||
Marketable Securities | 500,000 | 500,000 |
Equity Funds | ||
Assets [Abstract] | ||
Marketable Securities | 3,700,000 | 4,400,000 |
Equity Funds | Fair Value, Measurements, Recurring | ||
Assets [Abstract] | ||
Marketable Securities | 3,700,000 | 4,400,000 |
Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | ||
Assets [Abstract] | ||
Total Recurring Fair Value Assets | 5,700,000 | 6,200,000 |
Fair Value, Inputs, Level 1 | Money Market Funds | Fair Value, Measurements, Recurring | ||
Assets [Abstract] | ||
Marketable Securities | 500,000 | 500,000 |
Fair Value, Inputs, Level 1 | Equity Funds | Fair Value, Measurements, Recurring | ||
Assets [Abstract] | ||
Marketable Securities | 3,700,000 | 4,400,000 |
Fair Value, Inputs, Level 2 | ||
Assets [Abstract] | ||
Long-term debt, fair value | 2,061,200,000 | 1,720,600,000 |
Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | ||
Assets [Abstract] | ||
Total Recurring Fair Value Assets | 0 | 0 |
Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | ||
Assets [Abstract] | ||
Total Recurring Fair Value Assets | 0 | 0 |
Price Risk Derivative | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | 0 | |
Assets [Abstract] | ||
Current Assets, Gas purchase derivative assets | 1,500,000 | 1,300,000 |
Amount of Gain (Loss) Recognized on Derivative Instruments | (5,200,000) | (4,400,000) |
Amount Of Gain (Loss) Deferred Under PGA Procedures | (5,200,000) | (4,400,000) |
Price Risk Derivative | Fair Value, Measurements, Recurring | ||
Assets [Abstract] | ||
Derivative Asset | 1,500,000 | 1,300,000 |
Price Risk Derivative | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | ||
Assets [Abstract] | ||
Derivative Asset | 1,500,000 | 1,300,000 |
Energy Related Derivative | ||
Assets [Abstract] | ||
Gas supply derivative liabilities, at fair value | 41,500,000 | |
Derivative Liability, Noncurrent | 146,400,000 | |
Fair Value, Liabilities Measured on Recurring Basis, Change in Unrealized Gain (Loss) | 187,900,000 | |
Energy Related Derivative | Fair Value, Measurements, Recurring | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | 187,900,000 | |
Energy Related Derivative | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | 0 | |
Energy Related Derivative | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | 0 | |
Energy Related Derivative | Fair Value, Inputs, Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | 187,900,000 | $ 0 |
Assets [Abstract] | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Recorded to Regulatory Assets | 187,900,000 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases, Sales, Issues, Settlements | 0 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers, Net | 0 | |
Energy Related Derivative | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Liability | $ 187,900,000 | |
Minimum | Energy Related Derivative | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair Value Inputs, Price Per Dekatherm | $ / MMBTU | 2.60 | |
Maximum | Energy Related Derivative | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair Value Inputs, Price Per Dekatherm | $ / MMBTU | 4.47 | |
Accounts Receivable | ||
Concentration Risk [Line Items] | ||
Concentration Risk Amount | $ 14,200,000 | |
Accounts Receivable | Credit Concentration Risk | ||
Concentration Risk [Line Items] | ||
Concentration Risk, Percentage | 31.00% |
Commitments & Contingencies (Details) $ in Millions |
12 Months Ended | ||||
---|---|---|---|---|---|
Oct. 31, 2016
USD ($)
regulatory_commission
sites
|
Oct. 31, 2015
USD ($)
|
Oct. 31, 2014
USD ($)
|
Dec. 31, 2013
USD ($)
|
Mar. 01, 2012
USD ($)
|
|
Commitments and Contingencies Disclosure [Abstract] | |||||
Operating lease payments | $ 4.8 | $ 5.0 | $ 4.7 | ||
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 4.7 | ||||
Operating Leases, Future Minimum Payments, Due in Two Years | 4.6 | ||||
Operating Leases, Future Minimum Payments, Due in Three Years | 4.4 | ||||
Operating Leases, Future Minimum Payments, Due in Four Years | 4.5 | ||||
Operating Leases, Future Minimum Payments, Due in Five Years | 4.6 | ||||
Operating Leases, Future Minimum Payments, Due Thereafter | 19.8 | ||||
Operating Leases Future Minimum Payments Due | 42.6 | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months | 368.3 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 246.0 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 235.4 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 217.0 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 211.6 | ||||
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 1,301.6 | ||||
Unrecorded Unconditional Purchase Obligation | $ 2,579.9 | ||||
Number Of Regulatory Commissions | regulatory_commission | 3 | ||||
MGP Sites Under Settlement | sites | 9 | ||||
Site Contingency, Unasserted Claims | 0 | ||||
Site Contingency [Line Items] | |||||
Undiscounted Environmental Liability | $ 1.0 | ||||
Environmental Costs Incurred to Date | 0.1 | ||||
Regulatory Assets [Line Items] | |||||
Regulatory Assets | 487.0 | $ 215.8 | |||
Environmental costs | |||||
Regulatory Assets [Line Items] | |||||
Regulatory Assets | 5.1 | ||||
Pipeline And Storage Capacity Contracts | |||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months | 170.0 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 143.8 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 133.4 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 115.4 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 113.7 | ||||
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 405.5 | ||||
Unrecorded Unconditional Purchase Obligation | 1,081.8 | ||||
Gas Supply Reservation Fees | |||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months | 2.2 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 0.0 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 0.0 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 0.0 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 0.0 | ||||
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 0.0 | ||||
Unrecorded Unconditional Purchase Obligation | 2.2 | ||||
Gas Supply Purchase Commitments | |||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months | 124.4 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 96.8 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 96.8 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 97.1 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 96.8 | ||||
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 896.1 | ||||
Unrecorded Unconditional Purchase Obligation | 1,408.0 | ||||
Telecommunications And Technology Outsourcing Contracts | |||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months | 9.6 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 5.4 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 5.2 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 4.5 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 1.1 | ||||
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 0.0 | ||||
Unrecorded Unconditional Purchase Obligation | 25.8 | ||||
Others | |||||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||||
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months | 62.1 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 0.0 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 0.0 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 0.0 | ||||
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 0.0 | ||||
Unrecorded Unconditional Purchase Obligation, Due after Five Years | 0.0 | ||||
Unrecorded Unconditional Purchase Obligation | $ 62.1 | ||||
Tennessee Regulatory Authority | Environmental costs | General Rate Application Settlement 2012 | |||||
Regulatory Assets [Line Items] | |||||
Regulatory Assets | $ 2.0 | ||||
Regulatory Asset, Amortization Period | 8 years | ||||
North Carolina Utilities Commission | Environmental costs | General Rate Application Settlement 2013 | |||||
Regulatory Assets [Line Items] | |||||
Regulatory Assets | $ 6.3 | ||||
Regulatory Asset, Amortization Period | 5 years | ||||
Letter of Credit | |||||
Guarantor Obligations [Line Items] | |||||
Guarantor Obligations, Maximum Exposure, Undiscounted | $ 1.7 | ||||
Surety Bond | |||||
Guarantor Obligations [Line Items] | |||||
Guarantor Obligations, Maximum Exposure, Undiscounted | 6.4 | ||||
Manufactured Gas Plant Sites | |||||
Site Contingency [Line Items] | |||||
Undiscounted Environmental Liability | 0.8 | ||||
Other Environmental Remediation Sites | |||||
Site Contingency [Line Items] | |||||
Undiscounted Environmental Liability | $ 0.2 |
