UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended ~~September~~December 3031, 2015

o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission file number: 001-34733

Niska Gas Storage Partners LLC

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		27-1855740 (I.R.S. Employer Identification number)

170 Radnor Chester Road, Suite 150 Radnor, PA (Address of principal executive offices)		19087 (Zip Code)

(484) 367-7432

(Registrant’s telephone number, including area code)

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 x 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 x No o

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

Large accelerated filer o		Accelerated filer x		Non-accelerated filer o		Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

As of ~~November~~February 58, ~~2015~~2016, there were 37,988,724 Common Units outstanding.

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Cautionary Statement Regarding Forward-Looking Information

This report contains information that may constitute “forward-looking statements.” Generally, the words “believe,” “expect,” “intend,” “estimate,” “anticipate,” “project,” “will” and similar expressions identify forward-looking statements, which typically are not historical in nature. All statements that address operating performance, events or developments that we expect or anticipate will occur in the future—including statements relating to general views about future operating results—are forward-looking statements. Management believes that these forward-looking statements are reasonable as and when made. However, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date when made. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. In addition, forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from our historical experience and our present expectations or projections. These risks and uncertainties include changes in general economic conditions, competitive conditions in our industry, actions taken by third-party operators, processors and transporters, changes in the availability and cost of capital, operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control, the effects of existing and future laws and governmental regulations, the effects of future litigation, and certain factors described in Part II, “Item 1A. Risk Factors” and elsewhere in this report, in our Annual Report on Form 10-K for the fiscal year ended March 31, 2015 (“Annual Report”) and in our Quarterly Report on Form 10-Q for the period ended June 30, 2015 (“Q1 Quarterly Report”), and those described from time to time in our future reports filed with the Securities and Exchange Commission (the “SEC”).

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TABLE OF CONTENTS

		Page
~~PART I. FINANCIAL INFORMATION~~	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (unaudited)	1
	Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss) for the Three and Six Months Ended September 30, 2015 and 2014	1
	Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss) for the Three and Nine Months Ended December 31, 2015 and 2014	1
	Consolidated Balance Sheets as of September 30, 2015 and March 31, 2015	2
	Consolidated Balance Sheets as of December 31, 2015 and March 31, 2015	2
	Consolidated Statements of Cash Flows for the Six Months Ended September 30, 2015 and 2014	3
	Consolidated Statements of Cash Flows for the Nine Months Ended December 31, 2015 and 2014	3
	Consolidated Statements of Changes in Members’ Equity for the Six Months Ended September 30, 2015 and 2014	4
	Consolidated Statements of Changes in Members’ Equity for the Nine Months Ended December 31, 2015 and 2014	4
	Notes to Unaudited Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3435
Item 4.	Controls and Procedures	3536
~~PART II. OTHER INFORMATION~~	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	3536
Item 1A.	Risk Factors	3536
Item 6.	Exhibits	3637

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

Niska Gas Storage Partners LLC

Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss)

(in thousands of U.S. dollars, except for per unit amounts)

(Unaudited)

	Three Months Ended						~~Six~~Nine Months Ended
	September 30,						September 30,
	December 31,						December 31,
	2015			2014			2015			2014
Revenues:
Fee-based revenue	$	1213,~~652~~227		$	15,~~633~~628		$	2640,~~914~~141		$	5874,~~387~~015
Optimization, net	45,~~684~~393			(523,~~043~~591		)	~~(333~~5,060		)	731,~~580~~171
	17,336			10,590			26,581			65,967
	18,620			39,219			45,201			105,186
Expenses (income):
Operating	87,~~626~~709			129,~~062~~434			1624,~~583~~292			2332,~~015~~451
General and administrative	65,~~730~~718			64,~~205~~233			1723,~~960~~678			1620,~~279~~513
Depreciation and amortization	1417,~~805~~392			1641,~~012~~752			2542,~~539~~931			65107,~~978~~730
Interest	1213,~~965~~265			1213,~~735~~182			2538,~~706~~971			2538,~~047~~229
Loss on disposal of assets	240			20			240			6
Impairment of goodwill	—			245,604			—			245,604
Foreign exchange losses (gains)	79			(262		)	135			(312		)
Losses (gains) on disposals of assets	28			(70		)	268			(64		)
Other income	(6		)	(2		)	(11		)	(3		)
Foreign exchange losses	197			344			332			32
EARNINGS (LOSS) BEFORE INCOME TAXES	(26,103		)	(36,180		)	(59,571		)	(64,043		)
Other expense (income)	7			(2		)	(4		)	(8		)
Income tax benefit	(6,494		)	(7,348		)	(2,555		)	(16,240		)
EARNINGS (LOSS) BEFORE INCOME TAXES	(25,696		)	(275,258		)	(85,267		)	(339,301		)
NET EARNINGS (LOSS) AND COMPREHENSIVE INCOME (LOSS)	$	(19,609	)	$	(28,832	)	$	(57,016	)	$	(47,803	)
Income tax benefit	(4,704		)	(15,635		)	(7,259		)	(31,875		)
NET EARNINGS (LOSS) AND COMPREHENSIVE INCOME (LOSS)	$	(20,992	)	$	(259,623	)	$	(78,008	)	$	(307,426	)
Net earnings (loss) allocated to:
Managing Member	$	(~~353~~378	)	$	(~~538~~4,677	)	$	(1,~~027~~405	)	$	(~~896~~5,573	)
Common unitholders	$	(1920,~~256~~614	)	$	(28254,~~294~~946	)	$	(5576,~~989~~603	)	$	(46301,~~907~~853	)
Earnings (loss) per unit allocated to common unitholders - basic and diluted	$	(0.5154	)	$	(06.7885	)	$	(12.4702	)	$	(18.3027	)

(See Notes to Unaudited Consolidated Financial Statements)

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Niska Gas Storage Partners LLC

Consolidated Balance Sheets

(in thousands of U.S. dollars)

(Unaudited)

	September 30,			March 31,
	December 31,			March 31,
	2015			2015
ASSETS
Current assets
Cash and cash equivalents	$	186,~~829~~049		$	11,699
Margin deposits	189,~~674~~727			13,285
Trade receivables	12,~~376~~209			2,598
Accrued receivables	2129,~~838~~965			44,140
Natural gas inventory	~~111~~81,~~117~~014			136,295
Prepaid expenses and other current assets	3,~~078~~035			3,788
Short-term risk management assets	3134,~~639~~960			41,600
	206,551			253,405
	166,959			253,405
Long-term assets
Property, plant and equipment, net of accumulated depreciation	~~798~~784,~~820~~048			820,467
Intangible assets, net of accumulated amortization	3837,~~726~~266			41,829
Deferred financing costs, net of accumulated amortization	98,~~516~~508			11,001
Other assets	32,~~087~~989			3,329
Long-term risk management assets	2826,~~691~~065			30,928
	878,840			907,554
	858,876			907,554
TOTAL	$	1,~~085~~025,~~391~~835		$	1,160,959
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities
Obligations under credit facilities	$	~~173~~161,~~500~~251		$	193,500
Current portion of obligations under capital lease	1,~~360~~371			1,339
Trade payables	~~652~~130			885
Current portion of deferred taxes	2,334			2,334
Deferred revenue	~~6,715~~238			6,669
Accrued liabilities	5742,~~810~~148			47,686
Short-term risk management liabilities	2527,~~825~~962			25,560
	268,196			277,973
	235,434			277,973
Long-term liabilities
Long-term risk management liabilities	1918,~~082~~333			20,833
Asset retirement obligations	2,412			2,308
Other long-term liabilities	1,~~165~~169			1,270
Deferred income taxes	8479,~~620~~350			88,317
Obligations under capital lease	8,~~902~~555			9,587
Long-term debt	575,000			575,000
	691,181			697,315
	684,819			697,315
Members’ equity (deficit)
Common units	(~~140~~160,~~388~~453		)	(81,805		)
Managing Member’s interest	266,~~402~~035			267,476
	126,014			185,671
	105,582			185,671
Commitments and contingencies (Note 2)
TOTAL	$	1,~~085~~025,~~391~~835		$	1,160,959

(See Notes to Unaudited Consolidated Financial Statements)

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Niska Gas Storage Partners LLC

Consolidated Statements of Cash Flows

(in thousands of U.S. dollars)

(Unaudited)

