Securities registered or to be registered pursuant to Section 12(g) of the Act:
None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report:

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No o

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes o No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer ý Accelerated filer o Non-accelerated filer o

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

If "Other" has been checked in response to the previous question indicate by check mark which financial statement item the registrant has elected to follow. Item 17 o Item 18 o

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

This Amendment No. 1 on Form 20-F/A (the "Form 20-F/A") is being filed by Brookfield Infrastructure Partners L.P. (the "Registrant") to amend the Registrant's Annual Report on Form 20-F for the fiscal year ended December 31, 2013, filed with the Securities and Exchange Commission on March 28, 2014 (the "Form 20-F"). This Form 20-F/A is being filed solely to supplement Item 18 of the Form 20-F with the inclusion of the financial statements of Myria Holdings Inc. for the fiscal year ended December 31, 2013 (the "Myria Financial Statements") pursuant to Rule 3-09 of Regulation S-X.

As required by Rule 12b-15 under the Securities Exchange Act of 1934, as amended, updated certifications of our principal executive officer and our principal financial officer are being filed as exhibits to the Form 20-F/A. The Form 20-F/A also includes Exhibit 15.2, which contains the consent of PricewaterhouseCoopers LLP with respect to the Myria Financial Statements.

This Form 20-F/A consists solely of a cover page, this explanatory note, the Myria Financial Statements, updated certifications of our principal executive officer and our principal executive officer, Exhibit 15.2 and a signature page.

Except as described above, this Form 20-F/A does not amend, update or restate the information in any other item of the Form 20-F, or reflect any events that have occurred after the original filing of the Form 20-F.

Consolidated Financial Statements as of December 31, 2013 and 2012 and
for the years ended December 31, 2013 and 2012,
the six months ended December 31, 2011 and
the year ended June 30, 2011

We have audited the accompanying consolidated financial statements of Myria Holdings Inc. and its subsidiaries (the "Company"), which comprise the consolidated balance sheets as of December 31, 2013 and December 31, 2012, and the related consolidated statements of operations, comprehensive income, shareholders' equity and of cash flows for the years then ended.

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Our responsibility is to express an opinion on the consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Myria Holdings Inc. and its subsidiaries at December 31, 2013 and December 31, 2012, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

CONSOLIDATED STATEMENTS OF OPERATIONS

For the years ended December 31, 2013, December 31, 2012 and
the six months ended December 31, 2011 and
the year ended June 30, 2011

(USD 000's)

	Year Ended December 31, 2013			Year Ended December 31, 2012			Six months ended December 31, 2011			Year Ended June 30, 2011

	(in thousands)			(in thousands)			(in thousands)			(in thousands)
							(Not covered by Auditor's Report)			(Not covered by Auditor's Report)
OPERATING REVENUES
Transportation and storage	$	598,162		$	649,561		$	355,686		$	793,401
Natural gas sales		19,341			16,292			38,562			91,299
Other income		1,378			806			366			3,398

Total operating revenues		618,881			666,659			394,614			888,098

OPERATING COSTS AND EXPENSES
Purchases and other costs of sales		95,997			58,904			86,938			177,317
Operations and maintenance		178,838			185,965			94,300			171,031
General and administrative		41,300			42,447			19,888			50,799
Depreciation and amortization		90,046			88,434			44,013			84,235
Taxes, other than income taxes		27,483			31,845			16,199			33,937
Goodwill impairment		560,042			319,460			800,000			—
Other expenses (income)		(20,053	)		(14,821	)		(27,783	)		(23,609	)

Total operating costs and expenses		973,653			712,234			1,033,555			493,710

Operating (loss) income		(354,774	)		(45,575	)		(638,941	)		394,388

OTHER INCOME AND (EXPENSES)
Loss on Early Extinguishment of Debt		—			(37,852	)		—			—
Interest expense		(422,247	)		(493,820	)		(214,343	)		(421,466	)
Interest income (unrestricted)		1,032			1,173			600			1,343
Equity in earnings of Horizon		2,547			1,851			563			1,419
Other, net		2,072			1,674			(647	)		(333	)

Total other income and (expenses)		(416,596	)		(526,974	)		(213,827	)		(419,037	)

LOSS BEFORE INCOME TAXES		(771,370	)		(572,549	)		(852,768	)		(24,649	)
Income tax benefit		(78,273	)		(99,400	)		(17,881	)		(7,312	)

Net loss		(693,097	)		(473,149	)		(834,887	)		(17,337	)

Net loss attributable to non-controlling interests		(113,690	)		(56,225	)		(152,111	)		(25,233	)

Net loss attributable to Myria Holdings Inc.	$	(579,407	)	$	(416,924	)	$	(682,776	)	$	(42,570	)

The accompanying notes are an integral part of these consolidated financial statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the years ended December 31, 2013, December 31, 2012 and
the six months ended December 31, 2011 and the
year ended June 30, 2011

(USD 000's)

	Year Ended December 31, 2013			Year Ended December 31, 2012			Six Months Ended December 31, 2011			Year Ended June 30, 2011

	(in thousands)			(in thousands)			(in thousands)			(in thousands)
							(Not covered by Auditor's Report)			(Not covered by Auditor's Report)
Net loss	$	(693,097	)	$	(473,149	)	$	(834,887	)	$	(17,337	)

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Change in Fair Value of Derivatives Utilized for Hedging Purposes (Net of Tax (Benefit)/Expense of $1,158, ($119), ($2,089) and $7,931)		1,960			(194	)		(3,419	)		12,978
Reclassification of Change in Fair Value of Derivatives to Net Loss (Net of Tax (Benefit)/Expense of $1,816, ($27,089), $5,106 and $6,858)		(3,075	)		44,330			(8,355	)		(11,222	)

Total other comprehensive income (loss)		(1,115	)		44,136			(11,774	)		1,756

Comprehensive loss		(694,212	)		(429,013	)		(846,661	)		(15,581	)

Comprehensive income (loss) attributable to non-controlling interests		(223	)		8			(214	)		(1,634	)

Comprehensive loss attributable to Myria Holdings inc.	$	(693,989	)	$	(429,021	)	$	(846,447	)	$	(13,947	)

The accompanying notes are an integral part of these consolidated financial statements.

CONSOLIDATED BALANCE SHEETS

As of December 31, 2013 and December 31, 2012
(USD 000's)

	December 31, 2013			December 31, 2012

	(in thousands)			(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$	93,409		$	67,046
Restricted cash and deposits		1,556			—
Accounts receivable, net		53,847			80,981
Gas in underground storage		51,919			51,822
Materials and supplies		27,087			27,230
Gas imbalances		42,854			19,568
Fair value of derivatives		730			2,401
Prepaid income taxes		1,680			9,047
Other		7,502			8,019

Total current assets		280,584			266,114

Investments		10,073			11,626
Goodwill		2,598,556			3,158,599
Property, plant and equipment
Property, plant and equipment, at cost		1,924,443			1,905,800
Less: Accumulated depreciation and amortization		(302,332	)		(249,730	)

Total property, plant and equipment		1,622,111			1,656,070

Deferred charges and other assets		42,626			49,058

Total assets	$	4,553,950		$	5,141,467

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable	$	46,613		$	47,305
Accrued interest		10,093			9,950
Accrued taxes		16,782			24,151
Gas imbalances		24,520			10,947
Fair value of derivatives		468			324
Current maturities of long-term debt		50,000			15,000
Other liabilities		28,540			15,069

Total current liabilities		177,016			122,746

Other liabilities and deferred credits
Deferred income taxes, net		146,039			230,534
Other		23,695			13,205

Total other liabilities and deferred credits		169,734			243,739

Long-term debt
Long-term debt, less current maturities		2,918,532			2,982,808
Senior notes payable, related party		—			1,634,439
Senior notes accrued interest, payable in kind		—			20,962

Total long-term debt		2,918,532			4,638,209

SHAREHOLDERS' EQUITY
Common stock		—			—
Additional paid-in capital		3,504,977			1,657,270
Accumulated deficit		(2,433,561	)		(1,854,154	)
Accumulated other comprehensive income		9,070			9,962
Non-controlling Interests		208,182			323,695
Total shareholders' equity		1,288,668			136,773

Total liabilities and shareholders' equity	$	4,553,950		$	5,141,467

The accompanying notes are an integral part of these consolidated financial statements.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

For the years ended December 31, 2013, December 31, 2012 and
the six months ended December 31, 2011 and the year ended June 30, 2011

(USD 000's)

		Common Stock		Additional Paid in Capital		Retained Deficit			Accumulated Other Comprehensive Income/(Loss)			Non- controlling Interests			Total

Balances at July 1, 2010 (Not covered by Auditor's Report)	10,591.99	$	—	$	978,144	$	(711,884	)	$	(25,995	)	$	544,699		$	784,964
Net loss	—		—		—		(42,570	)		—			25,233			(17,337	)
Management contribution	—		—		6,300		—			—			—			6,300
Dividends	—		—		—		—			—			(25,233	)		(25,233	)
Return of capital	—		—		—		—			—			(2,740	)		(2,740	)
Issuance of Common Stocks	—		—		60,000		—			—			—			60,000
Net change in fair value of derivatives utilized for hedging purposes	—		—		—		—			10,844			2,134			12,978
Reclassification of change in fair value of derivatives to net income	—		—		—		—			(7,454	)		(3,768	)		(11,222	)
Balances at June 30, 2011 (Not covered by Auditor's Report)	10,591.99	$	—	$	1,044,444	$	(754,454	)	$	(22,605	)	$	540,325		$	807,710
Net loss	—		—		—		(682,776	)		—			(152,111	)		(834,887	)
Management contribution	—		—		2,520		—			—			—			2,520
Return of capital	—		—		—		—			—			(11,814	)		(11,814	)
Net change in fair value of derivatives utilized for hedging purposes	—		—		—		—			(5,590	)		2,171			(3,419	)
Reclassification of change in fair value of derivatives to net income	—		—		—		—			(5,971	)		(2,384	)		(8,355	)
Balances at December 31, 2011 (Not covered by Auditor's Report)	10,591.99	$	—	$	1,046,964	$	(1,437,230	)	$	(34,166	)	$	376,187		$	(48,245	)

The accompanying notes are an integral part of these consolidated financial statements.