Commitments & Contingencies - Long Term Contracts (Details) - Maximum |
12 Months Ended |
---|---|
Oct. 31, 2016 | |
Pipeline And Storage Capacity Contracts | |
Long-term Purchase Commitment [Line Items] | |
Long-term Purchase Commitment, Time Period | 19 years |
Gas Supply Reservation Fees | |
Long-term Purchase Commitment [Line Items] | |
Long-term Purchase Commitment, Time Period | 2 years |
Gas Supply Purchase Commitments | |
Long-term Purchase Commitment [Line Items] | |
Long-term Purchase Commitment, Time Period | 15 years |
Telecommunications And Technology Outsourcing Contracts | |
Long-term Purchase Commitment [Line Items] | |
Long-term Purchase Commitment, Time Period | 5 years |
Employee Benefit Plans (Details) - USD ($) |
12 Months Ended | ||
---|---|---|---|
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
|
Defined Contribution Plan Disclosure [Line Items] | |||
Deferred Compensation Noncurrent Liability | $ 4,700,000 | $ 5,300,000 | |
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Term Life Insurance Premiums Paid By Employer | 100,000 | 100,000 | $ 100,000 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Noncurrent liabilities | (23,400,000) | (15,100,000) | |
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account | |||
Regulatory asset | $ (487,000,000) | (215,800,000) | |
Defined Benefit Plan Actuarial Gains And Losses Amortization Corridor | 5 years | ||
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount Rate | 3.80% | ||
Defined Benefit Plans Impact Change Of Discount Rate Methodology | $ (2,400,000) | ||
Gains And Losses Amortized In Excess Of Percentage | 10.00% | ||
Money Purchase Pension Plan | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Defined Contribution Plans Estimated Future Employer Contributions In Next Fiscal Year | $ 2,100,000 | ||
Money Purchase Pension Plan | Pension Plan | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Service Required For Eligibility In Defined Contribution Plan | 30 days | ||
Standard Eligibility Age For Defined Contribution Plan | 18 years | ||
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay | 4.00% | ||
Employer Contribution Percentage Above IRS Limit | 4.00% | ||
Pension Contributions | $ 1,800,000 | 1,400,000 | 900,000 |
Plan Vesting Period Defined Contribution Plan | 3 years | ||
Voluntary Deferral Plan | Other Postretirement Benefit Plan | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Employer Contribution to Plan - deferred compensation | $ 0 | ||
Defined Contribution Restoration Plan | Other Postretirement Benefit Plan | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Employer Contribution Percentage Above IRS Limit | 13.00% | ||
Employer Contribution to Plan - deferred compensation | $ 500,000 | 500,000 | |
Plan 401 K | Other Postretirement Benefit Plan | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Service Required For Eligibility In Defined Contribution Plan | 30 days | ||
Standard Eligibility Age For Defined Contribution Plan | 18 years | ||
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay | 5.00% | ||
Plan Vesting Period Defined Contribution Plan | 6 months | ||
Defined Contribution Plan, Employer Matching Contribution, Percent of Match | 100.00% | ||
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent | 50.00% | ||
Employee Contribution Rate At Enrollment | 2.00% | ||
Contribution Annual Automatic Deferral Increase | 1.00% | ||
Employee Contribution Automatic Increase Rate Cap | 5.00% | ||
Investment In Company Stock Cap | 20.00% | ||
Employer Contribution to Plan | $ 6,900,000 | $ 6,600,000 | 6,100,000 |
Qualified Pension | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Standard Eligibility Age For Defined Benefit Plan | 30 years | ||
Service Required For Eligibility In Defined Benefit Plan | 125 days | ||
Years Of Highest Compensation For Benefit Calculation | 5 years | ||
Horizon For DBPP Long Term Rates Of Return | 20 years | ||
Period Of Compensation For Benefit Calculation | 10 years | ||
Plan Vesting Period Defined Benefit Plan | 5 years | ||
Maximum Credited Service Period | 35 years | ||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 100.00% | ||
Defined Benefit Plan, Actual Plan Asset Allocations | 100.00% | 100.00% | |
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year | $ 10,000,000 | ||
Reconciliation Of Changes In Plan Benefit Obligations And Fair Value Of Assets [Abstract] | |||
Accumulated Benefit Obligation At Year End | 296,300,000 | $ 263,100,000 | |
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Obligation at beginning of year | 311,500,000 | 302,700,000 | |
Service cost | 10,600,000 | 11,400,000 | 10,900,000 |
Interest cost | 9,500,000 | 12,000,000 | 11,700,000 |
Plan amendments | 0 | 0 | |
Plan settlements | 0 | 0 | |
Actuarial (gain) loss | 34,100,000 | 3,500,000 | |
Participant contributions | 0 | 0 | |
Administrative expenses | (500,000) | (600,000) | |
Benefit payments | (13,500,000) | (17,500,000) | |
Obligation at end of year | 351,700,000 | 311,500,000 | 302,700,000 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 329,300,000 | 336,400,000 | |
Actual return on plan assets | 17,600,000 | 1,000,000 | |
Employer contributions | 10,000,000 | 10,000,000 | |
Participant contributions | 0 | 0 | |
Administrative expenses | (500,000) | (600,000) | |
Plan settlements | 0 | 0 | |
Benefit payments | (13,500,000) | (17,500,000) | |
Fair value at end of year | 342,900,000 | 329,300,000 | 336,400,000 |
Funded status at year end - (under) over | (8,800,000) | 17,800,000 | |
Noncurrent assets | 0 | 17,800,000 | |
Current liabilities | 0 | 0 | |
Noncurrent liabilities | (8,800,000) | 0 | |
Net amount recognized | (8,800,000) | 17,800,000 | |
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account | |||
Unrecognized prior service (cost) credit | 10,700,000 | 12,800,000 | |
Unrecognized actuarial loss | (153,100,000) | (120,500,000) | |
Regulatory asset | (142,400,000) | (107,700,000) | |
Cumulative employer contributions in excess of cost | $ 133,600,000 | $ 125,500,000 | |
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount Rate | 3.80% | 4.34% | |
Rate Of Compensation Increase | 4.05% | 4.07% | |
Net Periodic Benefit Cost [Abstract] | |||
Service cost | $ 10,600,000 | $ 11,400,000 | 10,900,000 |
Interest cost | 9,500,000 | 12,000,000 | 11,700,000 |
Expected return on plan assets | (24,000,000) | (23,600,000) | (22,500,000) |
Amortization of prior service cost (credit) | (2,200,000) | (2,200,000) | (2,200,000) |
Amortization of net loss | 8,000,000 | 8,700,000 | 7,700,000 |
Settlement loss recognized | 0 | 0 | 0 |
Net periodic benefit cost | 1,900,000 | 6,300,000 | 5,600,000 |
Estimated Amortization And Expected Refunds [Abstract] | |||
Amortization of unrecognized prior service cost (credit) | (2,200,000) | ||
Amortization of unrecognized actuarial loss | 11,300,000 | ||
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract] | |||
Prior service cost (credit) | 0 | 0 | 0 |
Net loss (gain) | 40,500,000 | 26,200,000 | 14,400,000 |
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract] | |||
Amortization of net loss | 8,000,000 | 8,700,000 | 7,700,000 |
Settlement loss recognized | 0 | 0 | 0 |
Amortization of prior service (cost) credit | 2,200,000 | 2,200,000 | 2,200,000 |
Total recognized in regulatory asset (liability) | 34,700,000 | 19,700,000 | 8,900,000 |
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability) | $ 36,600,000 | $ 26,000,000 | $ 14,500,000 |
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Discount Rate | 4.34% | 4.13% | 4.55% |
Expected Long Term Rate Of Return On Plan Assets | 7.25% | 7.50% | 7.75% |
Rate Of Compensation Increase | 4.07% | 3.68% | 3.72% |
Expected Future Benefit Payments, Fiscal Year Maturity [Abstract] | |||
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | $ 39,600,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Two | 25,200,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Three | 25,000,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Four | 24,800,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Five | 24,900,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter | 126,800,000 | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 329,300,000 | $ 336,400,000 | |
Actual return on plan assets: | |||
Fair value at end of year | $ 342,900,000 | $ 329,300,000 | $ 336,400,000 |
Qualified Pension | Minimum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Standard Eligibility Age For Defined Benefit Plan | 21 years | ||