	Six Months Ended
	Nine Months Ended
	September 30,
	December 31,
	2015			2014
Operating Activities
Net earnings (loss)	$	(5778,~~016~~008	)	$	(47307,~~803~~426	)
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Unrealized foreign exchange losses (gains)	171			(66		)
Unrealized foreign exchange losses	329			260
Deferred income tax benefit	(39,~~738~~009		)	(1631,~~249~~938		)
Unrealized risk management losses	10,712			151
Unrealized risk management losses (gains)	11,405			(48,127		)
Depreciation and amortization	2542,~~539~~931			65107,~~978~~730
Amortization of deferred financing costs	12,~~872~~881			12,~~825~~738
Loss (gain) on disposal of assets	240			(14		)
Losses (gains) on disposals of assets	268			(64		)
Non-cash compensation	~~713~~1,273			1,~~243~~687
Write-down of inventory	—			10,500
Impairment of goodwill	—			245,604
Changes in non-cash working capital	54,054			(122,901		)
Write-downs of inventory	600			42,200
Net cash provided by (used in) operating activities	32,547			(107,336		)
Changes in non-cash working capital	61,667			(105,338		)
Net cash provided by (used in) operating activities	34,337			(92,674		)
Investing Activities
Property, plant and equipment expenditures	(~~881~~2,288		)	(15,~~698~~466		)
Proceeds from disposal of assets	—			14
Net cash used in investing activities	(~~881~~2,288		)	(15,~~684~~452		)
Financing Activities
Proceeds from credit facility drawings	~~132~~166,~~100~~300			~~498~~652,~~500~~700
Repayments of credit facilities	(~~152~~199,100		)	(~~374~~531,~~500~~700		)
Payments of financing costs	(388		)	(~~857~~880		)
Repayments of obligations under capital lease	(~~665~~1,001		)	(~~644~~970		)
Distributions to unitholders	(3,354		)	(1320,~~737~~105		)
Net cash (used in) provided by financing activities	(2437,~~407~~543		)	~~108~~99,~~762~~045
Effect of translation on foreign currency cash and cash equivalents	(~~129~~156		)	(~~112~~243		)
Net increase (decrease) in cash and cash equivalents	7,130			(370		)
Net (decrease) increase in cash and cash equivalents	(5,650		)	676
Cash and cash equivalents, beginning of period	11,699			7,704
Cash and cash equivalents, end of period	$	186,~~829~~049		$	78,~~334~~380
Supplemental cash flow disclosures (Note 12)

Supplemental cash flow disclosures (Note 11)

(See Notes to Unaudited Consolidated Financial Statements)

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Niska Gas Storage Partners LLC

Consolidated Statements of Changes in Members’ Equity

(in thousands of U.S. dollars)

(Unaudited)

				Managing
	Common			Member
	Units			Interest			Total
Balance, April 1, 2014	$	279,604		$	274,536		$	554,140
Net earnings (loss)	(46301,~~907~~853		)	(~~896~~5,573		)	(47307,~~803~~426		)
Distributions to unitholders	(2638,~~159~~986		)	(~~507~~751		)	(2639,~~666~~737		)
Issuance of common units	1219,~~928~~608			—			1219,~~928~~608
Non-cash equity contribution from parent	480			10			490
Non-cash compensation	~~739~~1,175			1422			~~753~~1,197
Balance, September 30, 2014	$	220,685		$	273,157		$	493,842
Balance, December 31, 2014	$	(39,972	)	$	268,244		$	228,272
Balance, April 1, 2015	$	(81,805	)	$	267,476		$	185,671
Net earnings (loss)	(5576,~~989~~603		)	(1,~~027~~405		)	(5778,~~016~~008		)
Distributions to unitholders	(3,294		)	(60		)	(3,354		)
Non-cash compensation	~~700~~1,249			1324			~~713~~1,273
Balance, September 30, 2015	$	(140,388	)	$	266,402		$	126,014
Balance, December 31, 2015	$	(160,453	)	$	266,035		$	105,582

(See Notes to Unaudited Consolidated Financial Statements)

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

1. Organization and Basis of Presentation

Organization

Niska Gas Storage Partners LLC (“Niska Partners” or the “Company”) is a publicly traded Delaware limited liability company (NYSE:NKA) which independently owns and operates natural gas storage assets in North America. The Company operates the AECO Hub™, which consists of the Countess and Suffield gas storage facilities in Alberta, Canada and the Wild Goose and Salt Plains gas storage facilities in California and Oklahoma, respectively. Each of these facilities markets natural gas storage services in addition to optimizing storage capacity with proprietary gas purchases.

In June 2015, the Company and Niska Gas Storage Management LLC, its Managing Member, entered into a definitive agreement to be acquired by Brookfield Infrastructure Partners L.P. and its institutional partners (“Brookfield”). Under the terms of the agreement (“Merger Agreement”), Brookfield will acquire all of the Company’s outstanding common units for $4.225 per common unit in cash and will acquire the Managing Member and the Incentive Distribution Rights (“IDRs”) in the Company (the “Transaction”). ~~The~~prior ~~closing of the Transaction is expected~~ to ~~occur in calendar year 2016 and is subject to customary closing conditions and regulatory approvals~~June 14, ~~including approval by the California Public Utilities Commission (“CPUC”)~~2017. A period provided for in the Merger Agreement for unsolicited consideration of alternative acquisition proposals expired on July 29, 2015.

The Merger Agreement, which includes a commitment by the Company not to make cash distributions until the earlier of the date of closing or termination of the Transaction, was approved by the Company’s Board of Directors (“the Company Board”) and the Conflicts Committee of its Board of Directors (the “Conflicts Committee”). Affiliates of Carlyle/Riverstone Global Energy and Power Fund II, L.P. and Carlyle/Riverstone Global Energy and Power Fund III, L.P. (collectively, the “Carlyle/Riverstone Funds”) delivered a written consent approving the Transaction. No additional unitholder action is required to approve the Transaction.

In connection with the entry into the Merger Agreement, Brookfield agreed to lend up to $50.0 million to the Company under a short-term credit facility to be used for working capital purposes (see Note 3).

AtThe ~~September 30,~~closing ~~2015,~~of ~~Niska~~the ~~Partners~~Transaction ~~had~~is ~~37,988,724~~dependent ~~common~~on ~~units~~certain ~~outstanding.~~conditions Ofrelated ~~this~~to ~~amount,~~regulatory ~~20,488,525~~requirements ~~common~~being ~~units~~satisfied, ~~are~~including ~~owned by~~ the ~~Carlyle/Riverstone~~approval ~~Funds~~of ~~through~~the ~~Niska~~California ~~Holdings,~~Public ~~L.P.~~Utilities ~~and~~Commission ~~Niska~~(“CPUC” ~~Sponsor~~or ~~Holdings~~the ~~Cȯȯpertief (~~“~~Sponsor Holdings~~Commission”)~~, U~~.~~A.,~~ ~~along~~The ~~with~~Company’s apreviously ~~1.80%~~disclosed ~~Managing~~timeline ~~Member’s~~allowed ~~interest~~for ina ~~the~~hearing ~~Company~~process ~~and~~to ~~all~~be ofundertaken with the ~~Company’s IDRs~~CPUC. ~~Including~~The ~~all~~CPUC ofhas ~~the~~determined ~~common~~that ~~units~~a ~~owned~~hearing byis ~~the~~not ~~Carlyle/Riverstone Funds~~required, ~~along~~which ~~with~~could reduce the ~~1.80%~~time ~~Managing~~to ~~Member’s~~close. ~~interest~~Consequently, the ~~Carlyle/Riverstone~~Transaction ~~Funds~~is ~~have~~expected ato ~~54.76%~~be ~~ownership~~consummated ~~interest~~ in ~~the~~calendar ~~Company~~year ~~excluding~~2016; ~~the IDRs~~however, ~~which~~the ~~are~~timing aof ~~variable~~the ~~interest.~~process ~~The~~remains ~~remaining~~within ~~17,500,199~~the ~~common~~purview ~~units,~~of ~~representing~~the aCPUC ~~45.24%~~and ~~ownership~~the ~~interest~~Transaction ~~excluding~~remains ~~the~~subject ~~IDRs,~~to ~~are~~other ~~owned~~non-regulatory byclosing ~~the public~~conditions.

At December 31, 2015, Niska Partners had 37,988,724 common units outstanding. Of this amount, 20,488,525 common units are owned by the Carlyle/Riverstone Funds through Niska Holdings L.P. and Niska Sponsor Holdings Cȯȯpertief U.A. (“Sponsor Holdings”), along with a 1.80% Managing Member’s interest in the Company and all of the Company’s IDRs. Including all of the common units owned by the Carlyle/Riverstone Funds, along with the 1.80% Managing Member’s interest, the Carlyle/Riverstone Funds have a 54.76% ownership interest in the Company excluding the IDRs, which are a variable interest. The remaining 17,500,199 common units, representing a 45.24% ownership interest in the Company excluding the IDRs, are owned by the public.

Basis of Presentation

The accounting policies applied in these unaudited interim financial statements are consistent with the policies applied in the consolidated financial statements of Niska Partners and notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, 2015.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

1. Organization and Basis of Presentation (continued)

Basis of Presentation (continued)

In the opinion of management, the accompanying consolidated financial statements of Niska Partners, which are unaudited except for the balance sheet at March 31, 2015 which is derived from audited financial statements, include all adjustments necessary to present fairly Niska Partners’ financial position as of ~~September~~December 3031, 2015, the results of Niska Partners’ operations for the three and ~~six~~nine months ended ~~September~~December 3031, 2015 and 2014, along with its cash flows for the ~~six~~nine months ended ~~September~~December 3031, 2015 and 2014. The results of operations for the three and ~~six~~nine months ended ~~September~~December 3031, 2015 are not necessarily representative of the results to be expected for the full fiscal year ending March 31, 2016. The optimization of proprietary gas purchases is seasonal with the majority of the revenues and costs associated with the physical sale of proprietary gas generally occurring during the third and fourth fiscal quarters, when demand for natural gas is typically the strongest.