For the years ended December 31, 2013, December 31, 2012 and
the six months ended December 31, 2011 and the year ended June 30, 2011

			Common Stock		Additional Paid in Capital			Retained Deficit			Accumulated Other Comprehensive Income/(Loss)			Non- controlling Interests			Total

Balances at December 31, 2011 (Not covered by Auditor's Report)	10,591.99		$	—	$	1,046,964		$	(1,437,230	)	$	(34,166	)	$	376,187		$	(48,245	)
Net loss	—			—		—			(416,924	)		—			(56,225	)		(473,149	)
Management contribution	—			—		4,933			—			—			—			4,933
Cash contributed from shareholders	—			—		600,000			—			—			15,000			615,000
Common stock and senior notes contributed from shareholders	(42.67	)		—		5,373			—			—			—			5,373
Return of capital	—			—		—			—			—			(11,275	)		(11,275	)
Net change in fair value of derivatives utilized for hedging purposes	—			—		—			—			(202	)		8			(194	)
Reclassification of change in fair value of derivatives to net income	—			—		—			—			44,330			—			44,330
Balances at December 31, 2012	10,549.32		$	—	$	1,657,270		$	(1,854,154	)	$	9,962		$	323,695		$	136,773
Net loss	—			—		—			(579,407	)		—			(113,690	)		(693,097	)
Management contribution	—			—		4,615			—			—			—			4,615
Senior Notes and PIK interest contributed from shareholders	—			—		1,843,273			—			—			—			1,843,273
Charge off of Senior Notes issuance costs previously deferred	—			—		(181	)		—			—			—			(181	)
Return of capital	—			—		—			—			—			(1,600	)		(1,600	)
Net change in fair value of derivatives utilized for hedging purposes	—			—		—			—			1,568			392			1,960
Reclassification of change in fair value of derivatives to net income	—			—		—			—			(2,460	)		(615	)		(3,075	)
Balances at December 31, 2013	10,549.32		$	—	$	3,504,977		$	(2,433,561	)	$	9,070		$	208,182		$	1,288,668

The accompanying notes are an integral part of these consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31, 2013, December 31, 2012 and
the six months ended December 31, 2011 and the year ended 30 June 2011

(USD 000's)	Year Ended December 31, 2013			Year Ended December 31, 2012			Six Months Ended December 31, 2011			Year Ended June 30, 2011

	(in thousands)			(in thousands)			(in thousands)			(in thousands)
							(Not covered by Auditor's Report)			(Not covered by Auditor's Report)
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES
Net loss	$	(693,097	)	$	(473,149	)	$	(834,887	)	$	(17,337	)
Adjustments to reconcile net loss to net cash flows provided by operating activities
Loss on Early Extinguishment of Debt		—			37,852			—			—
Goodwill impairment		560,042			319,460			800,000			—
Depreciation and amortization		90,046			88,434			44,013			84,235
Amortization of financing costs		42			2,648			2,947			4,526
Amortization of debt premium on long-term debt		(4,180	)		(9,236	)		(7,537	)		(13,008	)
Deferred income taxes		(85,501	)		(99,664	)		(15,292	)		8,876
Equity in earnings of Horizon		(2,547	)		(1,851	)		(563	)		(1,419	)
Distributions of earnings from Horizon		2,547			1,851			450			1,419
Carrying value adjustment to natural gas inventories and cushion gas		690			5,041			11,807			13,661
Carrying value adjustment to materials and supplies inventories		1,609			—						—
Interest paid in kind		191,337			163,108			73,716			69,654
Interest paid with common stock		—			—			—			60,000
Gain from sales of cushion gas		(21,755	)		(16,441	)		(27,937	)		(23,085	)
Parking service revenue deferrals		10,809			—			—			—
Ineffective portion of interest rate swap contract		—			2,204			5,747			12,276
Loss on extinguishment of interest rate swap		—			65,347			—			—
Tender premium on early extinguishment of debt		—			(40,866	)		—			—
Changes in working capital items
Restricted cash and deposits		—			12,071			(12,071	)		—
Gas in underground storage		(97	)		(11,747	)		29,133			(7,983	)
Accounts receivable		5,928			10,348			(21,751	)		23,998
Materials and supplies inventories		(1,466	)		(1,760	)		970			(384	)
Other current assets		(15,129	)		(9,926	)		(7,923	)		14,264
Accounts payable		(4,527	)		(5,978	)		29,200			4,715
Accrued interest		(3,322	)		(2,814	)		5,221			(43,712	)
Other current liabilities		21,245			27,539			(11,667	)		(33,703	)
Other, net		6,574			4,703			1,017			3,077

Net cash provided by operating activities		59,248			67,174			64,593			160,070
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(52,173	)		(49,301	)		(37,425	)		(63,109	)
Asset disposal costs		(7,512	)		(5,180	)		—			—
Proceeds from restricted deposits		—			—			1,006			664
Proceeds from sales of assets, net of disposal costs		49,668			25,590			9,076			17,656
Distributions from Horizon in excess of earnings		1,553			1,099			—			381
Proceeds from investments in restricted deposits		(1,556	)		44			—			—

Net cash used in investing activities		(10,020	)		(27,748	)		(27,343	)		(44,408	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-term debt		—			1,250,000			—			(24,300	)
Repayments of Long-term debt		(25,880	)		(1,743,400	)		(74,886	)		(56,714	)
Settlement of interest rate swap		—			(101,018	)					—
Debt issuance and restructuring costs		—			(31,284	)		(638	)		(2,100	)
Dividends paid		—			—			—			(25,233	)
Return of capital		(1,600	)		(11,275	)		(11,814	)		(2,740	)
Contribution from shareholders for management fees		4,615			4,933			—			—
Contribution from shareholders		—			600,000			2,520			6,300
Contribution from Non-controlling Interest		—			15,000			—			—

Net cash used in financing activities		(22,865	)		(17,044	)		(84,818	)		(104,787	)

Net increase in cash and cash equivalents		26,363			22,382			(47,568	)		10,875

CASH AND CASH EQUIVALENTS
Beginning of period		67,046			44,664			92,232			81,357

End of period	$	93,409		$	67,046		$	44,664		$	92,232

For the years ended December 31, 2013, December 31, 2012 and
the six months ended December 31, 2011 and the year ended 30 June 2011

The accompanying notes are an integral part of these consolidated financial statements.

MYRIA HOLDINGS INC. AND SUBSIDIARIES

ANNUAL REPORT DECEMBER 2013

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Myria Holdings Inc. ("Myria" or the "Company") is an investment holding company incorporated in Delaware on January 30, 2008. Myria is owned by a syndicate (the "Syndicate") of investors.

Myria, through a series of intermediary companies, owns an 80% interest of NGPL PipeCo LLC ("PipeCo"). PipeCo was previously a wholly owned subsidiary of Kinder Morgan Inc. ("KMI") who, also through a series of intermediary companies, owns the remaining 20% interest of PipeCo. In May of 2012, Myria and KMI contributed their respective shares of PipeCo to NGPL HoldCo LLC ("Holdco") in return for new equity interests in Holdco. Concurrently, Holdco made a contribution of the shares to Midco LLC ("Midco") in return for the sole membership interest in Midco. Therefore, as of May 2012, PipeCo's sole member is Midco, however PipeCo still continues to be indirectly owned 80% by Myria and 20% by KMI.

PipeCo is headquartered in Houston, Texas and through its wholly owned subsidiary Natural Gas Pipeline Company of America LLC, ("Natural") owns and operates a major interstate natural gas pipeline transmission and storage system, consisting primarily of two major interconnected transmission pipelines terminating in the Chicago, Illinois metropolitan area. KMI operates PipeCo pursuant to a 15-year Operations and Reimbursement Agreement (the "O&R Agreement") entered into on February 15, 2008. Natural also operates an approximate 3-mile natural gas pipeline in northern Illinois which is owned by Kinder Morgan Illinois Pipeline LLC ("KMIP"), a wholly owned subsidiary. Natural also owns a 50% investment in Horizon Pipeline Company, L.L.C. ("Horizon"), which is accounted for under the equity method, reflecting Naturals ability to exercise significant influence over its operating and financial policies.

The consolidated financial statements include the accounts of majority-owned subsidiaries. Investments in jointly owned operations in which the Company holds a 50% or less interest and has the ability to exercise significant influence over their operating and financial policies are accounted for under the equity method. All significant intercompany transactions and balances have been eliminated. Certain prior year amounts have been reclassified to conform to the current year presentation. The consolidated financial statements include all revenues and costs directly attributable to the Company and its subsidiaries, as well as allocations of KMI's centralized shared administrative service expenses. All of the allocations and estimates in the consolidated financial statements are based on assumptions that the Company's management believes are reasonable under the circumstances. However, these allocations and estimates are not necessarily indicative of the costs and expenses that would have resulted if the Company had been operated as an independent entity.

In 2012, Myria and PipeCo tested goodwill for impairment at its annual testing date of December 31, 2012. This testing used an internal valuation study to estimate the fair value of PipeCo and Myria to determine whether their carrying value exceeded their fair value and the amounts, if any, of goodwill impairment to record. The valuations used the income approach and the resulting fair value was further verified using the market approach. The income approach is a valuation technique that provides an estimation of the value of a business based on the benefit stream that a business could be expected to generate over its remaining useful life, and is typically applied using a discounted cash flow ("DCF") analysis. The DCF analysis involves discounting the reporting unit's projected future cash flows at an appropriately derived rate, which considers the time value of money, inflation, and the risk

inherent in ownership of the asset or business being valued. The market approach is a valuation technique that provides an estimation of the value of a business using one or more methods that compare the subject reporting unit to similar businesses that have been historically transacted in a marketplace. These valuations indicated that the fair values of PipeCo and Myria were less than their carrying values, which resulted in goodwill impairment charges of $300 million and $19 million, respectively, for a total impairment charge of $319 million at December 31, 2012. As a result of these charges, on an unconsolidated basis, PipeCo and Myria had remaining goodwill of $3,158.6 million and zero, respectively at December 31, 2012.

In 2011 and 2013, PipeCo conducted its annual goodwill impairment testing as of December 31, 2011 and December 31, 2013, respectively. This testing used a valuation approach similar to that used in December 2012, as discussed above, to estimate the fair value of the business. This valuation indicated that the fair value of PipeCo at December 31, 2011 and December 31, 2013, respectively, was less than its carrying value, which resulted in an impairment charge to the goodwill of PipeCo of $800 million and $560.0 million, respectively. As a result of these charges, on an unconsolidated basis, PipeCo and Myria had remaining goodwill of $3,458.6 million and $19.0 million, respectively at December 31, 2011 and $2,958.6 million and zero, respectively at December 31, 2013.

The impairment charge was primarily due to the effects of lower tariffs and lower natural gas volumes transported and related lower contracted storage volumes on Natural's pipeline system.