Qualified Pension | Derivative | Maximum | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Investment Limitation Percentage | 10.00% | ||
Qualified Pension | Fixed income securities | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 45.00% | ||
Defined Benefit Plan, Actual Plan Asset Allocations | 46.00% | 46.00% | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | $ 84,100,000 | ||
Fair value at end of year | 78,900,000 | $ 84,100,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 84,100,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | $ 78,900,000 | $ 84,100,000 | |
Qualified Pension | Equity securities | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 35.00% | ||
Defined Benefit Plan, Actual Plan Asset Allocations | 33.00% | 34.00% | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | $ 44,700,000 | ||
Fair value at end of year | 44,400,000 | $ 44,700,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 44,700,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | $ 44,400,000 | $ 44,700,000 | |
Qualified Pension | Real estate | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 5.00% | ||
Defined Benefit Plan, Actual Plan Asset Allocations | 5.00% | 5.00% | |
Qualified Pension | Cash and cash equivalents | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 0.00% | ||
Defined Benefit Plan, Actual Plan Asset Allocations | 2.00% | 1.00% | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | $ 2,900,000 | ||
Fair value at end of year | 5,900,000 | $ 2,900,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 2,900,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | $ 5,900,000 | $ 2,900,000 | |
Qualified Pension | Other investments | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 15.00% | ||
Defined Benefit Plan, Actual Plan Asset Allocations | 14.00% | 14.00% | |
Qualified Pension | Mutual funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | $ 121,800,000 | ||
Fair value at end of year | 133,200,000 | $ 121,800,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 121,800,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 133,200,000 | 121,800,000 | |
Qualified Pension | Common trust fund | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 23,600,000 | ||
Fair value at end of year | $ 25,000,000 | 23,600,000 | |
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract] | |||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period | 30 days | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency | Monthly | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description | None | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | $ 23,600,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | $ 25,000,000 | 23,600,000 | |
Qualified Pension | Private equity fund of funds | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 3.50% | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | $ 8,300,000 | ||
Fair value at end of year | 8,900,000 | 8,300,000 | |
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract] | |||
Initial Unfunded Subscription Balance | $ 12,000,000 | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency | Limited | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments | $ 2,600,000 | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description | Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval. | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | $ 8,300,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | $ 8,900,000 | 8,300,000 | |
Qualified Pension | Private equity fund of funds | Minimum | |||
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract] | |||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Liquidating Investment, Remaining Period | 8 years | ||
Qualified Pension | Private equity fund of funds | Maximum | |||
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract] | |||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Liquidating Investment, Remaining Period | 10 years | ||
Qualified Pension | Hedge fund of funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | $ 19,800,000 | ||
Fair value at end of year | $ 20,000,000 | 19,800,000 | |
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract] | |||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period | 65 days | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency | Quarterly | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description | Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on "first in first out" basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2016. | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | $ 19,800,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 20,000,000 | 19,800,000 | |
Qualified Pension | Commodities fund of funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 7,700,000 | ||
Fair value at end of year | $ 9,200,000 | 7,700,000 | |
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract] | |||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period | 35 days | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency | Monthly | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description | Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete. | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | $ 7,700,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 9,200,000 | 7,700,000 | |
Qualified Pension | High yield debt (bank loans) | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 16,400,000 | ||
Fair value at end of year | $ 17,400,000 | 16,400,000 | |
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract] | |||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period | 30 days | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency | Daily | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description | None | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | $ 16,400,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 17,400,000 | 16,400,000 | |
Qualified Pension | Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 126,400,000 | ||
Fair value at end of year | 127,700,000 | 126,400,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 126,400,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 127,700,000 | 126,400,000 | |
Qualified Pension | Fair Value, Inputs, Level 1 | Fixed income securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Qualified Pension | Fair Value, Inputs, Level 1 | Equity securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 44,700,000 | ||
Fair value at end of year | 44,400,000 | 44,700,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 44,700,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 44,400,000 | 44,700,000 | |
Qualified Pension | Fair Value, Inputs, Level 1 | Cash and cash equivalents | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 2,800,000 | ||
Fair value at end of year | 5,100,000 | 2,800,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 2,800,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 5,100,000 | 2,800,000 | |
Qualified Pension | Fair Value, Inputs, Level 1 | Mutual funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 78,900,000 | ||
Fair value at end of year | 78,200,000 | 78,900,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 78,900,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 78,200,000 | 78,900,000 | |
Qualified Pension | Fair Value, Inputs, Level 1 | Common trust fund | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Qualified Pension | Fair Value, Inputs, Level 1 | Private equity fund of funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Qualified Pension | Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 150,700,000 | ||
Fair value at end of year | 159,700,000 | 150,700,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 150,700,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 159,700,000 | 150,700,000 | |
Qualified Pension | Fair Value, Inputs, Level 2 | Fixed income securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 84,100,000 | ||
Fair value at end of year | 78,900,000 | 84,100,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 84,100,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 78,900,000 | 84,100,000 | |
Qualified Pension | Fair Value, Inputs, Level 2 | Equity securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Qualified Pension | Fair Value, Inputs, Level 2 | Cash and cash equivalents | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 100,000 | ||
Fair value at end of year | 800,000 | 100,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 100,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 800,000 | 100,000 | |