Pursuant to the rules and regulations of the SEC, the unaudited consolidated financial statements do not include all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). These consolidated financial statements should be read in conjunction with the consolidated financial statements of Niska Partners and notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, 2015.

2. Commitments and Contingencies

Commitments

Niska Partners has entered into non-cancelable operating leases for temporary pressure-support gas, office space, land-use rights at its operating facilities, storage capacity at other facilities, equipment and vehicles used in its operations. The remaining lease terms expire between ~~November~~January ~~2015~~2016 and February ~~2058~~2059 and require the payment of taxes, insurance and maintenance by the lessee.

The Company’s purchase obligations arising as a result of forward purchase contracts in place at ~~September~~December 3031, 2015 were as follows:

For the fiscal year ending:
2016	$	1619,~~062,712~~293
2017	~~365~~454,~~376~~231
2018	~~331~~339,~~561~~505
2019	1323,~~812~~424
2020	56,~~547~~797
2021 and thereafter	~~901~~1,320
Total future purchase commitments	$	1,~~779~~444,~~909~~570

Purchase obligations consisted of forward physical and financial commitments related to future purchases of natural gas. As the Company economically hedges substantially all of its natural gas purchases, there are forward sales that offset these commitments which are not included in the above table. As at ~~September~~December 3031, 2015, forward physical and financial sales for all future periods totaled $1,~~772~~437.83 million.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

2. Commitments and Contingencies (continued)

Contingencies

In June 2015, the Company engaged the services of certain consultants for consideration of $5.8 million, the payment of which is contingent upon the successful closing of the Transaction.

As of ~~September~~December 3031, 2015, the Company was under review by Canadian tax authorities for withholding taxes paid on behalf of the Carlyle/Riverstone Funds and the investors of the Carlyle/Riverstone Funds for earnings distributions made prior to the Company’s initial public offering. The Company received a notice from the Canadian tax authorities of a proposed assessment equivalent to $109.07 million and estimates the probable amount payable to range from $5.75 million to the proposed assessment of $109.07 million. The Company has recorded the minimum of the range, or $5.75 million, as a liability to the Canadian tax authorities. Niska Holdings L.P., a company held by the Carlyle/Riverstone Funds and the parent of Sponsor Holdings, guaranteed the repayment of any amounts owing with respect to this matter to the Company. Accordingly, as the Company believes collection of any amounts receivable is reasonably assured, it recorded a corresponding receivable equivalent to $5.75 million.

~~Subsequent~~The ~~to the announcement of the proposed acquisition of the~~ Company ~~by Brookfield Infrastructure Partners L.P.~~ and its ~~institutional~~subsidiaries ~~partners~~are ~~(the~~also ~~“Brookfield~~subject ~~Merger”)~~to onother ~~June 14,~~legal ~~2015,~~and ~~alleged~~tax ~~unitholders~~proceedings ofand ~~Niska~~actions ~~Gas~~arising ~~Storage~~in ~~Partners LLC (~~the ~~“Plaintiffs”)~~normal ~~filed~~course ~~four~~of ~~class action lawsuits against Niska Gas Storage Partners LLC, Niska Gas Storage Management LLC (“Management Co”), Niska Sponsor Holdings Coöperatief U~~business.A. ~~(“Swan~~While ~~Sponsor”)~~the ~~(collectively~~outcome ~~“Niska”),~~of ~~Brookfield~~these ~~Infrastructure~~proceedings ~~Partners L.P. (“Brookfield”), Swan Holdings LP (“Parent”), Swan Merger Sub LLC (“Merger Sub”),~~ and ~~the~~actions ~~members~~cannot ofbe ~~Niska’s~~predicted ~~board of directors (collectively~~ with ~~Niska~~certainty, ~~the~~it ~~“Defendants”)~~is in the ~~Court~~opinion of ~~Chancery~~management ofthat the ~~State~~resolution of ~~Delaware.~~such ~~These~~proceedings lawsuits are styled (a) Eddie Barringer vs. Niska Gas Storage Partners LLC, et al. (Case No. 11210); (b) David Raul vs. Niska Gas Storage Partners LLC, et al. (Case No. 11220); (c) Nathan Peterson vs. Niska Gas Storage Partners LLC, et al., (Case No. 11234); and ~~(d) Fred~~actions ~~Pappey~~will ~~vs.~~not ~~William~~have H.a ~~Shea, Jr.~~material etimpact ~~al.,~~on ~~(Case No. 11238) (collectively,~~ the ~~“Litigation”).~~Company’s ~~The above styled lawsuits have been~~ consolidated ~~for~~financial ~~all~~position ~~purposes~~or anresults ~~captioned~~of ~~In re Niska Gas Storage Partners LLC Public Unitholders Litigation, CONSOL~~operations. ~~C.A. No. 11210-CB (the “Action”).~~

The Plaintiffs allege causes of action challenging aspects of the Brookfield Merger, including that Niska’s board of directors breached their alleged fiduciary duties to Niska’s unitholders and that Niska and Brookfield aided and abetted the board of director’s breaches of alleged fiduciary duties. In general, the Plaintiffs allege the Brookfield Merger (a) provides inadequate consideration to Niska unitholders; (b) contains contractual terms (e.g. the no-solicitation, information rights, matching rights, and termination fee provisions) that dissuade other potential merger partners from making competing proposals; and (c) is not subject to a “majority of the minority” voting requirement.

Based on these allegations, the Plaintiffs request relief enjoining Niska from proceeding with or consummating the Brookfield Merger. To the extent that the Brookfield Merger is consummated before injunctive relief is granted, the Plaintiffs seek to have the Brookfield Merger rescinded. Plaintiffs also seek damages and experts’ and attorneys’ fees.

The Defendants’ date to answer, move to dismiss, or otherwise respond to the Litigation has not yet been set as Plaintiffs’ counsel has advised that Plaintiffs will be moving to consolidate the Litigation into one action and file a consolidated amended complaint. At that point, the parties will negotiate a schedule for Defendants to answer, move to dismiss, or otherwise respond. The Defendants believe the Litigation is without merit and intend to vigorously defend against it.

The Company and its subsidiaries are also subject to other legal and tax proceedings and actions arising in the normal course of business. While the outcome of these proceedings and actions cannot be predicted with certainty, it is the opinion of Management that the resolution of such proceedings and actions will not have a material impact on the Company’s consolidated financial position or results of operations.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

3. Debt

Niska Partners’ debt obligations consist of the following:

	September 30,			March 31,
	December 31,			March 31,
	2015			2015
Senior Notes due 2019	$	575,000		$	575,000
Revolving credit facilities	~~153~~140,~~500~~700			193,500
Short-term credit facility	20,~~000~~551			—
Total	~~748~~736,~~500~~251			768,500
Less portion classified as current	(~~173~~161,~~500~~251		)	(193,500		)
	$	575,000		$	575,000

Senior Notes due 2019

The Company has senior unsecured notes due 2019 (the “6.50% Senior Notes” or “Notes”) which were issued through its subsidiaries Niska Gas Storage Finance Corp. and Niska Gas Storage Canada ULC (together, the “Issuers”). The 6.50% Senior Notes are senior unsecured obligations which are: (1) effectively junior to Niska Partners’ secured obligations to the extent of the value of the collateral securing such debt; (2) equal in right of payment with all existing and future senior unsecured indebtedness of the Company; and (3) senior in right of payment to any future subordinated indebtedness of Niska Partners. The 6.50% Senior Notes are fully and unconditionally guaranteed by Niska Partners and certain of its direct and indirect subsidiaries on a senior unsecured basis, and are: (1) effectively junior to each guarantor’s secured obligations; (2) equal in right of payment with all existing and future senior unsecured indebtedness of each guarantor; and (3) senior in right of payment to any future subordinated indebtedness of each guarantor.

Interest on the 6.50% Senior Notes is payable semi-annually on October 1 and April 1, and the Notes will mature on April 1, 2019. As of September 30, 2015, the estimated fair market value of the Notes was $523.3 million.7

Prior to October 1, 2016, the Company has the option to redeem up to 35% of the aggregate principal amount of the 6.50%. Senior Notes using net cash proceeds from certain equity offerings at a price of 106.5% plus accrued and unpaid interest. The Company may also redeem all or a part of the 6.50% Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.25% during the twelve-month period beginning on October 1, 2016, 101.625% during the twelve-month period beginning on October 1, 2017 and at par beginning on October 1, 2018, plus accrued and unpaid interest. The Company is not required to make mandatory redemptions or sinking fund payments with respect to the 6.50% Senior Notes.

The indenture governing the 6.50% Senior Notes limits Niska Partners’ ability to pay distributions in respect of, repurchase or pay dividends on its membership interests (or other capital stock) or make other restricted payments. However, it does not prohibit certain types or amounts of restricted payments, including a general basket of $75.0 million of restricted payments.