On December 16, 2011, the Financial Accounting Standards Board ("FASB") issued ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires disclosures to provide information to help reconcile differences in the offsetting requirements under accounting principles generally accepted in the United States of America ("U.S. GAAP") and International Financial Reporting Standards ("IFRS"). The disclosure requirements of this ASU mandate that entities disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an enforceable master netting arrangement or similar agreement. This ASU also requires disclosure of collateral received and posted in connection with master netting arrangements or similar arrangements. The scope of this ASU includes derivative contracts, repurchase agreements, and securities borrowing and lending arrangements. Entities are required to apply the amendments of ASU No. 2011-11 for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. All disclosures provided by those amendments are required to be provided retrospectively for all comparative periods presented. For Myria, ASU No. 2011-11 was effective January 1, 2013, and the adoption of this ASU did have a material impact on its consolidated financial statements.

On January 31, 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. This ASU amends and clarifies the scope of the balance sheet offsetting disclosures prescribed in ASU No. 2011-11 (described above). Specifically, ASU No. 2013-01 limits the scope of ASU No. 2011-11's required disclosures to the following financial instruments, to the extent that they are offset in the financial statements or subject to an enforceable master netting arrangement or similar agreement: (i) recognized derivative contracts accounted for under ASC 815, Derivatives and Hedging; (ii) repurchase agreements and reverse repurchase agreements; and (iii) securities borrowing and securities lending transactions. For Myria, ASU No. 2013-01 was effective

January 1, 2013, and the adoption of this ASU did not have a material impact on its consolidated financial statements.

On February 5, 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This ASU amends and clarifies the disclosure requirements prescribed in ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. ASU No. 2013-02 requires that entities present information about reclassification adjustments from accumulated other comprehensive income in their annual financial statements in a single note or on the face of the financial statements. Public entities will also have to provide this information in their interim financial statements. Specifically, entities must present, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source and the income statement line items affected by the reclassification. If a component is not required to be reclassified to net income in its entirety, entities would instead cross reference to the related footnote for additional information. For Myria, ASU No. 2013-02 was effective January 1, 2013, and the adoption of this ASU did not have a material impact on its consolidated financial statements.

On February 7, 2013, the FASB issued ASU No. 2013-03, Clarifying the Scope and Applicability of a Particular Disclosure to Nonpublic Entities. This ASU clarifies that the requirement in ASU No. 2011-04 to disclose "the level of the fair value hierarchy within which the fair value measurements are categorized in their entirety (Level 1, 2, or 3)" does not apply to nonpublic entities for items that are not measured at fair value in the statement of financial position but for which fair value is disclosed. This ASU was effective immediately and did not have a material impact on the consolidated financial statements.

On January 16, 2014, the FASB issued ASU No. 2014-02, Accounting for Goodwill (a consensus of the Private Company Council). This ASU amends and clarifies the subsequent measurement of goodwill prescribed in ASU No. 2011-08. This ASU provides private entities with an accounting alternative for the subsequent measurement of goodwill. Private entities that elect the accounting alternative would amortize goodwill on a straight-line basis over 10 years, or less than 10 years if the entity demonstrates that another useful life is more appropriate. An entity that elects the alternative is further required to make an accounting policy election to test goodwill for impairment at either the entity level or the reporting unit level, and the test should be completed when a triggering event occurs that indicates the fair value of an entity may be below its carrying amount. The accounting alternative, if elected, should be applied prospectively to goodwill existing as of the beginning of the period of adoption and new goodwill recognized in annual periods beginning after December 15, 2014, and interim periods within annual periods beginning after December 15, 2015. Early application is permitted, including application to any period for which the entity's annual or interim financial statements have not yet been made available for issuance. The Company is currently evaluating this ASU.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of

revenues and expenses. Actual results could differ from these estimates. Certain prior year amounts have been reclassified to conform to the current year presentation.

In July 2011, the Board of Directors of Myria Holdings Inc. determined that, in accordance with its Bylaws, the Company's fiscal year shall begin on January 1 and end on December 31 of each year, starting on January 1, 2012. This resulted in a change in fiscal year end from June 30 to December 31. The required transition period of July 1, 2011 to December 31, 2011 is included in these consolidated financial statements.

Natural's regulated utility operations are accounted for in accordance with the provisions of Accounting Standards Codification ("ASC") Topic 980, Regulated Operations, which prescribes the circumstances in which the application of US GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process.

The following regulatory assets and liabilities are reflected in the accompanying Consolidated Balance Sheets in the captions "Deferred Charges and Other Assets," and "Other Liabilities and Deferred Credits: Other."

As of December 31, 2013 and 2012, $15.8 million and $18.4 million of Natural's regulatory assets, respectively, and all of its regulatory liabilities were being recovered from or refunded to customers through rates over periods ranging from 1 to 12 years. The regulatory asset of $0.5 million at December 31, 2013 related to employee benefit costs is not currently being recovered from customers through rates. The Company believes, however, that eventual recovery through future ratemaking procedures is probable.

In addition, Natural records allowance for funds used during construction ("AFUDC"), which is recorded as part of property plant and equipment. During the years ended December 31, 2013 and 2012 and the six and twelve months ended December 31, 2011 and June 30, 2011, Natural recorded

$0.8 million, $0.7 million, $0.4 million and $1.3 million, respectively, of AFUDC, including both debt and equity components of AFUDC.

The Company recognizes revenues as services are rendered or goods are delivered and, if applicable, title has passed.

The Company, through its wholly owned subsidiaries, provides various types of natural gas transportation and storage services to its customers in which the natural gas remains the property of these customers at all times. In many cases (generally described as "firm service"), the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers' agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as "interruptible service"), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported or injected into/withdrawn from storage under firm service agreements.

"Restricted Deposits" consists principally of funds on deposit with brokers in support of our risk management activities.

The caption "Accounts Receivable, Net" in the accompanying Consolidated Balance Sheets is presented net of allowances for doubtful accounts. The Company's policy for determining an appropriate allowance for doubtful accounts varies according to the type of service being provided and the customers being served. The allowance for doubtful accounts is adjusted as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. The Company had no allowances for doubtful accounts at December 31, 2013 and $0.1 million of allowances for doubtful accounts at December 31, 2012.

In accordance with Natural's transportation tariffs, it collects natural gas in-kind from shippers on its systems. Certain of this gas is used by Natural as fuel in its operations. Fuel collected in excess of operational needs typically is either sold or injected into storage for sales at a later date. Consequently, in the normal course of business, Natural both sells natural gas and maintains natural gas inventories. Only the fuel gas that Natural takes title to under its transportation tariffs is recorded in the accompanying Consolidated Balance Sheets. Natural receives fees from its storage service customers but does not reflect the value of their gas stored in its facilities in the accompanying Consolidated Balance Sheets. Inventories are accounted for using the following methods: last-in, first-out for gas in underground storage and average cost for materials and supplies.

Natural enters into derivative contracts for the purpose of hedging exposures that accompany its operational gas sales and Natural utilizes this risk management activity to formulate a gas sales plan. Natural gas placed in inventory is valued at forecasted realizable value (the "net realizable value") based on the operational gas sales plan. Natural evaluates its natural gas inventory on a quarterly basis and, if the carrying value of inventory is greater than the latest estimate of net realizable value, reduces the carrying value of the natural gas inventory to estimated net realizable value. Natural recorded no pre-tax reductions and $3.8 million of pre-tax reductions in the carrying value of its natural gas storage inventories during the years ended December 31, 2013 and 2012, respectively, and $11.4 million and $13.7 million during the six and twelve months ended December 31, 2011 and June 30, 2011, respectively, reported in the caption "Purchases and Other Costs of Sales" on the Consolidated Statements of Operations.

The Company maintains natural gas in underground storage as part of its inventory, which is recorded in the balance sheet caption "Current Assets: Gas in Underground Storage." This component of inventory represents the portion of gas stored in an underground storage facility generally known as "working gas," and represents an estimate of the portion of gas in these facilities available for routine injection and withdrawal to meet current demand. In addition to this working gas, underground gas storage reservoirs contain injected gas, which is not routinely cycled but, instead, serves the function of maintaining the necessary pressure to allow efficient operation of the facility. This gas, generally known as "cushion gas," is recorded in the balance sheet caption "Property, Plant and Equipment." Working gas that is utilized for operational backup of cushion gas is no longer available for sale and has been transferred from "Current Assets: Gas in Underground Storage" to "Property, Plant and Equipment". This cushion replacement gas is recorded as a separate pool ("cushion replacement pool") from Natural's other cushion gas volumes. Consistent with Natural's policy for recoverable cushion gas, since the cushion replacement pool is expected to eventually be recovered and sold, it is not depreciated. Natural evaluates the carrying value of the cushion replacement pool quarterly against our latest estimate of its net realizable value. If the carrying value exceeds the net realizable value, they reduce the carrying value to the net realizable value. Natural recorded pre-tax reductions in the carrying value of the cushion replacement pool of $0.7 million and $1.2 million during the years ended December 31, 2013 and 2012, and $0.4 million and zero during the six and twelve months ended December 31, 2011 and June 30, 2011, respectively, reported in the caption "Purchases and Other Costs of Sales" on the Consolidated Statements of Operations.

During the year ended December 31, 2013, Natural sold 8 million dekatherms of cushion gas, utilizing principally excess parked customer gas as backup for operational purposes, recording gains totaling $21.8 million.

During the year ended December 31, 2012, Natural sold 6 million dekatherms of cushion gas, utilizing excess parked customer gas as backup for operational purposes, recording gains totaling $16.4 million.

During the six months ended December 31, 2011, Natural sold 6 million dekatherms of cushion gas in anticipation of future storage expansion projects, recording gains totaling $23.1 million, and utilizing excess working gas as backup for operational purposes.

During the twelve months ended June 30, 2011, Natural sold 5 million dekatherms of cushion gas in anticipation of future storage expansion projects, recording gains totaling $24.0 million, and utilizing excess parked customer gas as backup for operational purposes.

During 2013, the Company began classifying the gain associated with its sales of recoverable cushion gas in the Consolidated Statements of Operations within Other Expense (Income). The Company previously recorded sales of recoverable cushion gas in the Consolidated Statements of Operations gross within Natural Gas Sales and Purchases and Other Costs of Sales. The Company has reclassified its 2012 sales and sales for the six and twelve months ended December 31, 2011 and June 30, 2011, respectively, of recoverable cushion gas and has changed its method of classification of such sales within the Consolidated Statements of Operations.

Myria, through its subsidiary Natural, has a 50% ownership in Horizon Pipeline Company LLC ("Horizon"), which is accounted for using the equity method. The balance of the investment in Horizon was $10.1 million and $11.6 million at December 31, 2013 and 2012, respectively. Equity earnings from Horizon were $2.5 million and $1.9 million for the years ended December 31, 2013 and 2012, respectively, and $0.6 million and $1.4 million for the six and twelve months ended December 31, 2011 and June 30, 2011, respectively. The Company received distributions from Horizon of $4.1 million and $3.0 million during the years ended December 31, 2013 and 2012, respectively, and $0.5 million and $1.8 million during the six months and twelve months ended December 31, 2011 and June 30, 2011, respectively.