Qualified Pension | Fair Value, Inputs, Level 2 | Mutual funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 42,900,000 | ||
Fair value at end of year | 55,000,000 | 42,900,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 42,900,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 55,000,000 | 42,900,000 | |
Qualified Pension | Fair Value, Inputs, Level 2 | Common trust fund | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 23,600,000 | ||
Fair value at end of year | 25,000,000 | 23,600,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 23,600,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 25,000,000 | 23,600,000 | |
Qualified Pension | Fair Value, Inputs, Level 2 | Private equity fund of funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Qualified Pension | Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 8,300,000 | ||
Fair value at end of year | 8,900,000 | 8,300,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 8,300,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 8,900,000 | 8,300,000 | |
Qualified Pension | Fair Value, Inputs, Level 3 | Fixed income securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Qualified Pension | Fair Value, Inputs, Level 3 | Equity securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Qualified Pension | Fair Value, Inputs, Level 3 | Cash and cash equivalents | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Qualified Pension | Fair Value, Inputs, Level 3 | Mutual funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Qualified Pension | Fair Value, Inputs, Level 3 | Common trust fund | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Qualified Pension | Fair Value, Inputs, Level 3 | Private equity fund of funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 8,300,000 | 7,200,000 | |
Fair value at end of year | 8,900,000 | 8,300,000 | 7,200,000 |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 8,300,000 | 7,200,000 | |
Actual return on plan assets: | |||
Relating to assets still held at the reporting date | 100,000 | 400,000 | |
Relating to assets sold during the period | 500,000 | 600,000 | |
Purchases, sales and settlements (net) | 0 | 100,000 | |
Transfer in/out of Level 3 | 0 | 0 | |
Fair value at end of year | 8,900,000 | 8,300,000 | 7,200,000 |
Non Qualified Pension | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year | 500,000 | ||
Reconciliation Of Changes In Plan Benefit Obligations And Fair Value Of Assets [Abstract] | |||
Accumulated Benefit Obligation At Year End | 4,600,000 | 5,500,000 | |
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Obligation at beginning of year | 5,500,000 | 5,900,000 | |
Service cost | 0 | 0 | 0 |
Interest cost | 200,000 | 200,000 | 200,000 |
Plan amendments | 0 | 0 | |
Plan settlements | (900,000) | 0 | |
Actuarial (gain) loss | 300,000 | (100,000) | |
Participant contributions | 0 | 0 | |
Administrative expenses | 0 | 0 | |
Benefit payments | (500,000) | (500,000) | |
Obligation at end of year | 4,600,000 | 5,500,000 | 5,900,000 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | 0 | |
Actual return on plan assets | 0 | 0 | |
Employer contributions | 1,400,000 | 500,000 | |
Participant contributions | 0 | 0 | |
Administrative expenses | 0 | 0 | |
Plan settlements | (900,000) | 0 | |
Benefit payments | (500,000) | (500,000) | |
Fair value at end of year | 0 | 0 | 0 |
Funded status at year end - (under) over | (4,600,000) | (5,500,000) | |
Noncurrent assets | 0 | 0 | |
Current liabilities | (500,000) | (500,000) | |
Noncurrent liabilities | (4,100,000) | (5,000,000) | |
Net amount recognized | (4,600,000) | (5,500,000) | |
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account | |||
Unrecognized prior service (cost) credit | 0 | (200,000) | |
Unrecognized actuarial loss | (1,500,000) | (1,600,000) | |
Regulatory asset | (1,500,000) | (1,800,000) | |
Cumulative employer contributions in excess of cost | $ (3,100,000) | $ (3,700,000) | |
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount Rate | 3.80% | 3.85% | |
Net Periodic Benefit Cost [Abstract] | |||
Service cost | $ 0 | $ 0 | 0 |
Interest cost | 200,000 | 200,000 | 200,000 |
Expected return on plan assets | 0 | 0 | 0 |
Amortization of prior service cost (credit) | 200,000 | 200,000 | 200,000 |
Amortization of net loss | 0 | 100,000 | 100,000 |
Settlement loss recognized | 300,000 | 0 | 0 |
Net periodic benefit cost | 700,000 | 500,000 | 500,000 |
Estimated Amortization And Expected Refunds [Abstract] | |||
Amortization of unrecognized prior service cost (credit) | 0 | ||
Amortization of unrecognized actuarial loss | 100,000 | ||
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract] | |||
Prior service cost (credit) | 0 | 0 | 500,000 |
Net loss (gain) | 300,000 | (100,000) | 1,000,000 |
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract] | |||
Amortization of net loss | 0 | 100,000 | 100,000 |
Settlement loss recognized | 300,000 | 0 | 0 |
Amortization of prior service (cost) credit | (200,000) | (200,000) | (200,000) |
Total recognized in regulatory asset (liability) | (200,000) | (400,000) | 1,200,000 |
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability) | $ 500,000 | $ 100,000 | $ 1,700,000 |
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Discount Rate | 3.85% | 3.69% | 3.98% |
Expected Future Benefit Payments, Fiscal Year Maturity [Abstract] | |||
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | $ 500,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Two | 500,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Three | 500,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Four | 400,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Five | 400,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter | 1,700,000 | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | $ 0 | |
Actual return on plan assets: | |||
Fair value at end of year | $ 0 | $ 0 | $ 0 |
Other Postretirement Benefit Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Standard Eligibility Age for Defined Benefit Plan Pre Amendment | 55 years | ||
Standard Eligibility Age for Defined Benefit Plan Post Amendment | 50 years | ||
Age Of Exclusion For Defined Benefit Plan | 65 years | ||
Years After Qualifying Age | 10 years | ||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 100.00% | ||
Defined Benefit Plan, Actual Plan Asset Allocations | 100.00% | 100.00% | |
Benefits Provided After Employee Is Eligible for Medicare Benefits | $ 0 | ||
Term Life Insurance Per Individual Benefit Provided By Employer | 15,000 | ||
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year | 2,200,000 | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Obligation at beginning of year | 37,600,000 | $ 37,800,000 | |
Service cost | 1,200,000 | 1,200,000 | 1,100,000 |
Interest cost | 1,300,000 | 1,500,000 | 1,500,000 |
Plan amendments | 0 | (1,900,000) | |
Plan settlements | 0 | 0 | |
Actuarial (gain) loss | 1,600,000 | 1,700,000 | |
Participant contributions | 100,000 | 600,000 | |
Administrative expenses | 0 | 0 | |
Benefit payments | (2,500,000) | (3,300,000) | |
Obligation at end of year | 39,300,000 | 37,600,000 | 37,800,000 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 27,500,000 | 27,700,000 | |
Actual return on plan assets | 1,100,000 | 300,000 | |
Employer contributions | 2,600,000 | 2,200,000 | |
Participant contributions | 100,000 | 600,000 | |
Administrative expenses | 0 | 0 | |
Plan settlements | 0 | 0 | |
Benefit payments | (2,500,000) | (3,300,000) | |
Fair value at end of year | 28,800,000 | 27,500,000 | 27,700,000 |
Funded status at year end - (under) over | (10,500,000) | (10,100,000) | |
Noncurrent assets | 0 | 0 | |
Current liabilities | 0 | 0 | |
Noncurrent liabilities | (10,500,000) | (10,100,000) | |
Net amount recognized | (10,500,000) | (10,100,000) | |
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account | |||
Unrecognized prior service (cost) credit | 1,500,000 | 1,900,000 | |
Unrecognized actuarial loss | (9,100,000) | (7,200,000) | |
Regulatory asset | (7,600,000) | (5,300,000) | |
Cumulative employer contributions in excess of cost | $ (2,900,000) | $ (4,800,000) | |
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount Rate | 3.80% | 4.38% | |
Net Periodic Benefit Cost [Abstract] | |||
Service cost | $ 1,200,000 | $ 1,200,000 | 1,100,000 |
Interest cost | 1,300,000 | 1,500,000 | 1,500,000 |
Expected return on plan assets | (1,800,000) | (1,800,000) | (1,800,000) |