The indenture governing the Notes contains certain other covenants that, among other things, limit Niska Partners and certain of its subsidiaries’ ability to:

· incur additional debt or issue certain capital stock;

· pay dividends on, repurchase or make distributions in respect of its capital stock or repurchase or retire subordinated indebtedness;

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

3. Debt (continued)

Senior Notes due 2019 (continued)

Interest on the 6.50% Senior Notes is payable semi-annually on October 1 and April 1, and the Notes will mature on April 1, 2019. As of December 31, 2015, the estimated fair market value of the Notes was $506.0 million.

Prior to October 1, 2016, the Company has the option to redeem up to 35% of the aggregate principal amount of the 6.50% Senior Notes using net cash proceeds from certain equity offerings at a price of 106.5% plus accrued and unpaid interest. The Company may also redeem all or a part of the 6.50% Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.25% during the twelve-month period beginning on October 1, 2016, 101.625% during the twelve-month period beginning on October 1, 2017 and at par beginning on October 1, 2018, plus accrued and unpaid interest. The Company is not required to make mandatory redemptions or sinking fund payments with respect to the 6.50% Senior Notes.

The indenture governing the Notes contains certain other covenants that, among other things, limit Niska Partners and certain of its subsidiaries’ ability to:

· incur additional debt or issue certain capital stock;

· pay dividends on, repurchase or make distributions in respect of its capital stock or repurchase or retire subordinated indebtedness;

· make certain investments;

· sell assets;

· create liens;

· consolidate, merge, sell or otherwise dispose of all or substantially all of its assets;

· enter into certain transactions with its affiliates; and

· permit restrictions on the ability of its subsidiaries to make distributions.

The occurrence of events involving the Company or certain of its subsidiaries may constitute an event of default under the indenture. Such events include failure to pay interest, principal, or the premium on the notes when due; failure to comply with the merger, asset sale or change of control covenants; certain defaults on other indebtedness; and certain insolvency proceedings. In the case of an event of default, the holders of the notes are entitled to remedies, including the acceleration of payment of the notes by request of the holders of at least 25% in aggregate principal amount of the notes, and any action by the trustee to collect payment of principal, interest or premium in arrears.

Upon the occurrence of a change of control together with a decrease in the ratings of the 6.50% Senior Notes by either Moody’s or S&P by one or more gradations within 90 days of the change of control event, Niska Partners must offer to repurchase the Notes at 101% of the principal amount of the notes to be repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.

The Company’s ability to repurchase the 6.50% Senior Notes upon a change of control will be limited by the terms of its debt agreements, including its asset-based revolving credit facilities. In addition, the Company cannot assure that it will have the financial resources to repurchase the Notes upon a change of control.

~~Revolving Credit Facilities~~8

Niska Partners, through its subsidiaries, Niska Gas Storage US, LLC and AECO Gas Storage Partnership, has senior secured asset-based revolving credit facilities, consisting of a U.S. revolving credit facility and a Canadian revolving credit facility, both of which are governed by a credit agreement (the “Credit Agreement” or the “$400 million Credit Agreement”). Each revolving credit facility matures on June 29, 2016.

As of September 30, 2015, $153.5 million in borrowings, with a weighted average interest rate of 3.95% (March 31, 2015 - $193.5 million of borrowings had a weighted average interest rate of 3.98%), were outstanding under the credit facilities. Amounts committed in support of letters of credit totaled $33.7 million at September 30, 2015 (March 31, 2015 - $5.8 million). Any borrowings under the $400 million Credit Agreement are classified as current.

The Credit Agreement provides that Niska Partners may borrow only up to the lesser of the level of the then current borrowing base or the committed maximum borrowing capacity, which is currently $400.0 million. As of September 30, 2015, the borrowing base collateral totaled $261.9 million.

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

3. Debt (continued)

Revolving Credit Facilities ~~(continued)~~

As of December 31, 2015, $140.7 million in borrowings, with a weighted average interest rate of 4.19% (March 31, 2015 - $193.5 million of borrowings had a weighted average interest rate of 3.98%), were outstanding under the credit facilities. Amounts committed in support of letters of credit totaled $19.5 million at December 31, 2015 (March 31, 2015 - $5.8 million). Any borrowings under the $400 million Credit Agreement are classified as current.

The Credit Agreement provides that Niska Partners may borrow only up to the lesser of the level of the then current borrowing base or the committed maximum borrowing capacity, which is currently $400.0 million. As of December 31, 2015, the borrowing base collateral totaled $240.9 million.

The Credit Agreement also includes a covenant that requires the maintenance of a fixed charge coverage ratio (“FCCR”) of 1.1 to 1.0 at the end of each fiscal quarter when excess availability under both revolving credit facilities is less than 15% of the aggregate amount of availability under both revolving credit facilities. When the Company’s FCCR is below 1.1 to 1.0, the Company will be unable to borrow the last 15% of availability under the revolving credit facilities without triggering an event of default. The Credit Agreement provides that, upon the occurrence of certain events of default, including a covenant default, the Company’s obligations thereunder may be accelerated and the lending commitments terminated.

As of ~~September~~December 3031, 2015, Niska Partners was in compliance with all covenant requirements under the indenture governing the 6.50% Senior Notes and the $400 million Credit Agreement. However, Niska Partners’ FCCR was 0.6 to 1.0. Therefore, the Company is subject to the above restriction limiting the last 15% of availability under the revolving credit facilities. Accordingly, the availability under the ~~borrowing~~Credit ~~base~~Agreement ~~at September 30, 2015~~ has been reduced by 15%, to $~~222~~204.6 8 million. As of ~~September~~December 3031, 2015, ~~Niska~~$44.6 ~~Partners’~~million ~~availability~~of ~~under~~ the ~~Credit~~Company’s ~~Agreement~~availability ~~was~~remained ~~$32~~unutilized.~~4 million.~~

The $400 million Credit Agreement contains limitations on Niska Partners’ ability to incur additional debt or to pay distributions in respect of, repurchase or pay distributions on its membership interests (or other capital stock) or make other restricted payments.

~~Niska~~The ~~Partners~~Company ~~has~~is nopresently ~~independent~~in ~~assets~~the orprocess ~~operations~~of ~~other~~negotiating ~~than~~an ~~its~~amendment ~~investments~~and inextension of its ~~subsidiaries.~~existing ~~Both~~Credit Agreement which if completed will, among other things, permit the ~~6.50%~~Merger ~~Senior~~Agreement ~~Notes~~to proceed without triggering a change-of-control provision in the Credit Agreement and extend the ~~$400 million~~term of the Credit Agreement ~~have~~beyond ~~been~~June 29, ~~jointly~~2016 ~~and~~to ~~severally~~September 30, ~~guaranteed~~2016, byor ~~Niska~~to ~~Partners~~December 31, 2016, if the Transaction closes on or before September 16, 2016. It is likely that any such amendment and ~~substantially~~extension ~~all~~will result in a reduction in the maximum availability under the Credit Agreement. However, in the event that an extension of the agreement is not consummated, the Company will be required to raise additional funds in order to repay the Credit Agreement at its ~~subsidiaries~~maturity in June 2016. ~~Niska~~If ~~Partners’~~the ~~subsidiaries~~extension ~~have~~of nothe ~~significant~~agreement ~~restrictions~~is onconsummated ~~their~~as ~~ability~~contemplated, the Company will be required to ~~pay~~further ~~distributions~~extend the maturity date or ~~make~~raise ~~loans~~additional funds to ~~Niska~~repay ~~Partners~~the ~~and~~Credit ~~have~~Agreement at its final maturity date. We can provide no ~~restricted~~assurance ~~assets~~that aswe ofwill ~~September 30,~~be ~~2015~~able to further extend the maturity date or raise additional funds to repay the Credit Agreement upon its revised maturity.

~~Short-term~~Niska Partners has no independent assets or operations other than its investments in its subsidiaries. Both the 6.50% Senior Notes and the $400 million Credit ~~Facility~~Agreement have been jointly and severally guaranteed by Niska Partners and substantially all of its subsidiaries. Niska Partners’ subsidiaries have no significant restrictions on their ability to pay distributions or make loans to Niska Partners and have no restricted assets as of December 31, 2015.

On July 28, 2015, the Company entered into a credit agreement with Brookfield for a $50.0 million short term credit facility (the “Short-term Credit Facility”), which may be borrowed subject to certain customary conditions. As of September 30, 2015, the outstanding amount of $20.0 million under the Short-term Credit Facility bears interest at an annual rate of 10%, which is payable in cash on a quarterly basis, unless the Company elects to pay such interest in-kind by capitalizing accrued interest into the principal amount.9

Amounts borrowed under the Short-term Credit Facility may be prepaid without premium and penalty, and all amounts due and owing under the Short-term Credit Facility will be payable on the earlier of January 28, 2017 or the first to occur of (a) the acceleration of the loans during the continuance of an event of default under the Short-term Credit Facility, (b) the date on which the Merger Agreement is terminated in accordance with its terms, (c) the date that is 90 days after the date on which the required lenders have determined that the acquisition of the business of the Company and its subsidiaries pursuant to the Merger Agreement cannot or will not be consummated for any reason, including without limitation regulatory matters or legal bars, and (d) any uncured breach of any other agreement between the Company and certain affiliates, on the one hand, and any lenders or any affiliate thereof, on the other hand, which results in termination of such agreement.