Property, plant and equipment is reported at its historical acquisition cost. The Company expenses costs for maintenance and repairs in the period incurred. When the Company sells or retires property, plant and equipment, it charges the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. Generally, the Company does not include retirement gains or losses in income except in cases of sales of operating systems or non-depreciable assets such as recoverable cushion gas. Gains and losses on minor system sales, excluding land, are recorded to the appropriate accumulated depreciation reserve. Gains and losses for operating systems sales and land sales are recorded to income or expense accounts in accordance with regulatory accounting guidelines.

The Company computes depreciation on its long-lived assets principally based on the straight-line method over their estimated useful lives. Generally, composite depreciation rates are applied to functional groups of property having similar economic characteristics. Depreciation rates range from 1.8% to 5.0%, excluding certain shorter-lived assets such as vehicles. Depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications,

technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are placed into service, the Company makes an estimate of useful lives (and salvage values where appropriate). However, subsequent events could change these estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on the Company's aggregate depreciation levels from year to year.

Underground gas storage reservoirs contain cushion gas, which is not routinely cycled but, instead, serves the function of maintaining the necessary pressure to allow efficient operation of the facility. Cushion gas is divided into the categories of "recoverable cushion gas" and "unrecoverable cushion gas," based on an engineering analysis of whether the gas can be economically removed from the storage facility at any point during its life. The portion of cushion gas that is determined to be unrecoverable is considered to be a permanent part of the facility itself and is depreciated over the facility's estimated useful life. The portion of cushion gas that is determined to be recoverable is also considered a component of the facility but is not depreciated because it is expected to ultimately be recovered and sold.

The Company reviews the carrying values of its long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. The Company recognizes an impairment loss when estimated future cash flows expected to result from use of the asset and its eventual disposition are less than its carrying amount. With the exception of the pre-tax reductions in the carrying value of cushion replacement gas, as discussed above in Note 4F, the Company did not record any impairments to property, plant and equipment during the years ended December 31, 2013 and 2012, or during the six months ended December 31, 2011 and the twelve months ended June 30, 2011.

The Company recognizes a liability for the fair value of an asset retirement obligation in the period incurred if a reasonable estimate of fair value can be made. A reconciliation of the changes in accumulated asset retirement obligations, which are included in the balance sheet caption "Other Liabilities and Deferred Credits: Other", is as follows:

In general, Natural's system is composed of underground piping, compressor stations and associated facilities, natural gas storage facilities and certain other facilities and equipment. Except as discussed below, Natural is not required to and has no plans to abandon any of these facilities, the majority of which have been providing utility service for many years, making it impossible to determine

the timing of any potential retirement expenditures. Notwithstanding current intentions, in general, if utility operations were to cease in total or in any particular area, Natural would be permitted to abandon the underground piping in place, but would have to remove surface facilities from land belonging to customers or others. No asset retirement obligation has been made for these assets as Natural cannot reasonably estimate when they will be settled in cash. Natural generally has no obligations for removal or remediation with respect to equipment and facilities, such as compressor stations, located on land it owns.

In addition, Natural has various condensate drip tanks located throughout the system, storage wells located within the storage fields, laterals no longer integral to the overall mainline transmission system, compressor stations which are no longer active, and other miscellaneous facilities, all of which have been officially abandoned. For these facilities, it is possible to reasonably estimate the timing of the payment of obligations associated with their retirement. The recognition of these obligations resulted in a combined liability of approximately $1.8 million and $2.0 million at December 31, 2013 and 2012, respectively, which represents the present value of those future obligations for which Natural is able to make reasonable estimations of the current fair value due to, as discussed above, its ability to estimate the timing of the incurrence of the expenditures. The remainder of Natural's asset retirement obligations have not been recorded due to its inability, as discussed above, to reasonably estimate when they will be settled in cash.

Gas imbalances receivable and payable reflect gas volumes owed from or to interconnecting pipelines. During 2013, imbalance volumes were priced at planned hedge prices with a lower of cost or market test performed at the end of each quarter. In June 2013, the value of the imbalances was adjusted to the AMIP (Average Monthly Index Price) to reflect that on a go forward basis imbalance gas injections would be priced at AMIP rather than at the planned hedge prices. Gas imbalances represent the difference between customer nominated versus actual gas receipts from and gas deliveries to interconnecting pipelines under various operational balancing agreements. Gas imbalances are settled in cash terms of the various agreements. Natural had no cash outs on operational balancing agreements for the year ended December 31, 2013, $0.7 million of cash-outs at an average price of $4.15 per dekatherm for the year ended December 31, 2012, $2.3 million of cash-outs for the six months ended December 31, 2011 and $10.8 million of cash-outs for the twelve months ended June 30, 2011.

	Year Ended December 31, 2013			Year Ended December 31, 2012			Six months Ended June 30, 2012			Year Ended June 30, 2011

	(in thousands)			(in thousands)			(in thousands)			(in thousands)
							(Not covered by Auditor's Report)			(Not covered by Auditor's Report)
Interest expense	$	(426,818	)	$	(426,027	)	$	(213,350	)	$	(418,235	)
Ineffective portion of interest rate swap contract		—			(2,204	)		(5,747	)		(12,276	)
Changes in Fair Value of interest rate swap contract		—			(7,181	)		—			—
Loss on settlement of interest rate swap contract		—			(65,347	)		—			—
Amortization of deferred financing costs		(42	)		(2,648	)		(2,947	)		(4,526	)
Amortization of debt premium on long term debt		4,180			9,236			7,537			13,007
AFUDC-Interest (Natural)		433			351			164			564

Interest expense	$	(422,247	)	$	(493,820	)	$	(214,343	)	$	(421,466	)

All highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents. "Other, Net" presented as a component of "Net Cash Flows Provided by Operating Activities" in the accompanying Consolidated Statements of Cash Flows includes, among other things, non-cash charges and credits to income.

Net of interest capitalized, the Company made cash payments for interest of $230.7 million and $259.0 million during the years ended December 31, 2013 and 2012, respectively, and $133.3 million and $329.0 million for the six and twelve months ended December 31, 2011 and June 30, 2011, respectively. Additionally, Myria issued paid in kind notes totaling $191.3 and $163.1 million for the years ended December 31, 2013 and 2012, respectively, and $73.7 and $69.7 million for the six and twelve months ended December 31, 2011 and June 30, 2011, respectively.

The Company made cash payments for income taxes of $1.8 million and $0.6 million during the years ended December 31, 2013 and 2012, respectively, and made no cash payments for income taxes and $2.2 million for the six and twelve months ended December 31, 2011 and June 30, 2011, respectively.

On February 15, 2008, Natural entered into the Operating Agreement (see Note 1) with KMI. The Operating Agreement provides for KMI to be reimbursed, at cost, for pre-approved costs, plus a fixed annual general and administration fee charge for services provided under the Operating Agreement. The fixed annual general and administration fee totaled $35.7 and $35.0 million for the years ended December 31, 2013 and 2012, respectively, and $15.4 million and $43.1 million for the six and twelve

months ended December 31, 2011 and June 30, 2011, respectively. G&A Costs for calendar year 2012 were set at $35.0 million as a result of an the arbitration settlement reached on February 13, 2012 and will escalate by 2% annually through 2014. Thereafter, the G&A Costs will be determined in accordance with the terms of the arbitration settlement agreement.

From time to time in the ordinary course of business, PipeCo buys and sells pipeline services and related services from/to (i) Kinder Morgan Energy Partners, LP and its subsidiaries, affiliates of Kinder Morgan, and (ii) Horizon. Such transactions are conducted in accordance with all applicable laws and regulations and on an arm's-length basis consistent with PipeCo's policies governing such transactions.

Totals of significant receivable (payable) balances with related parties are as follows:

Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized.

For federal income tax purposes, Myria Holdings Inc. is classified as a "C" corporation, Myria Acquisition LLC ("Myria Acquisition") is a disregarded entity ("DRE"), Holdco and Midco are classified as "C" corporations, and the remaining subsidiaries, PipeCo, Natural, and KMIP are

classified as DREs. As a DRE, PipeCo, Natural and KMIP are treated as "divisions" of Midco and are not subject to income taxes on a separate legal entity basis.

Pursuant to the First Amended Tax Allocation Agreement dated May 25, 2012, Myria Holdings Inc., Myria Acquisition, Holdco, and Midco (the "Group") have elected to file a consolidated federal income tax return under Section 1504(a) of the Internal Revenue Code of 1986, as amended. For each taxable year, Holdco will compute the federal income tax liability it would have paid on behalf of itself and Midco, and will pay those combined estimated taxes to Myria Acquisition. Myria Acquisition will perform a similar computation and will pay its estimated taxes (net of its separate company tax benefit) to Myria Holdings Inc. Myria Holdings Inc. will prepare consolidated federal income tax returns and make tax payments on behalf of the Group. After filing of the consolidated federal income tax return, Myria Holdings Inc. will reconcile with Myria Acquisition and Holdco the difference between estimated tax payments received during the tax fiscal year and the final tax liability on the tax return filed with the Internal Revenue Services. A similar mechanism applies in states where the Group files income tax returns on a consolidated, combined or unitary basis.

Natural utilizes energy derivatives for the purpose of mitigating risk resulting from fluctuations in the market price of natural gas and associated transportation costs. Previously, Myria Acquisition utilized an interest rate derivative for the purpose of mitigating exposure to fluctuations in market interest rates until such derivative was cash settled in May 2012. Natural and Myria Acquisition designate their derivative instruments as hedges of various exposures and tests the effectiveness of changes in the value of these hedging instruments with the risk being hedged. Hedge ineffectiveness is recognized in income in the period in which it occurs.

In general, legal costs are expensed as incurred. When significant specific litigation that is expected to continue for a significant period of time and require substantial expenditures has been identified, the Company identifies a range of probable costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement. If no amount within this range is a better estimate than any other amount, a liability equal to the low end of the range is recorded. Any such liability recorded is revised as better information becomes available.

The Company expenses or capitalizes, as appropriate, environmental expenditures that relate to current operations. The Company expenses amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. The Company does not discount environmental liabilities to a net present value. The Company records environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Generally, recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action.

The Company utilizes both internal staff and external experts to assist in identifying environmental issues and in estimating the costs and timing of remediation efforts. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in income in the period in which they are reasonably determinable.

On May 30, 2007, a group of investors, including Kinder Morgan CEO Richard D. Kinder and other members of Kinder Morgan senior management, completed a "Going Private transaction" in which all of the outstanding shares of Kinder Morgan were purchased for $107.50 per share. Prior to the Going Private transaction, there was no goodwill recorded on PipeCo's Consolidated Balance Sheets. The Going Private transaction was accounted for as a purchase and, accordingly, the difference between the purchase price and the fair value of net assets acquired at the time of the Going Private transaction, approximately $5.0 billion, was recorded as goodwill. On February 15, 2008, Myria completed its 80% acquisition of PipeCo resulting in $200 million of additional Goodwill recorded in the Company's Consolidated Balance Sheets.