Amortization of prior service cost (credit) | (300,000) | 0 | 0 |
Amortization of net loss | 400,000 | 0 | 0 |
Settlement loss recognized | 0 | 0 | 0 |
Net periodic benefit cost | 800,000 | 900,000 | 800,000 |
Estimated Amortization And Expected Refunds [Abstract] | |||
Amortization of unrecognized prior service cost (credit) | (300,000) | ||
Amortization of unrecognized actuarial loss | 700,000 | ||
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract] | |||
Prior service cost (credit) | 0 | (1,900,000) | 0 |
Net loss (gain) | 2,400,000 | 3,200,000 | 3,600,000 |
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract] | |||
Amortization of net loss | 400,000 | 0 | 0 |
Settlement loss recognized | 0 | 0 | 0 |
Amortization of prior service (cost) credit | 300,000 | 0 | 0 |
Total recognized in regulatory asset (liability) | 2,300,000 | 1,300,000 | 3,600,000 |
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability) | $ 3,100,000 | $ 2,200,000 | $ 4,400,000 |
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Discount Rate | 4.38% | 4.03% | 4.44% |
Expected Long Term Rate Of Return On Plan Assets | 7.25% | 7.50% | 7.75% |
Expected Future Benefit Payments, Fiscal Year Maturity [Abstract] | |||
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | $ 1,900,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Two | 2,100,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Three | 2,200,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Four | 2,400,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Year Five | 2,400,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter | 13,100,000 | ||
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract] | |||
Effect Of One Percentage Point Increase on Postretirement Benefit Obligation | 0 | $ 0 | |
Effect of One Percentage Point Decrease on Postretirement Benefit Obligation | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 27,500,000 | 27,700,000 | |
Actual return on plan assets: | |||
Fair value at end of year | $ 28,800,000 | $ 27,500,000 | $ 27,700,000 |
Other Postretirement Benefit Plan | Minimum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Standard Eligibility Age for Defined Benefit Plan Pre Amendment | 45 years | ||
Other Postretirement Benefit Plan | Fixed income securities | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 45.00% | ||
Defined Benefit Plan, Actual Plan Asset Allocations | 47.00% | 47.00% | |
Other Postretirement Benefit Plan | Equity securities | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 47.00% | ||
Defined Benefit Plan, Actual Plan Asset Allocations | 44.00% | 44.00% | |
Other Postretirement Benefit Plan | Real estate | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 5.00% | ||
Defined Benefit Plan, Actual Plan Asset Allocations | 5.00% | 5.00% | |
Other Postretirement Benefit Plan | Cash and cash equivalents | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 3.00% | ||
Defined Benefit Plan, Actual Plan Asset Allocations | 4.00% | 4.00% | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | $ 1,100,000 | ||
Fair value at end of year | 1,200,000 | $ 1,100,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 1,100,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | $ 1,200,000 | 1,100,000 | |
Other Postretirement Benefit Plan | High yield fixed income | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Defined Benefit Plan, Target Plan Asset Allocations | 5.00% | ||
Other Postretirement Benefit Plan | Mutual funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | $ 26,400,000 | ||
Fair value at end of year | 27,600,000 | 26,400,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 26,400,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 27,600,000 | 26,400,000 | |
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 27,500,000 | ||
Fair value at end of year | 28,800,000 | 27,500,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 27,500,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 28,800,000 | 27,500,000 | |
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 1 | Cash and cash equivalents | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 1,100,000 | ||
Fair value at end of year | 1,200,000 | 1,100,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 1,100,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 1,200,000 | 1,100,000 | |
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 1 | Mutual funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 26,400,000 | ||
Fair value at end of year | 27,600,000 | 26,400,000 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 26,400,000 | ||
Actual return on plan assets: | |||
Fair value at end of year | 27,600,000 | 26,400,000 | |
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 2 | Cash and cash equivalents | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 2 | Mutual funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 3 | Cash and cash equivalents | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | 0 | |
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 3 | Mutual funds | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Fair value at end of year | 0 | 0 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||
Fair value at beginning of year | 0 | ||
Actual return on plan assets: | |||
Fair value at end of year | 0 | $ 0 | |
Supplemental Executive Retirement Plans | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Assets for Participant Benefits | 0 | ||
Officers and Director-Level Employees Life Insurance | |||
Defined Benefit Plan, Information about Plan Assets [Abstract] | |||
Term Life Insurance Per Individual Benefit Provided By Employer | $ 200,000 |
Employee Share Based Plans (Details) $ / shares in Units, $ in Millions |
1 Months Ended | 11 Months Ended | 12 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Oct. 03, 2016
USD ($)
$ / shares
|
Dec. 15, 2015
shares
|
Dec. 15, 2014
shares
|
Dec. 31, 2011
shares
|
Oct. 02, 2016 |
Oct. 31, 2016
USD ($)
Integer
|
Oct. 31, 2015
USD ($)
|
Oct. 31, 2014
USD ($)
|
Dec. 14, 2015
$ / shares
|
Dec. 12, 2014
$ / shares
|
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Number Of Performance Periods Under ICP Plans | 3 years | |||||||||
Business Acquisition, Share Price | $ / shares | $ 60 | |||||||||
Share Price | $ / shares | $ 56.85 | $ 37.89 | ||||||||
Stock Issued During Period, Value, Share-based Compensation, Gross | $ 18.3 | $ 5.0 | $ 3.3 | |||||||
Maximum Statutory Withholdings Allowed | 50.00% | |||||||||
Compensation expense | $ 16.1 | 14.2 | 8.5 | |||||||
Tax Benefit | 6.1 | 4.0 | $ 2.5 | |||||||
Liability | 0.0 | $ 22.0 | ||||||||
Purchase Price of Common Stock, Percent | 95.00% | |||||||||
Stock Compensation Plan | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Expense related to acceleration of incentive plans | $ 5.3 | |||||||||
Performance Shares | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Number Of Incentive Compensation Plan Awards | Integer | 3 | |||||||||
Long Term Incentive Plan | Performance Shares | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Acceleration And Payout Election Rate | 96.00% | |||||||||
Stock Issued During Period, Shares, Restricted Stock Award | shares | 162,390 | |||||||||
Stock Issued During Period, Value, Share-based Compensation, Gross | $ 0.3 | |||||||||
Retention Stock Unit Award President And Chief Executive Officer | Restricted Stock Unit Award | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Nonvested Shares Granted in Period | shares | 64,700 | |||||||||
Retention Stock Unit Award President And Chief Executive Officer | Restricted Stock Unit Award | Share-based Compensation Award, Tranche One | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Stock Issued During Period, Shares, Restricted Stock Award | shares | 7,231 | |||||||||
Vesting % of restricted stock unit | 20.00% | |||||||||
Retention Stock Unit Award President And Chief Executive Officer | Restricted Stock Unit Award | Share-based Compensation Award, Tranche Two | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Stock Issued During Period, Shares, Restricted Stock Award | shares | 11,732 | |||||||||
Vesting % of restricted stock unit | 30.00% | |||||||||
Retention Stock Unit Award President And Chief Executive Officer | Restricted Stock Unit Award | Share-based Compensation Award, Tranche Three | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Stock Issued During Period, Shares, Restricted Stock Award | shares | 19,554 | |||||||||
Vesting % of restricted stock unit | 50.00% | |||||||||