The Company’s obligations under the Short-term Credit Facility are guaranteed by its parent, Sponsor Holdings, and the Company’s subsidiaries which guarantee the obligations under its $400 million Credit Agreement. Such obligations are also secured by a pledge by Sponsor Holdings over its equity interests in the Company and Niska Gas Storage Management LLC. The guarantee and pledge by Sponsor Holdings will terminate to the extent the Company obtains an amendment to the $400 million Credit Agreement which permits the Company and its subsidiaries to grant a security interest over their assets to the lenders under the Short-term Credit Facility, or such earlier date as the transactions contemplated by the Merger Agreement are consummated.

The Short-term Credit Facility requires the Company to comply with certain affirmative and negative covenants, with the Company permitted to enter into activities to the extent permitted by both the Merger Agreement and the Company’s $400 million Credit Agreement. The Company is also subject to customary events of default, substantially consistent with its $400 million Credit Agreement.

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

3. Debt (continued)

Short-term Credit Facility

On July 28, 2015, the Company entered into a credit agreement with Brookfield for a $50.0 million short term credit facility (the “Short-term Credit Facility”), which may be borrowed subject to certain customary conditions. As of December 31, 2015, the outstanding amount of $20.6 million under the Short-term Credit Facility bears interest at an annual rate of 10%, which is payable in cash on a quarterly basis, unless the Company elects to pay such interest in-kind by capitalizing accrued interest into the principal amount. During the three and nine months ended December 31, 2015, $0.6 million of interest was accrued and paid in-kind.

Amounts borrowed under the Short-term Credit Facility may be prepaid without premium and penalty, and all amounts due and owing under the Short-term Credit Facility will be payable on the earlier of January 28, 2017 or the first to occur of; (a) the acceleration of the loans during the continuance of an event of default under the Short-term Credit Facility; (b) the date on which the Merger Agreement is terminated in accordance with its terms; (c) the date that is 90 days after the date on which the required lenders have determined that the acquisition of the business of the Company and its subsidiaries pursuant to the Merger Agreement cannot or will not be consummated for any reason, including without limitation regulatory matters or legal bars; and (d) any uncured breach of any other agreement between the Company and certain affiliates, on the one hand, and any lenders or any affiliate thereof, on the other hand, which results in termination of such agreement.

4. Risk Management Activities and Financial Instruments

Risk Management Overview

Niska Partners has exposure to commodity price, the cost of compliance with environmental regulations, foreign currency, counterparty credit, interest rate and liquidity risks. Risk management activities are tailored to the risks they are designed to mitigate.

Commodity Price Risk

As a result of its natural gas inventory, Niska Partners is exposed to risks associated with changes in price when buying and selling natural gas across future time periods. To manage these risks and reduce variability of cash flows, the Company utilizes a combination of financial and physical derivative contracts, including forwards, futures, swaps and option contracts. The use of these contracts is subject to the Company’s risk management policies. These contracts have not been treated as hedges for financial reporting purposes and therefore changes in fair value are recorded directly in earnings.

Forward contracts and futures contracts are agreements to purchase or sell a specific financial instrument or quantity of natural gas at a specified price and date in the future. Niska Partners enters into forward contracts and futures contracts to mitigate the impact of changes in natural gas prices. In addition to cash settlement, exchange traded futures may also be settled by the physical delivery of natural gas.

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

4. Risk Management Activities and Financial Instruments (continued)

Commodity Price Risk (continued)

Swap contracts are agreements between two parties to exchange streams of payments over time according to specified terms. Swap contracts require receipt of payment for the notional quantity of the commodity based on the difference between a fixed price and the market price on the settlement date. Niska Partners enters into commodity swaps to mitigate the impact of changes in natural gas prices.

Option contracts are contractual agreements to convey the right, but not the obligation, for the purchaser of the option to buy or sell a specific physical or notional amount of a commodity at a fixed price, either at a fixed date or at any time within a specified period. Niska Partners enters into option agreements to mitigate the impact of changes in natural gas prices.

To limit its exposure to changes in commodity prices, Niska Partners enters into purchases and sales of natural gas inventory and concurrently matches the volumes in these transactions with offsetting derivative contracts. To comply with its internal risk management policies, Niska Partners is required to limit its exposure of unmatched volumes of proprietary current natural gas inventory to an aggregate overall limit of 8.0 billion cubic feet (“Bcf”). At ~~September~~December 3031, 2015, 4234.93 Bcf of natural gas inventory was offset with financial contracts, representing 98.08% of total inventory. At March 31, 2015, 47.2 Bcf of natural gas inventory was offset with financial contracts, representing 98.6% of total inventory. As of ~~September~~December 3031, 2015 and March 31, 2015, the volumes of inventories which were economically hedged using each type of contract were:

	September 30,	March 31,
	December 31,	March 31,
	2015	2015
Forwards	0.5.0 Bcf	1.5 Bcf
Futures	4229.43 Bcf	46.0 Bcf
Swaps	—	(0.3 Bcf)	)
	42.9 Bcf	47.2 Bcf
	34.3 Bcf	47.2 Bcf

Price Risk Associated with Compliance with Environmental Regulations

One of Niska Partners’ operating facilities, the Wild Goose storage facility, is located in California. In 2006, California adopted AB 32, the Global Warming Solutions Act of 2006, with a goal of reaching: (i) 1990 greenhouse gases (“GHG”) emissions levels by the year 2020; (ii) 80% of 1990 levels by 2050; and (iii) a mandatory emission reporting program. AB 32 required the California Air Resources Board (“ARB”) to develop a scoping plan describing the approach California will take to reduce GHGs to achieve the goal of reducing emissions to 1990 levels by 2020 (the “2020 Goal”). The scoping plan was first approved by the ARB in 2008 which identifies a cap-and-trade program as one of the strategies California will employ to meet the 2020 Goal. In 2010, ARB approved that cap and trade program and it came into effect on January 1, 2013.

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

4. Risk Management Activities and Financial Instruments (continued)

Price Risk Associated with Compliance with Environmental Regulations (continued)

~~One~~Entities ofare ~~Niska~~subject ~~Partners’~~to ~~operating~~compliance ~~facilities,~~obligations ~~the~~if ~~Wild~~they ~~Goose~~exceed ~~storage~~certain ~~facility,~~ARB-defined isemission ~~located in California~~thresholds. InDuring ~~2006,~~each ~~California~~year ~~adopted~~of ABthe 32program, the ~~Global~~ARB ~~Warming~~issues ~~Solutions~~emission ~~Act~~allowances ~~of 2006~~(i.e., ~~with~~the arights ~~goal~~to ofemit ~~reaching (i~~GHGs) ~~1990~~ ~~greenhouse~~equal ~~gases~~to (“the amount of GHG”) emissions ~~levels~~allowed byfor ~~the~~that year. ~~2020;~~Emitters ~~(ii) 80%~~can ofobtain ~~1990~~allowances ~~levels~~from bythe ~~2050;~~ARB ~~and~~at ~~(iii) a~~quarterly ~~mandatory~~auctions ~~emission~~or ~~reporting~~from ~~program~~third parties or exchanges. ABEmitters 32may ~~required~~also satisfy a portion of their compliance obligation through the ~~California~~purchase ~~Air~~of ~~Resources~~offset ~~Board~~credits; ~~(“ARB”)~~e.g., tocredits ~~develop~~for aGHG ~~scoping~~reductions ~~plan~~achieved ~~describing~~by ~~the~~third ~~approach~~parties ~~California~~(such ~~will~~as ~~take~~landowners, tolivestock ~~reduce~~owners, ~~GHGs~~and tofarmers) ~~achieve~~that occur outside the ~~goal~~industry ofsectors ~~reducing~~covered ~~emissions~~under tothe ~~1990~~cap ~~levels~~through byARB-qualified ~~2020~~offset ~~(the~~projects ~~“2020~~such ~~Goal”)~~as reforestation or biomass projects. ~~The~~During ~~scoping~~the ~~plan~~nine ~~was~~months ~~first~~ended ~~approved~~December 31, by2015, the ~~ARB~~Company indetermined ~~2008~~that ~~which~~it ~~identifies~~had aexceeded ~~cap-and-trade~~its ~~program~~allowed asemissions ~~one~~threshold ofand ~~the~~became ~~strategies~~subject ~~California~~to ~~will~~compliance ~~employ~~obligations towhereby ~~meet~~it ~~the~~must ~~2020~~purchase ~~Goal~~allowances or offset credits. InAs ~~2010~~of December 31, ~~ARB~~2015, ~~approved~~the ~~that~~Company ~~cap~~had $0.8 million of accrued emission allowances and ~~trade~~offset ~~program~~credits and itthe ~~came~~Company ~~into~~was ~~effect~~exposed onto ~~January 1,~~risks ~~2013~~associated with changes in the price of credits for GHG reductions.