Myria evaluates goodwill for potential impairment on an annual basis or whenever events or changes in circumstances indicate that the carrying value may not be recoverable.

Natural's interstate natural gas pipeline and storage operations, as well as those of its joint venture investee, are subject to regulation by the FERC. The FERC regulates, among other things, rates and charges for transportation and storage of natural gas in interstate commerce, the construction and operation of interstate pipeline and storage facilities and the accounts and records of interstate pipelines.

On December 4, 2013, Natural and Stingray Pipeline Company, L.L.C. ("Stingray") filed a joint application with the FERC in Docket No. CP14-25-000 requesting authority to abandon by sale to Stingray all the facilities that Natural currently leases to Stingray under Rate Schedule X-50. In addition, Natural filed to abandon the Rate Schedule X-50 long term lease between Natural and Stingray. The application was approved by FERC on February 27, 2014. Natural sold the facilities to Stingray on March 13, 2014.

On October 18, 2013, Natural filed with the FERC in Docket No. CP14-10-000 to: 1) abandon, by sale to Eagle Rock Field Services, L.P. ("Eagle Rock"), Natural's North Moore and Shamrock Laterals located in Moore County, Texas, 2) abandon in place two 1,265 horsepower ("hp") compressor units at Natural's Compressor Station No. 112 located in Moore County, Texas and 3) request a non-jurisdictional determination finding that following abandonment, and upon transfer to Eagle Rock, the North Moore and Shamrock Laterals will become part of Eagle Rock's gathering system and will be non-jurisdictional and not subject to regulation by the FERC under the Natural Gas Act. Natural received authority from the FERC to abandon such facilities on December 23, 2013. Natural sold the aforementioned laterals and abandoned the compressor units on February 14, 2014. The proceeds for this project were $0.5 million and there was no gain or loss recorded in income.

On May 10, 2013, Natural filed with the FERC a prior notice request in Docket No. CP13-476 to convert 1.0 billion cubic feet ("Bcf") of cushion gas storage capacity to working gas storage capacity at its Herscher Mount Simon reservoir located in Kankakee County, Illinois. The project has an estimated total cost of $7 million. Natural received authority from the FERC for the project on July 17, 2013. Work began in July 2013 and is expected to be completed in 2014.

On March 8, 2013, Natural filed with the FERC in Docket No. CP13-97-000 requesting a certificate of public convenience and necessity to increase the maximum inventory at Natural's Cooks Mills Storage Field ("Cooks Mills") located in Douglas and Coles Counties, Illinois by 350 million cubic feet, thereby increasing the maximum inventory at Cooks Mills from 6.4 Bcf to 6.75 Bcf. On July 17, 2013, the FERC issued an order granting Natural's request. No construction is involved in this project.

On September 20, 2011, Natural filed with the FERC a certificate application regarding its Natural Gas Storage Optimization Project. Specifically, Natural requested to: (i) construct and operate a new 3,550 horsepower ("hp") gas fired compressor unit at Natural's existing Compressor Station No. 205 located near Keota in Washington County, Iowa; (ii) construct and operate a new "greenfield" compressor station consisting of a 22,000 hp electric compressor unit to be located near Altamont in Effingham County, Illinois; (iii) reduce cushion gas inventory by 5 billion Bcf at Natural's North Lansing Storage Field located near Longview in Harrison County, Texas; (iv) abandon in place various gas fired compressor units at Natural's Compressor Station Nos. 310 and 311 located respectively near Centralia in Clinton County, Illinois and near Hammond in Piatt County, Illinois and (v) obtain a pre-determination that rolled-in rate treatment for the costs of the proposed facilities is appropriate. The project has a total estimated cost of $57.6 million. On February 1, 2012, the FERC issued its Environmental Assessment Report regarding the project and recommended approval of the project subject to standard mitigation measures for a project of this scope. On May 17, 2012, the FERC approved the project subject to standard environmental conditions. Construction on this project is expected to begin in May 2014.

Myria, through its subsidiaries, is subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters.

Natural had established environmental reserves of approximately $3.0 million as of December 31, 2013 and 2012, to address remediation issues associated with four projects, which are recorded in the balance sheet caption "Other Liabilities and Deferred Credits: Other."

In August 2007, Natural and Kinder Morgan received an information request from the Illinois Attorney General's Office regarding the presence of polychlorinated biphenyls ("PCBs") in natural gas transmission lines. Thereafter, in October 2007, Natural received information requests regarding the presence of PCBs in its natural gas transmission lines in Missouri from the United States Environmental Protection Agency ("EPA"), Region 7 and the Missouri Attorney General's Office. Natural responded to these requests. No proceeding or enforcement actions have been initiated. However, in April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking ("ANPRM") proposing major changes in the way in which PCBs are regulated for all industries, including natural gas pipelines. Although most recently the EPA indicated that a Notice of Proposed Rulemaking would be issued that will not substantially increase the PCB compliance for Natural, there can be no assurance that Natural will not incur additional costs for PCB compliance in the future.

On January 8, 2010, Natural received a Clean Air Act Section 114 information request from the EPA, Region 5. This information request requires that Natural provides the EPA with air permit and various other information related to its natural gas pipeline compressor station operations in Illinois. Natural has responded to this information request and believes its natural gas compressor station operations are in substantial compliance with applicable air quality laws and regulations.

In 2008, Natural conducted a self-audit of Compressor Station 168 and made a report to the Texas Commission on Environmental Quality ("TCEQ") under the Texas Environmental, Health and Safety Audit Privilege Act disclosing that its actual emissions were higher than the emissions limit in its permit due to inaccuracies with the factors used to quantify the emissions at the time the facility permitting was completed, but that the actual emissions over time had remained unchanged. Natural then

submitted a permit application to correct the emissions limits. Following several discussions with the TCEQ staff, the TCEQ voided the permit application and refused to issue the revised permit. The TCEQ asserts that Natural must conduct further work to obtain a permit, including performing an analysis of additional pollution controls for the facility. Natural believed it was entitled to revise the facility's emission limits under Texas law and that the TCEQ's voidance of the permit application was improper and therefore appealed the ruling of the TCEQ to the Texas state court. In March 2013, the state court upheld the TCEQ's decision. Natural did not appeal. In June 2013, the State of Texas (through the Attorney General) filed a civil enforcement action seeking civil penalties, attorneys' fees and injunctive relief to bring the facility into compliance with its existing permit limits. Natural reached a final settlement agreement with the State in the form of an Agreed Order which was entered by the court on January 31, 2014. Under that judgment, Natural paid $175,000 in civil penalties and $27,500 in attorneys' fees. The judgment also establishes a schedule for Natural to obtain a new permit and install pollution control equipment.

In addition, Natural is involved with and has been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves will be established for those sites if and when PipeCo's contribution is believed to be probable and reasonably estimable.

After consideration of reserves established, the Company believes that costs for environmental remediation and ongoing compliance with these laws will not have a material adverse impact on its business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause the Company to incur significant costs.

William r. Justiss ii et al. v. Natural Gas Pipeline Company of America LLC and Kevin Brown

On January 5, 2009, the trial of the lawsuit styled William R. Justiss II et al. v. Natural Gas Pipeline Company of America LLC and Kevin Brown was held in the 62nd Judicial District Court, Lamar County, Texas, in which the owners of seven neighboring properties near rural Howland, Texas sued for damages arising from the operation of a natural gas compressor station owned and operated by Natural. At the conclusion of the trial, the jury returned a verdict finding that the alleged nuisance in the form of noise and odor emitted from the station had existed since 1998 with respect to five of the seven properties in question and found that no nuisance existed for the remaining two properties. On January 30, 2009, the trial court entered judgment in accordance with the verdict rendered. The total principal amount of all compensatory damages found by the jury was $1.2 million. The court also awarded $0.7 million in prejudgment interest and court costs. The total judgment amount is $1.9 million.

On April 30, 2010, the Court of Appeals for the Sixth Appellate District of Texas at Texarkana issued a memorandum opinion that affirmed the trial court's judgment. On December 14, 2012, the Texas Supreme Court reversed the judgment and remanded the case to the trial court for a new trial on liability and damages.

On April 3, 2013, the parties reached a settlement agreement which has been fully executed and funded. All claims have been dismissed by the Court, with prejudice, and the matter is concluded. The settlement did not have a material adverse impact on the Company's business, cash flows, financial position or results of operations.

On August 16, 2011, at Natural's Compressor Station No. 201 in Herscher, Illinois, a crew was performing work inside a compressor building when a flash fire and explosion occurred. Three workers were injured. Natural is working with the Department of Transportation Pipeline and Hazardous Materials Safety Administration to investigate the cause of the incident.

In addition, Natural is a defendant in various lawsuits arising from the day-to-day operations of its business. Although no assurance can be given, the Company believes, based on its experience to date, and with consideration for reserves established, that the ultimate resolution of such matters, including the matters discussed in this Note, will not have a material adverse impact on its business, cash flows, financial position or results of operations.

Neither Myria Holdings Inc. nor Myria Acquisition, LLC are subject to any litigation as of December 31, 2013.

Investments in property, plant and equipment, at cost, and accumulated depreciation and amortization are as follows:

Components of the income tax benefit for federal and state income taxes are as follows:

	Year Ended December 31, 2013			Year Ended December 31, 2012			Six Months Ended December 31, 2011			Year Ended June 30, 2011

	(in thousands)			(in thousands)			(in thousands)			(in thousands)
							(Not covered by Auditor's Report)			(Not covered by Auditor's Report)
Current Taxes
U.S.
Federal	$	6,235		$	—		$	(749	)	$	(17,544	)
State		993			264			(1,840	)		1,356

Total current taxes (Benefit)		7,229			264			(2,589	)		(16,188	)

Deferred Taxes
U.S.
Federal		(78,232	)		(86,961	)		(15,981	)		(9,177	)
State		(7,269	)		(12,703	)		689			(301	)

Total deferred taxes (Benefit)		(85,501	)		(99,664	)		(15,292	)		8,876

Total tax Benefit	$	(78,272	)	$	(99,400	)	$	(17,881	)	$	(7,312	)

Effective tax rate		(10.15	)%		(17.36	)%		(2.10	)%		29.66	%

The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:

	December 31, 2013			December 31, 2012

	(in thousands)			(in thousands)
Deferred Tax Assets
Financing costs	$	10,331		$	11,930
Environmental costs		1,178			1,176
Contributions in aid of construction		16,441			13,012
Capitalized interest		8,351			8,032
Inventory		2,083			—
State Tax Credits		2,100			2,178
Net Operating Losses		233,954			159,290
Other		5,689			8,129
Subtotal	$	280,127		$	203,747
Less: Valuation Allowance		(1,813	)		(1,050	)

Total deferred tax assets	$	278,314		$	202,697

Deferred Tax Liabilities
Property, plant and equipment	$	397,275		$	406,218
Amortization of regulatory assets		5,112			5,381
Partnership income		10,445			9,907
Derivatives		1,061			1,759
Capitalized interest		9,223			8,903
Other		284			1,116

Total deferred tax liabilities	$	423,400		$	433,284

Current deferred tax liabilities		(953	)		53
Noncurrent deferred tax liabilities		146,039			230,534
Net deferred tax liabilities	$	145,086		$	230,587

Under ASC 740-10, the Company must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2013, based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of all deductible temporary differences with the exception of certain state net operating losses. Therefore, the

company has recorded a valuation allowance against a portion of deferred tax assets for state net operating losses that it considers not more likely than not of being realized within their respective carry forward periods. The amount of valuation allowance at the end of the period is $2.8 million.