Duke Energy Restricted Stock Unit Award [Member] | Restricted Stock Unit Award | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Percentage | 100.00% | |||||||||
Accounts Payable, Related Parties, Current | $ 6.1 |
Income Taxes Income Tax Expense Components (Details) - USD ($) $ in Millions |
1 Months Ended | 12 Months Ended | ||
---|---|---|---|---|
Oct. 31, 2016 |
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
|
Income Tax Table Continuing Operations [Line Items] | ||||
Current Federal Tax Expense (Benefit) | $ 27.2 | $ (0.7) | $ 2.5 | |
Current State Tax Expense (Benefit) | 11.8 | 1.1 | 1.8 | |
Deferred Federal Income Tax Expense (Benefit) | 79.6 | 77.9 | 76.5 | |
Deferred State Income Tax Expense (Benefit) | 5.8 | 12.1 | 14.2 | |
Amortization of investment tax credits | (0.2) | (0.2) | (0.2) | |
Federal Total | 106.6 | 77.0 | 78.8 | |
State Total | 17.6 | 13.2 | 16.0 | |
Current Income Tax Expense (Benefit) | $ 40.4 | |||
Deferred Income Tax Expense (Benefit) | (8.7) | |||
Taxes accrued | 68.4 | 68.4 | 30.3 | |
Income Tax Examination, Interest Income | 0.5 | |||
Duke Energy | ||||
Income Tax Table Continuing Operations [Line Items] | ||||
Taxes accrued | $ 31.5 | 31.5 | ||
Domestic Tax Authority | NOL Carryforward 1 | ||||
Income Tax Table Continuing Operations [Line Items] | ||||
Deferred Federal Income Tax Expense (Benefit) | $ 91.4 | 64.3 | ||
Domestic Tax Authority | Net Operating Loss Utilization | ||||
Income Tax Table Continuing Operations [Line Items] | ||||
Deferred Federal Income Tax Expense (Benefit) | $ 19.8 | $ 28.6 |
Income Taxes Operating Loss Carryforwards (Details) - USD ($) |
12 Months Ended | ||
---|---|---|---|
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
|
Operating Loss Carryforwards [Line Items] | |||
Unrecognized Tax Benefits | $ 0 | ||
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount | 0 | $ 300,000 | $ 0 |
Operating Loss Carryforwards | $ 175,400,000 | ||
Operating Loss Carryforwards, Limitations on Use | Following the Acquisition, utilization of our tax carryforwards is subject to various limitations. The primary limitation is federal NOL carryforwards of $159.6 million are subject to an effective annual limitation of $31.8 million. | ||
Capital Loss Carryforward | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | $ 300,000 | ||
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2017 | ||
Charitable Carryforward | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | $ 3,200,000 | ||
Charitable Carryforward | Minimum | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2016 | ||
Charitable Carryforward | Maximum | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2019 | ||
Domestic Tax Authority | |||
Operating Loss Carryforwards [Line Items] | |||
Net Operating Loss, Retroactive Impact | $ 46,800,000 | $ 61,100,000 | |
Domestic Tax Authority | Carryforward Limitation 1 | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards, Annual Amount Subject To Limitation | 31,800,000 | ||
Domestic Tax Authority | Federal NOL | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | 163,500,000 | ||
Domestic Tax Authority | Federal NOL | Carryforward Limitation 1 | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | $ 159,600,000 | ||
Domestic Tax Authority | Federal NOL | Minimum | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2020 | ||
Domestic Tax Authority | Federal NOL | Maximum | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2036 | ||
State and Local Jurisdiction | State NOL | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | $ 8,400,000 | ||
State and Local Jurisdiction | State NOL | Minimum | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2027 | ||
State and Local Jurisdiction | State NOL | Maximum | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2036 |
Income Taxes (Details) - USD ($) |
12 Months Ended | |||||
---|---|---|---|---|---|---|
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
|
Effective Income Tax Rate Reconciliation, Amount [Abstract] | ||||||
Federal taxes at 35% | $ 111,100,000 | $ 79,500,000 | $ 83,500,000 | |||
State income taxes, net of federal benefit | 11,400,000 | 8,600,000 | 10,400,000 | |||
Amortization of investment tax credits | (200,000) | (200,000) | (200,000) | |||
Other, net | 1,900,000 | 2,300,000 | 1,100,000 | |||
Total | $ 124,200,000 | $ 90,200,000 | $ 94,800,000 | |||
Effective Income Tax Rate Reconciliation, Percent | 39.10% | 39.70% | 39.70% | |||
Deferred tax assets: | ||||||
Benefit of tax carryforwards | $ 175,400,000 | $ 84,000,000 | ||||
Revenues and cost of natural gas | 0 | 3,500,000 | ||||
Employee benefits and compensation | 28,600,000 | 22,100,000 | ||||
Revenue requirement | 30,100,000 | 26,100,000 | ||||
Property, plant and equipment | 5,300,000 | 7,500,000 | ||||
Deferred Tax Assets, Derivative Instruments | 70,600,000 | 0 | ||||
Other | 13,800,000 | 10,500,000 | ||||
Total deferred tax assets | 323,800,000 | 153,700,000 | ||||
Valuation allowance | $ (800,000) | $ (500,000) | $ (500,000) | (800,000) | (800,000) | $ (500,000) |
Total deferred tax assets, net | 323,000,000 | 152,900,000 | ||||
Deferred tax liabilities: | ||||||
Utility Plant | 1,010,800,000 | 849,800,000 | ||||
Revenues and cost of natural gas | 20,000,000 | 0 | ||||
Equity Method Investments | 34,800,000 | 44,800,000 | ||||
Deferred costs | 85,000,000 | 73,900,000 | ||||
Deferred Tax Liabilities, Derivatives | 70,600,000 | 0 | ||||
Other | 5,900,000 | 13,600,000 | ||||
Total deferred tax liabilities | 1,227,100,000 | 982,100,000 | ||||
Net Deferred Income Tax Liabilities | 904,100,000 | 829,200,000 | ||||
Valuation Allowance [Abstract] | ||||||
Balance at beginning of year | 800,000 | 500,000 | 500,000 | |||
Charged to income tax expense | 0 | 300,000 | 0 | |||
Balance at end of year | 800,000 | 800,000 | 500,000 | |||
Unrecognized Tax Benefits | 0 | |||||
NC Tax Law [Line Items] | ||||||
State and Local Income Tax Expense (Benefit) | 17,600,000 | 13,200,000 | $ 16,000,000 | |||
Regulatory liabilities, Noncurrent | 617,000,000 | 590,300,000 | ||||
Regulatory liabilities, Total | 617,000,000 | 611,800,000 | ||||
Deferred income taxes | ||||||
NC Tax Law [Line Items] | ||||||
Regulatory liabilities, Noncurrent | $ 78,900,000 | 68,700,000 | ||||
North Carolina | State and Local Jurisdiction | ||||||
NC Tax Law [Line Items] | ||||||
Increase (Decrease) in Deferred Income Taxes | 15,700,000 | 17,500,000 | ||||
State and Local Income Tax Expense (Benefit) | $ 600,000 | $ 500,000 | ||||
North Carolina | State and Local Jurisdiction | Earliest Tax Year | ||||||
NC Tax Law [Line Items] | ||||||
Statutory Tax Rate | 6.90% | |||||
North Carolina | State and Local Jurisdiction | Tax Year 2014 | ||||||
NC Tax Law [Line Items] | ||||||
Statutory Tax Rate | 6.00% | |||||
North Carolina | State and Local Jurisdiction | Tax Year 2015 | ||||||
NC Tax Law [Line Items] | ||||||
Statutory Tax Rate | 5.00% | |||||
North Carolina | State and Local Jurisdiction | Short Tax Year 2016 | ||||||
NC Tax Law [Line Items] | ||||||
Statutory Tax Rate | 4.00% | |||||
North Carolina | State and Local Jurisdiction | Latest Tax Year | ||||||
NC Tax Law [Line Items] | ||||||
Statutory Tax Rate | 3.00% | |||||
North Carolina | Deferred income taxes | State and Local Jurisdiction | ||||||
NC Tax Law [Line Items] | ||||||
Regulatory liabilities, Noncurrent | $ 15,100,000 | $ 17,000,000 | ||||
North Carolina | Corporate Tax Legislation | State and Local Jurisdiction | ||||||
NC Tax Law [Line Items] | ||||||
Regulatory liabilities, Noncurrent | $ 3,000,000 | |||||
North Carolina | Corporate Tax Legislation | Deferred income taxes | State and Local Jurisdiction | ||||||
NC Tax Law [Line Items] | ||||||
Regulatory liabilities, Noncurrent | $ 58,600,000 |
Investments in Unconsolidated Affiliates (Details) - USD ($) |
12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
Oct. 03, 2016 |
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
Oct. 02, 2016 |
||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Retained Earnings, Undistributed Earnings from Equity Method Investees | $ 0 | |||||||||
Investments in equity method unconsolidated affiliates | 199,200,000 | $ 207,000,000 | ||||||||
Equity in earnings of unconsolidated affiliates | 28,600,000 | 34,500,000 | $ 32,800,000 | |||||||
Accounts payable to affiliated companies | [1],[2] | 8,700,000 | 2,500,000 | |||||||
Receivables from affiliated companies | [1],[2] | 7,000,000 | 200,000 | |||||||