Entities are subject to compliance obligations if they exceed certain ARB-defined emission thresholds. During each year of the program, the ARB issues emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year. Emitters can obtain allowances from the ARB at quarterly auctions or from third parties or exchanges. Emitters may also satisfy a portion of their compliance obligation through the purchase of offset credits; e.g., credits for GHG reductions achieved by third parties (such as landowners, livestock owners, and farmers) that occur outside the industry sectors covered under the cap through ARB-qualified offset projects such as reforestation or biomass projects. During the quarter ended September 30, 2015, the Company determined that it had exceeded its allowed emissions threshold and became subject to compliance obligations whereby it must purchase allowances or offset credits. As of September 30, 2015, the Company had $0.8 million of accrued emission allowances and offset credits and the Company was exposed to risks associated with changes in the price of credits for GHG reductions.

Counterparty Credit Risk

Niska Partners is exposed to counterparty credit risk on its trade and accrued accounts receivable and risk management assets. Counterparty credit risk is the risk of financial loss to the Company if a customer fails to perform its contractual obligations. Niska Partners engages in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. Credit risk associated with trade accounts receivable is mitigated by the high percentage of investment grade customers, collateral support of receivables and Niska Partners’ ability to take ownership of customer owned natural gas stored in its facilities in the event of non-payment. For the ~~six~~nine months ended ~~September~~December 3031, 2015 and 2014, no expense related to doubtful accounts ~~expense~~ was recognized as a result of receivables deemed to be uncollectible. It is management’s opinion that no allowance for doubtful accounts was required as of ~~September~~December 3031, 2015 and March 31, 2015, respectively, on the Company’s accrued and trade accounts receivable.

The Company analyzes the financial condition of counterparties prior to entering into an agreement. Credit limits are established and monitored on an ongoing basis. Management believes, based on its credit policies, that the Company’s financial position, results of operations and cash flows will not be materially affected as a result of non-performance by any single counterparty. Credit risk is assessed prior to transacting with any counterparty and each counterparty is required to maintain an investment grade rating, provide a parental guarantee from an investment grade parent, or provide an alternative method of financial assurance (letter of credit, cash, etc.) to support proposed transactions. In addition, the Company’s tariffs contain provisions that permit it to take title to a customer’s inventory should the customer’s account remain unpaid for an extended period of time. Although the Company relies on a few counterparties for a significant portion of its revenues, one counterparty making up 4146.14% and 6158.02% of gross revenues for the ~~six~~nine months ended ~~September~~December 3031, 2015 and 2014, respectively, is a physical natural gas clearing and settlement facility that requires counterparties to post margin deposits equal to 125% of their net position, which reduces the risk of default.

Exchange traded futures and options comprise approximately 7176.74% of Niska Partners’ commodity risk management assets at ~~September~~December 3031, 2015. These exchange traded contracts have minimal credit exposure as the exchanges guarantee that every contract will be margined on a daily basis. In the event of any default, Niska Partners’ account on the exchange would be absorbed by other clearing members. Because every member posts an initial margin, the exchange can protect the exchange members if or when a clearing member defaults.

Niska Partners further manages credit exposure by entering into master netting agreements for the majority of non-retail contracts. These master netting agreements provide the Company, in the event of default, the right to offset the counterparty’s rights and obligations.

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

4. Risk Management Activities and Financial Instruments (continued)

Interest Rate Risk

Niska Partners assesses interest rate risk by continually identifying and monitoring changes in interest rate exposures that may adversely impact expected future cash flows. At ~~September~~December 3031, 2015, Niska Partners was exposed to interest rate risk resulting from the variable rates associated with its $400 million Credit Agreement of which $~~153~~140.57 million was drawn.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Niska Partners continues to manage its liquidity risk by ensuring sufficient cash and credit facilities are available to meet its operating and capital expenditure obligations when due, under both normal and stressed conditions.

Foreign Currency Risk

Foreign currency risk is created by fluctuations in foreign exchange rates. As Niska Partners conducts a portion of its activities in Canadian dollars, earnings and cash flows are subject to currency fluctuations. The performance of the Canadian dollar relative to the U.S. dollar could positively or negatively affect earnings. Niska Partners is exposed to cash flow risk to the extent that Canadian currency outflows exceed Canadian currency inflows. The Company enters into currency swaps to mitigate the impact of changes in foreign exchange rates. The notional value of currency swaps at ~~September~~December 3031, 2015 was $1822.26 million (March 31, 2015 - $19.6 million). These contracts expire on various dates from ~~October~~February 1, ~~2015~~2016 through ~~July~~December 1, 2016. Niska Partners has not elected hedge accounting treatment, therefore, changes in fair value are recorded directly in earnings.

The following tables show the fair values of Niska Partners’ risk management assets and liabilities at ~~September~~December 3031, 2015 and March 31, 2015:

	Energy			Currency
	Contracts			Contracts			Total
December 31, 2015	Contracts			Contracts			Total
September 30, 2015
Short-term risk management assets	$	31,998		$	2,962		$	34,960
Short-term risk management assets	$	27,782		$	3,857		$	31,639
Long-term risk management assets	26,065			—			26,065
Long-term risk management assets	28,691			—			28,691
Short-term risk management liabilities	(27,438		)	(524		)	(27,962		)
Short-term risk management liabilities	(25,384		)	(441		)	(25,825		)
Long-term risk management liabilities	(18,333		)	—			(18,333		)
Long-term risk management liabilities	(19,082		)	—			(19,082		)
	$	12,292		$	2,438		$	14,730
	$	12,007		$	3,416		$	15,423

	Energy			Currency
	Contracts			Contracts			Total
March 31, 2015	Contracts			Contracts			Total
March 31, 2015
Short-term risk management assets	$	39,392		$	2,208		$	41,600
Long-term risk management assets	29,647			1,281			30,928
Short-term risk management liabilities	(25,560		)	—			(25,560		)
Long-term risk management liabilities	(20,512		)	(321		)	(20,833		)
	$	22,967		$	3,168		$	26,135

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

4. Risk Management Activities and Financial Instruments (continued)

Information about the Company’s risk management assets and liabilities that had netting or rights of offset arrangements is as follows:

Gross Amounts Recognized

Gross Amounts Offset in the Balance Sheet

Net Amounts Presented in the Balance Sheet

Margin Deposits not Offset in the Balance Sheet

Net Amounts

December 31, 2015

Gross Amounts Recognized

Gross Amounts Offset in the Balance Sheet

Net Amounts Presented in the Balance Sheet

Margin Deposits not Offset in the Balance Sheet

Net Amounts

September 30, 2015

Assets

Commodity derivatives

~~161~~187,~~228~~824

(~~104~~129,~~755~~761

)

5658,~~473~~063

(4346,~~263~~618

)

1311,~~210~~445

Currency derivatives

32,~~857~~967

—(5

)

32,~~857~~962

—

32,~~857~~962

Total assets

~~165~~190,~~085~~791

(~~104~~129,~~755~~766

)

6061,~~330~~025

(4346,~~263~~618

)

1714,~~067~~407

Liabilities

Commodity derivatives

~~149~~175,~~221~~532

(~~104~~129,~~755~~761

)

4445,~~466~~771

(3841,~~900~~322

)

54,~~566~~449

Currency derivatives

~~441~~529

—(5

)

~~441~~524

(~~441~~524

)

—

Total liabilities

~~149~~176,~~662~~061

(~~104~~129,~~755~~766

)

4446,~~907~~295

(3941,~~341~~846

)

54,~~566~~449

Net

1514,~~423~~730

—

1514,~~423~~730

(34,~~922~~772

)

119,~~501~~958

	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet		Margin Deposits not Offset in the Balance Sheet			Net Amounts
March 31, 2015	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet		Margin Deposits not Offset in the Balance Sheet			Net Amounts
March 31, 2015
Assets
Commodity derivatives	$	148,385	$	(79,346	)	$	69,039	$	(50,070	)	$	18,969
Currency derivatives	5,167		(1,678		)	3,489		—			3,489
Total assets	153,552		(81,024		)	72,528		(50,070		)	22,458
Liabilities
Commodity derivatives	125,418		(79,346		)	46,072		(39,338		)	6,734
Currency derivatives	1,999		(1,678		)	321		(321		)	—
Total liabilities	127,417		(81,024		)	46,393		(39,659		)	6,734
Net	$	26,135	$	—		$	26,135	$	(10,411	)	$	15,724

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

4. Risk Management Activities and Financial Instruments (continued)

The Company expects to recognize risk management assets and liabilities outstanding at ~~September~~December 3031, 2015 into net earnings (loss) and comprehensive income (loss) in the fiscal periods as follows:

	Energy			Currency
	Contracts			Contracts		Total
Fiscal year ending March 31, 2016	$	3,~~962~~669		$	~~1,791~~229	$	53,~~753~~898
Fiscal year ending March 31, 2017	67,~~426~~090			12,~~625~~209		89,~~051~~299
Fiscal year ending March 31, 2018	3,~~233~~240			—		3,~~233~~240
Thereafter	(1,~~614~~707		)	—		(1,~~614~~707		)
	$	12,~~007~~292		$	32,~~416~~438	$	1514,~~423~~730

Net realized and unrealized optimization gains and losses from the settlement of risk management contracts are summarized as follows:

Three Months Ended

~~Six~~Nine Months Ended

September 30,

December 31,

2015

2014

2015

2014

Classification

Energy contracts

Realized

12,~~911~~415

103,~~314~~785

710,~~669~~084

1518,~~079~~864

Optimization, net

Unrealized

~~(1,617~~284

)

147,~~293~~546

(10,~~960~~675

)

148,~~071~~618

Optimization, net

Currency contracts

Realized

~~305~~1,941

~~(131~~277

)

12,~~047~~988

1,~~065~~342

Optimization, net

Unrealized

~~1,236~~(977

)

~~(295~~732

)

~~248~~(730

)

(~~1,224~~491

)

Optimization, net

13,~~835~~663

1152,~~181~~340

(1,~~996~~667

)

1568,~~991~~333

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

5. Fair Value Measurements

The carrying amount of cash and cash equivalents, margin deposits, trade receivables, accrued receivables, trade payables and accrued liabilities reported on the unaudited consolidated balance sheet approximate fair value.

Fair values have been determined as follows for Niska Partners’ assets and liabilities that were accounted for or disclosed at fair value on a recurring and non-recurring basis:

Level 1

Level 2

Level 3

Total

December 31, 2015

Level 1

Level 2

Level 3

Total

September 30, 2015

Assets

Commodity derivatives

—

5658,~~473~~063

—

5658,~~473~~063

Currency derivatives

—

32,~~857~~962

—

32,~~857~~962

Total assets

—

6061,~~330~~025

—

6061,~~330~~025

Liabilities

Commodity derivatives

—

4445,~~466~~771

—

4445,~~466~~771

Currency derivatives

—

~~441~~524

—

~~441~~524

Long-term debt

—

~~523~~506,~~250~~000

—

~~523~~506,~~250~~000

Total liabilities

—

~~568~~552,~~157~~295

—

~~568~~552,~~157~~295

	Level 1		Level 2		Level 3		Total
March 31, 2015	Level 1		Level 2		Level 3		Total
March 31, 2015
Assets
Commodity derivatives	$	—	$	69,039	$	—	$	69,039
Currency derivatives	—		3,489		—		3,489
Goodwill	—		—		—		—
Total assets	$	—	$	72,528	$	—	$	72,528
Liabilities
Commodity derivatives	$	—	$	46,072	$	—	$	46,072
Currency derivatives	—		321		—		321
Long-term debt	—		432,688		—		432,688
Total liabilities	$	—	$	479,081	$	—	$	479,081

The Company’s derivative assets and liabilities recorded at fair value on a recurring basis have been categorized as Level 2. The determination of the fair value of assets and liabilities for Level 2 valuations is generally based on a market approach. The key inputs used in Niska Partners’ valuation models include transaction-specific details such as notional volumes, contract prices and contract terms as well as forward market prices and basis differentials for natural gas obtained from third-party service providers (typically the New York Mercantile Exchange, or NYMEX). There were no changes in Niska Partners’ approach to determining fair value and there were no transfers out of Level 2 during the periods ended ~~September~~December 3031, 2015 and March 31, 2015.

The fair value of debt is the estimated amount the Company would have to pay to transfer its debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are supported by observable market transactions when available.

Non-financial assets and liabilities are re-measured at fair value on a non-recurring basis. During the year ended March 31, 2015, the Company wrote down goodwill to its estimated fair value of $nil, which is classified as a Level 3 measurement in the table above. There were no other non-financial assets or liabilities recorded at fair value as of ~~September~~December 3031, 2015 and March 31, 2015.

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

6. Members’ Equity

Distributions to Unitholders

As of the beginning of fiscal 2016, one of the Company’s Canadian subsidiaries owed interest to a non-Canadian subsidiary. During the ~~quarter~~nine months ended ~~September~~December 3031, 2015, the Company filed a tax election that deemed this interest as paid. The election triggered an obligation for the Company to pay withholding taxes of approximately $3.4 million to the Canadian tax authorities on behalf of the Company’s unitholders. Consistent with similar transactions in the past, the Company has accounted for this payment as a distribution to unitholders.

Unit-Based Performance Plan

The Company maintains compensatory unit-based performance plans (the “Plans”) to provide long-term incentive compensation for certain employees and directors, and to align their economic interest with those of common unitholders. The Plans are administered by the Compensation Committee of the Board of Directors and permit the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, other unit-based awards, distribution equivalent rights and substitution awards. Unit-based awards are settled either in cash or in common units following the satisfaction of certain time and/or performance criteria.

The Company agreed not to grant additional unit awards under these plans under the terms of the Merger Agreement.

Unit-based awards are classified as liabilities when expected to be settled in cash or when the Company has the option to settle in cash or equity. This accounting treatment has resulted from the Company’s historical practice of choosing to settle this type of award in cash. When awards are classified as liabilities, the fair value of the units granted is determined on the date of grant and is re-measured at each reporting period until the settlement date. The fair value at each remeasurement date is equal to the settlement expected to be incurred based on the anticipated number of units vested adjusted for (i) the passage of time and (ii) the payout threshold associated with the performance targets which the Company expects to achieve compared to its established peers. The performance criterion is based on total unitholder return (“TUR”) metrics compared to such metrics of a select group of the Company’s peers. The TUR metrics reflect the Company’s percentile ranking during the applicable performance period compared to a peer group. The pro-rata number of units vested is calculated as the number of performance awards multiplied by the percentage of the requisite service period.

Unit-based awards that are expected to be settled in units are classified as equity. The fair value of the units granted is determined on the date of grant and is amortized to equity using the straight-line method over the vesting period. Each equity settled award permits the holder to receive one common unit on the vesting date.

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

6. Members’ Equity (continued)

Unit-Based Performance Plan (continued)

The following tables summarize the Company’s unit-based awards outstanding and non-vested unit-based awards as of ~~September~~December 3031, 2015:

	Number of Time-Based Units		Number of Performance- Based Units		Total Units
Unit-based awards outstanding - March 31, 2015	1,199,341		214,679		1,414,020
Exercised	(225,097	)	(124,049	)	(349,146	)
Unit-based awards outstanding - September 30, 2015	974,244		90,630		1,064,874
Unit-based awards outstanding - December 31, 2015	974,244		90,630		1,064,874

	Number of Time-Based Units		Number of Performance- Based Units		Total Units
Nonvested unit-based awards - March 31, 2015	1,199,341		214,679		1,414,020
Vested	(225,097	)	(124,049	)	(349,146	)
Nonvested unit-based awards September 30, 2015	974,244		90,630		1,064,874
Nonvested unit-based awards December 31, 2015	974,244		90,630		1,064,874

As of ~~September~~December 3031, 2015, outstanding unit-based awards classified as liability and equity amounted to 743,609 units and 321,265 units, respectively.

Unit-based compensation for the three and ~~six~~nine months ended ~~September~~December 3031, 2015 were $0.67 million and $12.52 million, respectively (arecoveries ~~recovery~~ of $12.01 million and ~~an expense of~~ $01.47 million for the three and ~~six~~nine months ended ~~September~~December 3031, 2014, respectively). Amounts paid to employees for unit-based awards settled in cash for the ~~six~~nine months ended ~~September~~December 3031, 2015 and 2014 were $0.3 million and $10.6 million, respectively. ~~During~~In ~~the quarter ended September~~August ~~30,~~ 2015, 19,868 equity awards were settled using common units purchased from the open market for $0.1 million. No other equity awards were settled during the ~~six~~nine months ended ~~September~~December 3031, 2015, and 2014.

As of ~~September~~December 3031, 2015, there was $43.02 million (March 31, 2015 - $5.1 million) of total unrecognized compensation cost related to non-vested unit-based awards granted that were subject to both time and performance conditions. That cost is expected to be recognized over the next two years.

Modifications of Certain Unit-based Awards Outstanding

In July 2015, the Company offered certain eligible employees retention award opportunities that will become vested on the earlier of the date of successful closing of the Transaction or the ninetieth day following the termination of the Transaction contemplated in the Merger Agreement. To participate in this plan, each participant was required to forfeit rights to any outstanding performance-based unit awards and agree that all settlements, if any, of the outstanding time-based unit awards will be settled in cash.

Eligible employees with 466,949 outstanding unit-based awards participated in this plan which resulted in modifications of their original awards. In addition, 28,478 equity awards that would have been forfeited upon the termination of a previous employee were modified to remain eligible to vest upon the closing of the Transaction. These modifications did not result in additional compensation costs for the Company.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

6. Members’ Equity (continued)

Earnings per unit

Niska Partners uses the two-class method for allocating earnings per unit (“EPU”). The two-class method requires the determination of net earnings (loss) allocated to member interests as shown below.