The Company's practice is to recognize interest and/or penalties related to income tax matters in income tax expense. As of December 31, 2013 and December 31, 2012, the Company had $0.8 million and $1.3 million of accrued interest and $0.8 million and $0.4 million of accrued penalties, respectively. As of December 31, 2011 and June 30, 2011, the Company had $0.9 million and $1.3 million of accrued interest and $0.4 million and $0.4 million of accrued penalties, respectively. The Company believes it is reasonably possible that its liability for unrecognized tax benefits will decrease by $2.2 million during the next twelve months, and believes $2.2 million of the unrecognized tax benefits on its Consolidated Balance Sheets at December 31, 2013 would affect its effective tax rate in future periods in the event those unrecognized tax benefits were recognized.

The Company is subject to taxation and has tax years open to examination for the periods 2007-2012 in the United States, and 2007-2012 in various states.

Current Maturities of long-term debt:	December 31, 2013		December 31, 2012

	(in millions)		(in millions)
Senior Secured Credit Facility, Mandatory Prepayments	$	50	$	15

	$	50	$	15
Long-term debt:
PipeCo Senior Secured Credit Facility, Non-current		599		660
PipeCo 7.119% Senior Notes Due December 15, 2017		1,250		1,250
PipeCo 9.625% Senior Notes Due June 1, 2019		550		550
PipeCo 7.768% Senior Notes Due December 15, 2037		500		500
Unamortized debt (discount) / premium on PipeCo Senior Notes, net		20		23
Myria Senior Notes payable to related parties		—		1,634
Myria Senior Notes, interest payable in kind		—		21
		2,919		4,638

Total debt	$	2,969	$	4,653

The 7.119% and 7.768 senior notes are redeemable in whole or in part, at our option at any time, at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. The indenture for the senior notes includes covenants that, among other things, limits PipeCo's ability and the ability of its subsidiaries to (i) create liens that secure debt, (ii) enter into sale-leaseback transactions, (iii) incur debt, subject to a leverage test, (iv) enter into business outside our present business and (v) merge or consolidate with, or sell, lease or transfer assets substantially as an entirety to another entity. In addition, if PipeCo experience certain kinds of changes of control coupled with a ratings downgrade such that the notes cease to have an investment grade rating, it must give the holders of the notes the opportunity to sell their senior notes to PipeCo at 101% of their principal amount, plus accrued and unpaid interest. As discussed below, the 6.514% senior notes due December 15, 2012 have been repaid in full.

On May 25, 2012, PipeCo closed on its previously announced refinancing plans. This refinancing included (i) the issuance of $550 million of 9.625% senior notes ("2019 Senior Notes") due June 1, 2019, (ii) a new $775 million senior secured credit facility ("Credit Facility") comprised of (1) $700 million of term loans and (2) a $75 million revolving credit facility. In addition, in conjunction with the refinancing, Myria and Kinder Morgan contributed $60 million and $15 million, respectively, of additional equity capital. The proceeds from these debt offerings and capital contributions were used principally to retire approximately $1.21 billion of the $1.25 billion outstanding of the 6.514% senior notes due December 2012 ("2012 Senior Notes"). In conjunction with this refinancing, PipeCo recorded a $41.8 million loss on early extinguishment of debt. This loss included (i) cash premiums of $40.9 million paid to retire its 2012 Senior Notes and (ii) $0.9 million to write off the unamortized debt expenses related to its 2012 Senior Notes and its previous $75 million credit facility, which was terminated concurrently with the closing of the refinancing. The remaining $0.04 billion of our 2012 Senior Notes outstanding were retired in December 2012.

Interest on the 2019 Senior Notes is due on June 1 and December 1 of each year, commencing on December 1, 2012. PipeCo may redeem all or part of the 2019 Senior Notes at its option, at any time, at a price equal to 100% of the principal amount of the notes redeemed plus accrued interest to the redemption date plus a redemption premium per the terms of the offering. If PipeCo sells certain of its assets or experience specific kinds of changes of control, it may be required to repurchase all or a portion of the 2019 Senior Notes. The 2019 Senior Notes are secured by a first priority lien on the capital stock of its two direct operating subsidiaries, Natural and Kinder Morgan Illinois Pipeline LLC (the "Shared Collateral"), which collateral will also equally and ratably secure the obligations under the Credit Facility and 2017 Senior Notes and 2037 Senior Notes outstanding. However, the liens on the Shared Collateral will automatically be released with respect to the 2019 Senior Notes if and to the extent such liens no longer secure any 2017 Senior Notes, 2037 Senior Notes or any replacement notes (whether as a result of a payment in full of such notes or otherwise), which may occur upon the repayment in full of our Credit Facility. Prior to the date, if ever, that the lien on the Shared Collateral securing the notes is released, the 2019 Senior Notes will be the senior secured obligations and will be effectively equal in right of payment with all of the existing and future senior secured indebtedness secured by the Shared Collateral to the extent of the value of the Shared Collateral, but will be effectively junior in right of payment to the existing and any future senior secured indebtedness that is secured by collateral other than the Shared Collateral. The indenture that governs the 2019 Senior Notes includes covenants that, among other things, limits PipeCo's ability and the ability of its subsidiaries to (i) incur or guarantee additional indebtedness or issue certain preferred stock, (ii) pay

dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness, (iii) transfer or sell assets and (iv) consolidate, merge or transfer all or substantially all of our assets. PipeCo incurred $7.4 million of issuance costs in connection with the 2019 Senior Notes.

Also on May 25, 2012, PipeCo entered into a new $775 million Credit Facility due September 15, 2017, with a syndicate of lenders and Credit Suisse AG, as Administrative Agent. The Credit Facility is comprised of (i) term loans on the closing date in an aggregate principal amount of $700 million and (ii) revolving loans that may be made at any time and from time to time prior to the maturity date, in an aggregate principal amount at any time outstanding (when taken together with the face amount of letters of credit then outstanding) not to exceed $75 million. The proceeds from the Credit Facility term loans were used, together with the proceeds from the 2019 Senior Notes described above, to retire substantially all of the then outstanding 2012 Senior Notes. The proceeds from the revolving loans, if any, may be used for general corporate purposes. Loans outstanding under the Credit Facility are secured by the Shared Collateral, as described above. Term loans under the credit facility are subject to mandatory prepayment provisions under the terms of the agreement. Mandatory prepayments under the terms of the agreement include (i) fixed prepayments each June and December, primarily of $25 million each until December 2016 (however, only $7.5 million each in June and December 2013), then increasing to $30 million each and (ii) variable prepayment amounts, generally equal to 60% of "Excess Cash Flow" on a semi-annual basis. In general, Excess Cash Flow is defined as earnings before interest, taxes, depreciation and amortization ("EBITDA") less (i) interest expense, (ii) fixed prepayments of term loans, (iii) capital expenditures, (iv) financing fees and expenses and (v) payments of income tax liabilities. The Credit Facility also includes covenants, which limit us similarly to the covenants applicable to the 2019 Senior Notes, as described above. In addition, the Credit Facility also contains financial covenants that require PipeCo to maintain certain debt and interest to earnings ratios, as well as limits on capital expenditures. As of December 31, 2013 and 2012, PipeCo was in compliance with all of its debt covenants. PipeCo incurred $23.9 million of issuance costs in connection with the Credit Facility.

On March 28, 2013, PipeCo amended the terms of the Credit Facility to reduce the minimum required interest Coverage Ratio and increase the maximum Total Leverage Ratio in certain future periods in exchange for an amendment fee, an extension of call protection provided to lenders and an increase in the variable prepayment amount from 60% to 100% of Excess Cash Flow when the Total Leverage Ratio is greater than 7.00 to 1.00.

Loans under the Credit Facility can be either Alternate Base Rate ("ABR") loans or "Eurodollar" loans. The interest rate on ABR loans equals the ABR plus an applicable margin. The ABR is equal to the greatest of (i) the prime rate in effect on such day, (ii) the Federal Funds rate in effect on such day plus ¹/2 of 1.00% and (iii) the Adjusted LIBO Rate (the greater of (1) 1.25% per annum and (2) the product of (a) the LIBO Rate in effect for such interest period and (b) statutory reserves) as of such date for a one-month interest period plus 1.00%. The interest rate on Eurodollar loans equals the Adjusted LIBO Rate for the applicable interest period plus an applicable margin.

PipeCo currently anticipates remaining in compliance with the financial covenants throughout 2014. However, if future operating performance leads to, or is anticipated to lead to, noncompliance, there are various means by which PipeCo can mitigate such noncompliance, including an equity contribution from PipeCo's parent. The terms of the PipeCo's Credit Facility allow for parent company equity contributions, subject to certain limitations, to be included in the EBITDA amount within the calculation of the Interest Coverage Ratio and Maximum Total Leverage Ratio covenants. Myria has directed NGPL HoldCo LLC, the indirect parent of PipeCo, to maintain no less than $20 million in

cash to be contributed to prevent or cure a PipeCo financial covenant default as contained in Article 6 of the Credit Facility during the remainder of 2014. As of the date of this report, NGPL HoldCo LLC had a cash balance of $50 million available for contribution to PipeCo.

Through December 31, 2013, PipeCo made no revolving loans under the Credit Facility. As of December 31, 2013, PipeCo has $649 million of Eurodollar term loans outstanding under the credit facility at an interest rate of 6.75%.

The estimated fair value of the PipeCo Senior Notes was estimated to be $2.7 billion and $3.2 billion at December 31, 2013 and 2012, respectively.