Net proceeds from the sales of interests in unconsolidated affiliates and other assets | 174,500,000 | 700,000 | 1,900,000 | |||||||
Gain on Sale of Investments | 80,900,000 | 0 | 0 | |||||||
Equity Method Investee [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Related party expenses | 28,700,000 | 29,500,000 | 29,700,000 | |||||||
Accounts payable to affiliated companies | $ 2,400,000 | 2,500,000 | ||||||||
Cardinal Pipeline Company | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity Method Investment, Ownership Percentage | 21.49% | |||||||||
Investments in equity method unconsolidated affiliates | $ 14,200,000 | 15,100,000 | ||||||||
Equity in earnings of unconsolidated affiliates | $ 1,500,000 | $ 1,700,000 | $ 1,700,000 | |||||||
Pipeline Subscription Capacity Percentage | 100.00% | |||||||||
Pipeline Transportation Capacity Subscribed | 53.00% | |||||||||
Summarized Financial Information Percentage | 100.00% | 100.00% | 100.00% | |||||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||||||
Equity Method Investment, Summarized Financial Information, Current Assets | $ 10,300,000 | $ 9,500,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Noncurrent Assets | 101,500,000 | 106,400,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Current Liabilities | 46,000,000 | 1,200,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities | 300,000 | 45,400,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Revenue | 16,600,000 | 16,600,000 | $ 16,700,000 | |||||||
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss) | 16,600,000 | 16,600,000 | 16,700,000 | |||||||
Equity Method Investment, Summarized Financial Information, Net Income (Loss) | 7,700,000 | 7,700,000 | 8,000,000 | |||||||
Cardinal Pipeline Company | Equity Method Investee [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Related party expenses | 8,700,000 | 8,800,000 | 8,800,000 | |||||||
Accounts payable to affiliated companies | $ 700,000 | 700,000 | ||||||||
Pine Needle Company | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity Method Investment, Ownership Percentage | 45.00% | |||||||||
Investments in equity method unconsolidated affiliates | $ 16,600,000 | 18,400,000 | ||||||||
Equity in earnings of unconsolidated affiliates | $ 2,800,000 | $ 2,700,000 | $ 2,700,000 | |||||||
Pipeline Subscription Capacity Percentage | 100.00% | |||||||||
Summarized Financial Information Percentage | 100.00% | 100.00% | 100.00% | |||||||
Storage Capacity Subscribed | 64.00% | |||||||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||||||
Equity Method Investment, Summarized Financial Information, Current Assets | $ 7,700,000 | $ 9,900,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Noncurrent Assets | 68,100,000 | 71,600,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Current Liabilities | 3,000,000 | 5,400,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities | 35,200,000 | 35,100,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Revenue | 17,100,000 | 16,900,000 | $ 18,000,000 | |||||||
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss) | 15,400,000 | 15,300,000 | 15,300,000 | |||||||
Equity Method Investment, Summarized Financial Information, Net Income (Loss) | 6,800,000 | 6,000,000 | 6,000,000 | |||||||
Pine Needle Company | Equity Method Investee [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Related party expenses | 10,700,000 | 11,400,000 | 11,400,000 | |||||||
Accounts payable to affiliated companies | $ 900,000 | 1,000,000 | ||||||||
South Star Energy Services | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity Method Investment, Ownership Percentage | 0.00% | 15.00% | ||||||||
Equity Method Investment, Ownership Percentage Sold | 15.00% | |||||||||
Investments in equity method unconsolidated affiliates | $ 0 | 41,300,000 | ||||||||
Equity in earnings of unconsolidated affiliates | $ 18,800,000 | $ 19,400,000 | $ 20,400,000 | |||||||
Summarized Financial Information Percentage | 100.00% | 100.00% | 100.00% | |||||||
Net proceeds from the sales of interests in unconsolidated affiliates and other assets | $ 160,000,000 | |||||||||
Gain on Sale of Investments | $ 80,900,000 | |||||||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||||||
Equity Method Investment, Summarized Financial Information, Current Assets | $ 212,200,000 | $ 204,200,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Noncurrent Assets | 126,800,000 | 132,300,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Current Liabilities | 47,100,000 | 46,000,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities | 0 | 0 | ||||||||
Equity Method Investment, Summarized Financial Information, Revenue | 638,300,000 | 769,300,000 | $ 845,700,000 | |||||||
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss) | 216,400,000 | 244,600,000 | 234,600,000 | |||||||
Equity Method Investment, Summarized Financial Information, Net Income (Loss) | 125,500,000 | 129,300,000 | 136,600,000 | |||||||
South Star Energy Services | Equity Method Investee [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Operating revenues | 300,000 | 1,600,000 | 3,500,000 | |||||||
Receivables from affiliated companies | $ 0 | 200,000 | ||||||||
Hardy Storage | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | |||||||||
Investments in equity method unconsolidated affiliates | $ 42,100,000 | 39,700,000 | ||||||||
Equity in earnings of unconsolidated affiliates | $ 5,100,000 | $ 5,200,000 | $ 5,300,000 | |||||||
Summarized Financial Information Percentage | 100.00% | 100.00% | 100.00% | |||||||
Storage Capacity Subscription Percentage | 100.00% | |||||||||
Storage Capacity Subscribed | 40.00% | |||||||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||||||
Equity Method Investment, Summarized Financial Information, Current Assets | $ 6,600,000 | $ 11,700,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Noncurrent Assets | 151,800,000 | 156,800,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Current Liabilities | 14,400,000 | 19,100,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities | 59,100,000 | 70,000,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Revenue | 23,500,000 | 23,400,000 | $ 23,800,000 | |||||||
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss) | 23,500,000 | 23,400,000 | 23,800,000 | |||||||
Equity Method Investment, Summarized Financial Information, Net Income (Loss) | 11,000,000 | 10,400,000 | 10,500,000 | |||||||
Hardy Storage | Equity Method Investee [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Related party expenses | 9,300,000 | 9,300,000 | 9,500,000 | |||||||
Accounts payable to affiliated companies | $ 800,000 | 800,000 | ||||||||
Constitution Pipeline Company | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity Method Investment, Ownership Percentage | 24.00% | |||||||||
Investments in equity method unconsolidated affiliates | $ 93,100,000 | 82,400,000 | ||||||||
Equity in earnings of unconsolidated affiliates | $ (1,300,000) | $ 6,100,000 | $ 2,700,000 | |||||||
Pipeline Subscription Capacity Percentage | 100.00% | |||||||||
Summarized Financial Information Percentage | 100.00% | 100.00% | 100.00% | |||||||
Estimated Pipeline Development And Construction Costs | $ 955,000,000 | |||||||||
Estimated Contributions For Pipeline And Construction Costs | 229,300,000 | |||||||||
Capital contributions to or payments to acquire equity method investments | 12,100,000 | |||||||||
Total Contributions To Equity Method Investments For Project | $ 84,800,000 | |||||||||
Target Pipeline In Service Date | 2018 | |||||||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||||||
Equity Method Investment, Summarized Financial Information, Current Assets | $ 6,600,000 | $ 6,200,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Noncurrent Assets | 380,900,000 | 330,200,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Current Liabilities | 1,200,000 | 4,400,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities | 0 | 0 | ||||||||
Equity Method Investment, Summarized Financial Information, Revenue | 0 | 0 | $ 0 | |||||||
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss) | 0 | 0 | 0 | |||||||
Equity Method Investment, Summarized Financial Information, Net Income (Loss) | (3,400,000) | 24,600,000 | 10,100,000 | |||||||
Equity Method Investment, Other than Temporary Impairment | $ 0 | |||||||||
Atlantic Coast Pipeline | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Equity Method Investment, Ownership Percentage | 7.00% | 10.00% | ||||||||
Equity Method Investment, Ownership Percentage Sold | 3.00% | |||||||||
Investments in equity method unconsolidated affiliates | $ 33,200,000 | 10,100,000 | ||||||||
Equity in earnings of unconsolidated affiliates | $ 1,700,000 | $ (600,000) | $ 0 | |||||||
Summarized Financial Information Percentage | 100.00% | 100.00% | ||||||||
Net proceeds from the sales of interests in unconsolidated affiliates and other assets | $ 13,900,000 | |||||||||
Capital contributions to or payments to acquire equity method investments | $ 35,300,000 | |||||||||
Total Contributions To Equity Method Investments For Project | $ 46,000,000 | |||||||||
Target Pipeline In Service Date | 2019 | |||||||||
Long-term Purchase Commitment, Period | 20 years | |||||||||
Estimated Percentage Project Financing | 60.00% | |||||||||
Estimated Percentage Debt Financing | 50.00% | |||||||||
Estimated Percentage Equity Financing | 50.00% | |||||||||
Maximum Funding Obligation Under Equity Contribution Agreements | $ 10,600,000 | |||||||||
Equity Method Investment, Summarized Financial Information [Abstract] | ||||||||||
Equity Method Investment, Summarized Financial Information, Current Assets | 134,300,000 | $ 23,400,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Noncurrent Assets | 376,300,000 | 86,100,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Current Liabilities | 47,900,000 | 9,100,000 | ||||||||
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities | 0 | 0 | ||||||||
Equity Method Investment, Summarized Financial Information, Revenue | 0 | 0 | ||||||||
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss) | 0 | 0 | ||||||||
Equity Method Investment, Summarized Financial Information, Net Income (Loss) | 17,300,000 | $ (5,200,000) | ||||||||
Atlantic Coast Pipeline | Minimum | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Estimated Pipeline Development And Construction Costs | 4,500,000,000 | |||||||||
Atlantic Coast Pipeline | Maximum | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Estimated Pipeline Development And Construction Costs | $ 5,000,000,000 | |||||||||
|
Business Segments (Details) $ in Millions |
3 Months Ended | 12 Months Ended | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Oct. 31, 2016
USD ($)
|
Jul. 31, 2016
USD ($)
|
Apr. 30, 2016
USD ($)
|
Jan. 31, 2016
USD ($)
|
Oct. 31, 2015
USD ($)
|
Jul. 31, 2015
USD ($)
|
Apr. 30, 2015
USD ($)
|
Jan. 31, 2015
USD ($)
|
Oct. 31, 2016
USD ($)
segment
|
Oct. 31, 2015
USD ($)
|
Oct. 31, 2014
USD ($)
|
||||
Segment Reporting Information [Line Items] | ||||||||||||||
Number of Reportable Segments | segment | 1 | |||||||||||||
Segment Reporting, Disclosure of Major Customers | 0 | |||||||||||||
Segment Reporting Information [Abstract] | ||||||||||||||
Total Assets | $ 5,691.0 | $ 5,086.3 | $ 5,691.0 | $ 5,086.3 | $ 4,719.8 | |||||||||
Noncurrent Asset Additions | 569.2 | 473.4 | 498.1 | |||||||||||
Segment Reporting Information, Profit (Loss) [Abstract] | ||||||||||||||
Unaffiliated revenues | 1,141.7 | |||||||||||||
Revenue from Duke Energy | 7.0 | [1] | ||||||||||||
Total operating revenues | 171.9 | $ 160.4 | $ 352.9 | $ 463.5 | 184.1 | $ 162.2 | $ 427.3 | $ 609.5 | 1,148.7 | 1,383.1 | 1,479.5 | |||
Interest Expense | 68.6 | 68.6 | 54.7 | |||||||||||
Depreciation and amortization | 137.3 | 128.7 | 119.0 | |||||||||||
Equity in earnings of unconsolidated affiliates | 28.6 | 34.5 | 32.8 | |||||||||||
Gain on sale of unconsolidated affiliates | 132.8 | 0.0 | 0.0 | |||||||||||
Income tax expense | 124.2 | 90.2 | 94.8 | |||||||||||
Net income | 38.7 | $ (6.7) | $ 63.4 | $ 97.8 | (14.1) | $ (8.3) | $ 66.4 | $ 93.0 | 193.2 | 137.0 | 143.8 | |||
Retail Natural Gas | ||||||||||||||
Segment Reporting Information, Profit (Loss) [Abstract] | ||||||||||||||
Total operating revenues | 1,066.3 | 1,237.4 | 1,300.5 | |||||||||||
Wholesale Natural Gas | ||||||||||||||
Segment Reporting Information, Profit (Loss) [Abstract] | ||||||||||||||
Total operating revenues | 72.3 | 134.3 | 169.5 | |||||||||||
Other Revenues | ||||||||||||||
Segment Reporting Information, Profit (Loss) [Abstract] | ||||||||||||||
Total operating revenues | 10.1 | 11.4 | 9.5 | |||||||||||
Gas Utilities and Infrastructure | ||||||||||||||
Segment Reporting Information [Abstract] | ||||||||||||||
Total Assets | 5,691.0 | 5,045.0 | 5,691.0 | 5,045.0 | 4,678.8 | |||||||||
Noncurrent Asset Additions | 569.2 | 473.4 | 498.1 | |||||||||||
Segment Reporting Information, Profit (Loss) [Abstract] | ||||||||||||||
Unaffiliated revenues | 1,141.7 | |||||||||||||
Revenue from Duke Energy | 7.0 | |||||||||||||
Total operating revenues | 1,148.7 | 1,383.1 | 1,479.5 | |||||||||||
Interest Expense | 68.6 | 68.6 | 54.7 | |||||||||||
Depreciation and amortization | 137.3 | 128.7 | 119.0 | |||||||||||
Equity in earnings of unconsolidated affiliates | 9.8 | 15.1 | 12.3 | |||||||||||
Gain on sale of unconsolidated affiliates | 0.0 | |||||||||||||
Income tax expense | 85.2 | 85.9 | 87.0 | |||||||||||
Net income | 143.3 | 131.1 | 131.2 | |||||||||||
Other Segments | ||||||||||||||
Segment Reporting Information [Abstract] | ||||||||||||||
Total Assets | $ 0.0 | $ 41.3 | 0.0 | 41.3 | 41.0 | |||||||||
Noncurrent Asset Additions | 0.0 | 0.0 | 0.0 | |||||||||||
Segment Reporting Information, Profit (Loss) [Abstract] | ||||||||||||||
Unaffiliated revenues | 0.0 | |||||||||||||
Revenue from Duke Energy | 0.0 | |||||||||||||
Total operating revenues | 0.0 | 0.0 | 0.0 | |||||||||||
Interest Expense | 0.0 | 0.0 | 0.0 | |||||||||||
Depreciation and amortization | 0.0 | 0.0 | 0.0 | |||||||||||
Equity in earnings of unconsolidated affiliates | 18.8 | 19.4 | 20.5 | |||||||||||
Gain on sale of unconsolidated affiliates | 132.8 | |||||||||||||
Income tax expense | 39.0 | 4.3 | 7.8 | |||||||||||
Net income | $ 49.9 | $ 5.9 | $ 12.6 | |||||||||||
|
Related Party Transactions with Duke Energy (Details) - USD ($) $ in Millions |
3 Months Ended | 12 Months Ended | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Oct. 31, 2016 |
Jul. 31, 2016 |
Apr. 30, 2016 |
Jan. 31, 2016 |
Oct. 31, 2015 |
Jul. 31, 2015 |
Apr. 30, 2015 |
Jan. 31, 2015 |
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
|||||
Related Party Transaction [Line Items] | |||||||||||||||
Revenue, Net | $ 171.9 | $ 160.4 | $ 352.9 | $ 463.5 | $ 184.1 | $ 162.2 | $ 427.3 | $ 609.5 | $ 1,148.7 | $ 1,383.1 | $ 1,479.5 | ||||
Accounts payable to affiliated companies | [1],[2] | 8.7 | $ 2.5 | 8.7 | 2.5 | ||||||||||
Duke Energy | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Revenue, Net | 80.8 | $ 83.2 | $ 86.2 | ||||||||||||
Related party expenses | 0.2 | ||||||||||||||
Duke Energy | Duke Energy RSU Award | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Accounts payable to affiliated companies | $ 6.1 | $ 6.1 | |||||||||||||
|
Severance (Details) - Severance $ in Millions |
12 Months Ended |
---|---|
Oct. 31, 2016
USD ($)
| |
Restructuring Cost and Reserve [Line Items] | |
Severance Charges | $ 18.7 |
Severance Liability | $ 18.7 |
Reclassification of Financial Statements - Adoption of New Accounting Guidance (Details) $ in Millions |
Oct. 31, 2015
USD ($)
|
---|---|
Accounting Standards Update 2015-17 [Member] | Scenario, Previously Reported | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Deferred Tax Assets, Net, Current | $ 32.4 |
Reclassifications of Consolidated Financial Statements - Duke Acquisition (Details) - Scenario, Previously Reported - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Oct. 31, 2015 |
Oct. 31, 2014 |
|
Operating Income Tax Expense Benefit | $ 76.9 | $ 83.2 |
Non Operating Income Tax Expense Benefit | $ 13.3 | $ 11.6 |
Quarterly Financial Data (Details) - USD ($) $ in Millions |
3 Months Ended | 12 Months Ended | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Oct. 31, 2016 |
Jul. 31, 2016 |
Apr. 30, 2016 |
Jan. 31, 2016 |
Oct. 31, 2015 |
Jul. 31, 2015 |
Apr. 30, 2015 |
Jan. 31, 2015 |
Oct. 31, 2016 |
Oct. 31, 2015 |
Oct. 31, 2014 |
Oct. 03, 2016 |
|
Quarterly Financial Data [Abstract] | ||||||||||||
Operating Revenues | $ 171.9 | $ 160.4 | $ 352.9 | $ 463.5 | $ 184.1 | $ 162.2 | $ 427.3 | $ 609.5 | $ 1,148.7 | $ 1,383.1 | $ 1,479.5 | |
Operating Income (Loss) | (50.3) | 0.5 | 103.9 | 171.3 | (8.8) | (1.7) | 111.1 | 162.2 | 225.4 | 262.8 | 263.1 | |
Net income (loss) | $ 38.7 | $ (6.7) | $ 63.4 | $ 97.8 | $ (14.1) | $ (8.3) | $ 66.4 | $ 93.0 | $ 193.2 | $ 137.0 | $ 143.8 | |
South Star Energy Services | ||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||
Equity Method Investment, Ownership Percentage Sold | 15.00% |
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