On May 25, 2012, concurrent with the PipeCo refinancing previously discussed, Myria Acquisition repaid in full all outstanding balances under its Credit Agreement and cash settled the then outstanding associated interest rate swap. Myria Acquisition recorded a loss on early extinguishment of $1.9 million consisting of the write-off of unamortized debt financing costs associated with the Credit Agreement repayment, and recorded a $65.3 million charge to interest expense associated with the swap settlement. Myria Acquisition received cash contributed from Myria Holdings Inc. to complete the debt repayment and swap settlement. Subsequent to this repayment, Myria Acquisition had no outstanding debt.

The Credit Agreement was entered into on February 15, 2008, with a syndicate of lenders to fund its 80% acquisition of the PipeCo. Interest related to the Credit Agreement was calculated at three-month or one-month LIBOR at Myria's option selected in advance, plus a credit margin of 3.25% to 3.5% depending on certain financial covenants. In accordance with a related Pledge and Security Agreement, Myria Acquisition granted the Administrative Agent a first priority perfected lien on its 800 shares of PipeCo and certain personal property. Borrowings under this Credit Agreement were subordinate to the debt agreements with PipeCo. The Credit Agreement also contained financial covenants over Myria Acquisition's financial position, and required quarterly amortization payments and quarterly excess cash flow payments.

On December 19, 2013 the holders of the Myria Senior Notes unanimously agreed to contribute 100% of the Myria Senior Notes and all associated paid in kind interest ("PIK Interest) to the Company as follows:

These Senior Notes were issued on February 15, 2008, to a syndicate of investors who are also the equity owners of the Company.

The Note Purchase Agreement ("NPA") under which the Notes were issued was amended in September and December 2010. As amended, interest related to the NPA was 11.5% per annum payable quarterly in arrears on the 19th of February, May, August and November starting February 2011. Any overdue payment of principal or interest was subject to additional penalty interest at a rate of 13.5% per annum. The NPA did not convey a security interest in the interests of Myria Acquisition nor did it contain any financial covenants, although it did grant a first priority lien on all properties acquired by Myria subsequent to February 15, 2008. Additionally, Myria Holdings Inc. could elect to pay all or any portion of the interest on the notes as "payment in kind," with the amount of such interest being added to the outstanding principal amount of the notes on such interest payment date. Such paid-in-kind interest ("PIK Interest") was deemed paid on the quarterly payment date in the same manner as any interest paid in cash, and such PIK Interest would thereafter accrue interest. Myria Holdings Inc. was unconditionally obligated to prepay in cash all then outstanding principal of the notes constituting PIK Interest by February 2016, which is the fifth anniversary of the first date PIK Interest was paid. Additionally, the Myria Senior Notes contained resale restrictions generally requiring the consent of more than 75% of the Myria stockholders, excluding the consent of the stockholder proposing to make such sale.

Maturities of long-term debt for the five years ending December 31, 2018, include the repayment of the 2017 Senior Notes and the Credit Facility. The $50 million of repayments due on the Credit Facility in 2014 are reported in the balance sheet caption "Current Liabilities: Current Maturities of Long-term Debt." Excluding any potential timing effects related to Excess Cash Flow prepayments on the Credit Facility, principal repayments required on the Senior Notes and credit facility are as follows:

The Company is authorized to issue 1,000,000 shares of common stock with a par value of $0.01 per share. Holders of common stock are entitled to one vote per share on all matters to be voted upon by stockholders of the Company. On February 15, 2008, the Company sold 10,000 shares of its common stock and raised $1.0 billion of proceeds.

In May 2012, Myria completed a deleveraging plan whereby $600 million of additional equity capital was contributed by participating shareholders. The plan made provision for shareholders who were willing, but unable, to make the necessary capital contribution. In such case, these non-participating shareholders did not contribute cash to Myria but instead exchanged a portion of their Myria Holdings Senior Notes ("Senior Notes) and common stock thereby diluting their ownership interest. Two owners contributed a total of $5.4 million in Senior Notes principal and 42.67 shares of common stock under these provisions.

The Company, through its subsidiaries, enters into derivative contracts for the purpose of hedging exposures that accompany its normal business activities. Natural's normal business activities expose it to risks associated with changes in the market price of natural gas and associated transportation costs. Specifically, these risks are associated with (i) pre-existing or anticipated physical natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. Price changes in natural gas are often caused by shifts in the supply and demand for this commodity, as well as its locations.

As of December 31, 2013, Natural entered into the following outstanding commodity forward contracts to hedge its forecasted energy commodity sales:

Additionally, Myria Acquisition entered into an interest rate swap with a $600 million notional balance for the purpose of converting the floating rate on its $600 million Credit Agreement to a fixed rate. By employing this strategy, Myria Acquisition minimized its exposure to volatility in market interest rates. This swap was designated and initially qualified as a cash flow hedge.

However, beginning in December 2010 Myria Acquisition began making principal repayments on its Credit Agreement. The resulting difference between the principal balance of the Credit Agreement and the $600 million notional balance of the swap caused $0.2 million gain of ineffectiveness to be recognized in current earnings as a reduction to interest expense for the year ended December 31, 2012 and $5.7 million and $12.3 million of ineffectiveness to be recognized in current earnings as interest expense for the six and twelve months ended December 31, 2011 and June 30, 2011, respectively. In April 2012, hedge accounting was discontinued when it became probable that the interest rate swap would be settled early in connection with the Company's refinancing plans. As a result, changes in the fair value of the swap from April onwards totaling $9.3 million were recorded directly into earnings as interest expense. In May 2012, Myria Acquisition cash settled the swap concurrent with the repayment of the Credit Agreement thereby extinguishing both. At settlement, Myria Acquisition recognized a $65.3 million loss on the swap settlement which was recorded directly into earnings as interest expense.

The following tables summarize the pre-tax impact of Natural and Myria Acquisition's derivative contracts on the Consolidated Statements of Operations:

The following table summarized the fair values of Naturals derivative contracts and classifications in the Consolidation Balance Sheets as of December 31, 2013 and 2012:

Natural expects to reclassify $0.2 million from accumulated other comprehensive income (loss) into earnings during the next twelve months when the associated forecasted sales and purchases are also expected to occur. As of December 31, 2013, the maximum length of time over which Natural has hedged its exposure to commodity price risk is through December 2014.

Natural gas and Myria Acquisition had counterparty credit risk as a result of these financial derivative contracts. Counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of counterparties may affect the Company's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. The Company maintains credit policies to minimize this credit risk. These policies include (i) an evaluation of potential counterparties' financial condition (including credit ratings), (ii) collateral requirements under certain circumstances and (iii) the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty. Based on these policies, exposure, credit and other reserves, the Company does not anticipate a material adverse effect on our financial position, results of operations or cash flows as a result of potential counterparty non-performance.

Over-the-counter swaps and options are entered into with counterparties outside central trading organizations such as a futures, options or stock exchanges. These contracts are with a number of parties, all of which have investment grade credit ratings. While derivative transactions are entered into principally with investment grade counterparties and their credit ratings are actively monitored, it is nevertheless possible that from time to time losses will result from counterparty credit risk.

In conjunction with Natural's purchase of exchange- traded derivative contracts or when the market value of derivative contracts with specific counterparties exceeds established limits, Natural is required to provide collateral to its counterparties, which may include posting letters of credit or placing cash in margin accounts. Natural had no outstanding letters of credit at December 31, 2013 and 2012 in support of its hedging of commodity price risks associated with the sale of natural gas. Natural also has agreements with certain counterparties to its derivative contracts that contain provisions

requiring the Company to post additional collateral upon a decrease in its credit rating. As of December 31, 2013, we had cash margin deposits totaling $1.6 million, reported in the caption "Restricted Deposits" on the Consolidated Balance Sheets. As of December 31, 2013, Natural had no derivative instruments with credit-risk-related contingent features in a net liability position and would not have to post additional collateral if a downgrade was triggered.

Certain of Natural's derivative contracts are subject to master netting agreements. As of December 31, 2013 and 2012, the Company presented the fair value of its derivative contracts on a gross basis on the accompanying Consolidated Balance Sheets.

The following tables present derivative contracts subject to such netting agreements as of the dates indicated (in thousands):

U.S. GAAP includes a hierarchical disclosure framework associated with the level of pricing observability utilized in measuring fair value. This framework defines three levels of inputs to the fair value measurement process, and requires that each fair value measurement be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. The three broad levels of inputs defined by the disclosure framework are as follows:

» level 1 inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date

» level 2 inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and

» level 3 inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity's own data).

Derivative contracts can be exchange-traded or over-the- counter ("OTC"). Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. PipeCo and its affiliated companies value exchange-traded derivative contracts using quoted market prices for identical securities. OTC derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. PipeCo and its affiliated companies use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy.

Certain OTC derivative contracts trade in less liquid markets with limited pricing information, and the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our financial statements.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management's best estimate is used.

The following two tables summarize the fair value measurements of derivative contracts, based on the three levels established by U.S. GAAP and does not include cash margin deposits reported in the balance sheet caption "Restricted Deposits":

The following table provides a summary of changes in the fair value of the Level 3 derivative contracts:

The following table provides a summary of changes in goodwill based on Level 3 inputs:

Expenses incurred under operating leases were $1.4 million and $1.5 million for the years ended December 31, 2013 and 2012, respectively, and $1.6 million and $2.2 million for the six and twelve months ended December 31, 2011 and June 30, 2011, respectively.

Future minimum commitments under non-cancelable operating leases as of December 31, 2013 are as follows:

Approximately $9.4 million had been committed for the purchase of property, plant and equipment at December 31, 2013.

Natural had one customer that accounted for 16.3% of total revenues for the year ended December 31, 2013. Natural had one customer that accounted for 14.3% of total revenues for the year ended December 31, 2012.

Natural's principal delivery market area encompasses the states of Illinois, Indiana and Iowa and secondary markets in portions of Wisconsin, Nebraska, Kansas, Missouri and Arkansas. Natural is the largest transporter of natural gas to the Chicago market. During the year ended December 31, 2013, Natural delivered an average of 1.99 trillion Btus per day of natural gas to this market. Natural's storage capacity is largely located near its transportation delivery markets, effectively serving the same customer base. Natural has a number of individually significant customers, including local natural gas distribution companies in the greater Chicago area and major natural gas marketers and approximately 60% of its tariff service revenues are attributable to its ten largest customers. Natural mitigates credit risk by requiring collateral or financial guarantees and letters of credit from customers with specific credit concerns. In support of credit extended to certain customers, Natural had received prepayments of $11.3 million and $2.5 million as of December 31, 2013 and 2012, respectively, included in the balance sheet caption "Current Liabilities: Other."

During the first quarter of 2014, PipeCo purchased 4.3 million dekatherms of system gas for approximately $30.5 million. This purchase was made to supplement the increased usage for its northern customers during severe weather.

Management has performed an evaluation of subsequent events through April 30, 2014, the date the company's consolidated financial statements were available to be issued and no other events occurred requiring disclosure.

Number			Description

	1.1*		Certificate of registration of Brookfield Infrastructure Partners L.P., registered as of May 29, 2007—incorporated by reference to Exhibit 1.1 to our partnership's Registration Statement on Form 20-F filed July 31, 2007. (With regard to applicable cross-references in this report, our partnership's registration statement was filed with the SEC under File No. 1-33632).
	1.2*		Second Amended and Restated Limited Partnership Agreement of Brookfield Infrastructure Partners L.P., dated March 28, 2014.
	4.1*		Third Amended and Restated Limited Partnership Agreement of Brookfield Infrastructure L.P., dated March 28, 2014.
	4.2*		Amended and Restated Master Services Agreement, dated March 28, 2014, by and among Brookfield Asset Management Inc., Brookfield Infrastructure Partners L.P., Brookfield Infrastructure L.P., and others.
	4.3*		Amended and Restated Relationship Agreement, dated March 28, 2014, by and among Brookfield Asset Management Inc., Brookfield Infrastructure Partners L.P., Brookfield Infrastructure L.P., and others.
	4.4*		Registration Rights Agreement, dated December 4, 2007, between Brookfield Infrastructure Partners L.P. and Brookfield Asset Management Inc.—incorporated by reference to Exhibit 4.4 to our partnership's Registration Statement on Form 20-F/A filed December 13, 2007.
	8.1*		Significant Subsidiaries (as defined in §210.1-02 (w) of Regulation S-X) of Brookfield Infrastructure Partners L.P. (Incorporated by reference to Item 4, "Information on the Company").
	12.1		Certification of Samuel Pollock, Chief Executive Officer, Brookfield Infrastructure Group L.P., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	12.2		Certification of Bahir Manios, Chief Financial Officer, Brookfield Infrastructure Group L.P., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	13.1		Certification of Samuel Pollock, Chief Executive Officer, Brookfield Infrastructure Group L.P., pursuant to 18 U.S.C. Section 1350, as adopted to Section 906 of the Sarbanes-Oxley Act of 2002.
	13.2		Certification of Bahir Manios, Chief Financial Officer, Brookfield Infrastructure Group L.P., pursuant to 18 U.S.C. Section 1350, as adopted to Section 906 of the Sarbanes-Oxley Act of 2002.
	15.1*		Consent of Deloitte LLP, independent registered chartered accountants, relating to the incorporation of the consolidated financial statements of Brookfield Infrastructure Partners L.P. into this Annual Report on Form 20-F.*
	15.2		Consent of PricewaterhouseCoopers LLP relating to the incorporation of the consolidated financial statements of Myria Holdings Inc. into the Annual Report on Form 20-F filed with the Securities and Exchange Commission on March 28, 2014.

The registrant hereby certifies that it meets all of the requirements for filing an annual report on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.


o		REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the fiscal year ended December 31, 2013
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
o		SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Title of class		Name of each exchange on which registered

Limited Partnership Units		New York Stock Exchange; Toronto Stock Exchange

		Page number

Independent Auditor's Report			F-3
Consolidated Statements of Operations			F-4
Consolidated Statements of Comprehensive Income (Loss)			F-5
Consolidated Balance Sheets			F-6
Consolidated Statements of Shareholders Equity			F-7 - F-8
Consolidated Statements of Cash Flows			F-9 - F-10
Notes to the Consolidated Financial Statements			F-11 - F-42

	December 31, 2013		December 31, 2012

	(in thousands)		(in thousands)
Regulatory assets
Employee benefit costs	$	477	$	711
Deferred income taxes		13,234		13,946
Rate regulation and application costs		2,593		4,433

Total regulatory assets		16,304		19,090

Regulatory liabilities
Deferred revenues		338		297

Total regulatory liabilities		338		297

Net regulatory assets	$	15,966	$	18,793

	Year Ended December 31, 2013		Year Ended December 31, 2012		Six Months ended December 31, 2011		Year Ended June 30, 2010

	(in thousands)		(in thousands)		(in thousands)		(in thousands)
					(Not covered by Auditor's Report)		(Not covered by Auditor's Report)
Sales, transportation and storage of natural gas and other revenues	$	3,386	$	6,948	$	5,126	$	10,227
Purchases and transportation of natural gas	$	1,452	$	866	$	85	$	741
Management fee expense to Myria Management LLC	$	4,615	$	4,933	$	2,520	$	5,040
Charges for general and administrative costs paid to Kinder Morgan, Inc.	$	35,700	$	35,000	$	15,411	$	43,140
Labor and other reimbursable costs paid to Kinder Morgan, Inc.	$	99,669	$	92,452	$	54,255	$	101,276


		UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 20-F/A (AMENDMENT NO. 1)


o U.S. GAAP		ý International Financial Reporting Standards as issued by the International Accounting Standards Board		o Other

		December 31, 2013			December 31, 2012

		(in thousands)			(in thousands)
Natural gas transmission and storage	1.94%	$	1,837,491		$	1,813,999
General and other	8.30%		57,821			77,371
Construction work in process	n/a		29,130			14,430

Total property, plant and equipment			1,924,443			1,905,800

Accumulated depreciation and amortization			(302,332	)		(249,730	)
Property, plant and equipment, net		$	1,622,111		$	1,656,070

					Six months Ended December 31, 2011			Year Ended June 30, 2011

					(Not covered by Auditor's Report)			(Not covered by Auditor's Report)
Federal income tax rate	35.00	%	35.00	%		35.00	%		35.00	%
Increase (decrease) as a result of
Goodwill impairment	(25.41	)%	(19.53	)%		(32.83	)%		—
State and local taxes, net of federal benefit	(0.82	)%	2.34	%		0.05	%		(2.61	)%
Permanent items	(0.26	)%	0.45	%		—			(0.12	)%
Other	—		—			(0.12	)%		(2.61	)%
Effective tax rate	10.15	%	17.36	%		2.10	%		29.66	%

	December 31, 2013			December 31, 2012

	(in thousands)			(in thousands)
Balance at beginning of period	$	8,058		$	4,540
Prior year tax positions		(16	)		—
Settlements with taxing authorities		(2,595	)		4,048
Lapse in statute of limitations		—			(531	)

Balance at end of period	$	5,447		$	8,057


Myria Senior Notes Outstanding	1,327,961
PIK Interest paid to date	515,312
Myria Senior Notes and PIK Interest contributed from shareholders	(1,843,273	)

Balance outstanding at December 31, 2013	—

Calendar year	Maturities

	(In millions)
2014	$	50
2015	$	50
2016	$	55
2017	$	1,744
2018	$	—
Thereafter	$	1,050

Total Maturities	$	2,949
Unamortized debt premium	$	20

Total Debt	$	2,969

		Net Open Position Long/(Short)

DERIVATIVES DESIGNATED AS HEDGING CONTRACTS
Natural gas fixed price		(6.3) billion cubic feet
Natural gas basis		(6.3) billion cubic feet

	Amount of gain/(loss) recognized in OCI on derivative (effective portion)

(in thousands) Derivatives in cash flow hedging relationships	Year Ended December 31, 2013		Year Ended December 21, 2012		Six Months Ended December 31, 2011			Year Ended June 30, 2011
					(Not covered by Auditor's Report)			(Not covered by Auditor's Report)
Interest rate swap	$	—	$	3,430	$	(23,009	)	$	(3,716	)

Energy commodity derivative contracts		2,797		2,929		18,967			15,596

	$	2,797	$	6,359	$	(4,042	)	$	11,880

	Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)

(in thousands) Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)	Year Ended December 31, 2013		Year Ended December 21, 2012		Six Months Ended December 31, 2011		Year Ended June 30, 2011
					(Not covered by Auditor's Report)		(Not covered by Auditor's Report)
Interest expense	$	—	$	—	$	—	$	—

Operating revenues: Natural gas sales		4,612		2,858		20,693		30,5751

	$	4,612	$	2,858	$	20,693	$	30,751

		Amount of gain/(loss) recognized in income on derivative

(in thousands) Derivatives not designated as hedge contracts	Location of gain/(loss) recognized in income on derivative	Year Ended December 31, 2013		Year Ended December 31, 2012			Six Months Ended December 31, 2011		Year Ended June 30, 2011
							(Not covered by Auditor's Report)		(Not covered by Auditor's Report)
Interest rate swap	Interest expense	$	—	$	(74,968	)	$	—	$	—
Energy commodity derivative contracts	Operating revenues: Natural gas sales	$	—	$	(62	)	$	—	$	740

		Asset derivatives				Liability derivatives

(in thousands)		December 31, 2013		December 31, 2012		December 31, 2013			December 31, 2012
						(Not covered by Auditor's Report)			(Not covered by Auditor's Report)
Derivatives designated as hedging contracts	Balance sheet location		Fair value of derivatives				Fair value of derivatives
Energy commodity derivative contracts	Other, Current	$	730	$	2,401	$	(468	)	$	(324	)
Energy commodity derivative contracts	Other, Non-current		—		—		—			—

Total derivatives		$	730	$	2,401	$	(468	)	$	(324	)

	Offsetting of Financial Assets and Derivative Assets

							Gross Amounts not Offset in the Balance Sheet
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet		Amounts of Assets Presented in the Balance Sheet		Financial Instruments			Cash Collateral Held^(a)		Net Amount
As of December 31, 2013
Energy commodity derivative contracts	$	730		—	$	730	$	(468	)		—	$	262

As of December 31, 2012
Energy commodity derivative contracts	$	2,401		—	$	2,401	$	(178	)		—	$	2,223

	Asset fair value measurements using (amounts in thousands)

	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
As of December 31, 2013
Energy commodity derivative contracts	$	730	$	299	$	431		—
As of December 31, 2012
Energy commodity derivative contracts	$	2,401		—	$	2,401		—

	Goodwill

	(in thousands)
Goodwill	$	5,164,184

Accumulated impairment charges recorded to expense		(1,686,126	)
Balance as of June 30, 2010 (Not covered by Auditor's Report)	$	4,278,059
Impairment charges recorded to expense		—
Balance as of June 30, 2011 (Not covered by Auditor's Report)	$	4,278,059
Impairment charges recorded to expense		(800,000	)
Balance as of December 31, 2011 (Not covered by Auditor's Report)	$	3,478,058
Impairment charges recorded to expense		(319,460	)
Balance as of December 31, 2012	$	3,158,598
Impairment charges recorded to expense		(560,042	)
Balance as of December 31, 2013	$	2,598,556


		BROOKFIELD INFRASTRUCTURE PARTNERS L.P. by its general partner, Brookfield Infrastructure Partners Limited
		By:		/s/ DON MACKENZIE Name: Don Mackenzie Title: Director