	Three Months Ended						~~Six~~Nine Months Ended
	September 30,						September 30,
	December 31,						December 31,
	2015			2014			2015			2014
Numerator:
Net earnings (loss)	$	(1920,~~609~~992	)	$	(28259,~~832~~623	)	$	(5778,~~016~~008	)	$	(47307,~~803~~426	)
Less:
Managing Member’s interest	~~353~~378			~~538~~4,677			1,~~027~~405			~~896~~5,573
Net earnings (loss) attributable to common unitholders	$	(1920,~~256~~614	)	$	(28254,~~294~~946	)	$	(5576,~~989~~603	)	$	(46301,~~907~~853	)
Denominator:
Basic:
Weighted average units outstanding	37,988,724			3637,~~398~~245,~~996~~225			37,988,724			36,~~156~~520,~~526~~746
Diluted:
Weighted average units outstanding	37,988,724			3637,~~398~~245,~~996~~225			37,988,724			36,~~156~~520,~~526~~746
Earnings (loss) per unit:
Basic	$	(0.5154	)	$	(06.7885	)	~~(1.47~~$	(2.02	)	$	(18.3027	)
Diluted	$	(0.5154	)	$	(06.7885	)	$	(12.4702	)	$	(18.3027	)
Weighted average number of equity-settled awards:	~~416~~321,~~453~~265			~~315~~465,~~490~~971			~~563~~482,~~784~~651			~~158~~261,~~607~~434

The Company maintains unit-based compensation plans that could dilute EPU in future periods. Because granted awards were anti-dilutive for the three and ~~six~~nine months ended ~~September~~December 3031, 2014 and 2015, the diluted EPU calculations above exclude the weighted average number of equity-settled unit-based awards.

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

7. Revenues

Niska Partners’ fee-based revenue consists of the following:

Three Months Ended

~~Six~~Nine Months Ended

September 30,

December 31,

2015

2014

2015

2014

Long-term contract revenue

8,~~928~~754

1413,~~101~~373

1827,~~573~~327

5467,~~584~~956

Short-term contract revenue

34,~~724~~473

12,~~532~~255

812,~~341~~814

36,~~803~~059

Total

1213,~~652~~227

15,~~633~~628

2640,~~914~~141

5874,~~387~~015

Long-term contract revenue for the ~~six~~nine months ended ~~September~~December 3031, 2014 included a one-time payment of $26.0 million as a result of the termination by TransCanada Gas Storage Partnership (“TransCanada”), the Company’s largest volumetric customer, of its previous storage service agreement.

Optimization, net consists of the following:

	Three Months Ended						~~Six~~Nine Months Ended
	September 30,						September 30,
	December 31,						December 31,
	2015			2014			2015			2014
Realized optimization revenue, net	$	56,~~065~~686		$	47,~~458~~013		$	1017,~~379~~065		$	1825,~~231~~244
Unrealized risk management (losses) gains	(~~381~~693		)	~~999~~48,278			(1011,~~712~~405		)	~~(151~~48,127		)
Write-down of inventory	—			(10,500		)	—			(10,500		)
Write-downs of inventory	(600		)	(31,700		)	(600		)	(42,200		)
Total	$	45,~~684~~393		$	(523,~~043~~591	)	$	~~(333~~5,060	)	$	731,~~580~~171

8. Income Taxes

Income taxes included in the consolidated financial statements were as follows:

	Three Months Ended						~~Six~~Nine Months Ended
	September 30,						September 30,
	December 31,						December 31,
	2015			2014			2015			2014
Income tax benefit	$	(64,~~494~~704	)	$	(715,~~348~~635	)	$	(27,~~555~~259	)	$	(1631,~~240~~875	)
Effective income tax rate	2518		%	206		%	49		%	259		%

The effective tax rate for the three and ~~six~~nine months ended ~~September~~December 3031, 2015 and 2014 ~~differs~~differed from the U.S. statutory federal rate of 35% primarily because certain Canadian subsidiaries are taxed at a lower statutory tax rate as well as the earnings (loss) from certain subsidiaries are exempt from U.S federal income taxes. In addition, during the three and nine months ended December 31, 2014, the Company recorded a goodwill impairment of $245.6 million of which no tax benefit was recognized.

Income tax benefit for the ~~six~~three and nine months ended ~~September~~December 3031, 2015 decreased by $1310.79 million and $24.6 million compared to the ~~six~~three and nine months ended ~~September~~December 3031, 2014. ~~This~~These ~~change~~changes ~~was~~were primarily due to lower recognized losses in certain taxable entities. ~~and~~An an increase in Canadian provincial income tax rates which impacted certain Canadian taxable entities also contributed to lower tax benefit for the nine months ended December 31, 2015.

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

9. Accrued Liabilities

Niska Partners’ accrued liabilities consist of the following:

	September 30,		March 31,
	December 31,		March 31,
	2015		2015
Accrued gas purchases	$	2116,~~706~~560	$	13,917
Accrued interest	2111,~~384~~968		21,411
Employee-related accruals	2,~~653~~895		2,369
Other accrued liabilities	1210,~~067~~725		9,989
Total	$	5742,~~810~~148	$	47,686

10. ~~Changes~~Related inParty ~~Non-Cash Working Capital~~Transactions

~~Changes~~As of December 31, 2015, in ~~non-cash~~addition ~~working~~to ~~capital~~the ~~for~~$5.5 million receivable from Niska Holdings L.P. discussed in Note 2, the ~~six~~Company ~~months~~had ~~ended~~receivables ~~September~~from other related parties of $0.7 million ($nil as of March 3031, 2015) ~~and~~which ~~2014~~are ~~consist~~included ofin accrued receivable in the ~~following:~~balance sheets. These receivables relate to reimbursement of costs incurred by Niska Partners on behalf of a related party as well as management fees charged to affiliated entities for certain administrative services.

	Six Months Ended
	September 30,
	2015			2014
Margin deposits	$	(5,390	)	$	(25,360	)
Trade receivables	1,245			4,093
Accrued receivables	21,977			122,578
Natural gas inventory	25,178			(209,331		)
Prepaid expenses and other current assets	711			1,148
Other assets	80			—
Trade payables	(15		)	(278		)
Accrued liabilities	10,319			(27,010		)
Deferred revenue	47			11,904
Other long-term liabilities	(98		)	(645		)
Total	$	54,054		$	(122,901	)

During the three and nine months ended December 31, 2015, total management fees and reimbursable costs recognized by the Company amounted to $0.3 million and $0.8 million, respectively, as reductions to general and administrative expenses ($nil for the nine months ended December 31, 2014).

11. Changes in Non-Cash Working Capital

Changes in non-cash working capital for the nine months ended December 31, 2015 and 2014 consist of the following:

	Nine Months Ended
	December 31,
	2015			2014

Margin deposits	$	3,558		$	29,434
Trade receivables	337			2,769
Accrued receivables	13,523			112,573
Natural gas inventory	54,681			(176,425		)
Prepaid expenses and other current assets	754			(3,103		)
Other assets	67			(437		)
Trade payables	(486		)	(299		)
Accrued liabilities	(4,247		)	(67,187		)
Deferred revenue	(6,430		)	(2,029		)
Other long-term liabilities	(90		)	(634		)
Total	$	61,667		$	(105,338	)

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

1112. Supplemental Cash Flow Disclosures

	Six Months Ended
	Nine Months Ended
	September 30,
	December 31,
	2015			2014
Interest paid	$	23,915		$	4,243
Interest paid in cash	$	44,960		$	27,658
Taxes paid	$	251		$	288
Interest paid in-kind	$	551		$	—
Non-cash changes in working capital related to property, plant and equipment	$	(4	)	$	(395	)
Taxes paid (recovered)	$	1,463		$	(231	)
Non-cash earnings distribution and reinvestment	$	—		$	12,928
Non-cash changes in working capital related to property, plant and equipment	$	262		$	1,716
Non-cash earnings distribution and reinvestment	$	—		$	19,631

~~12.~~Under ~~Segment~~the ~~Disclosures~~Company’s Short-term Credit Facility, interest is payable in cash on a quarterly basis, unless the Company elects to pay such interest in-kind by capitalizing accrued interest into the principal amount.

13. Segment Disclosures

The Company’s process for the identification of reportable segments involves examining the nature of services offered, the types of customer contracts entered into and the nature of the economic and regulatory environment.

Niska Partners operates along functional lines in its commercial, engineering and operations teams for operations in Alberta, northern California and the U.S. mid-continent. All functional lines and facilities offer the same services: storage and optimization. The Company has a small retail marketing business which is an extension of the Company’s proprietary optimization activities. Proprietary optimization activities occur when the Company purchases, stores and sells natural gas for its own account in order to utilize or optimize storage capacity that is not contracted or available to third-party customers. All services are delivered using reservoir storage. The Company measures profitability consistently along all functional lines based on revenues and earnings before interest, taxes, depreciation and amortization, and unrealized risk management gains and losses. The Company has aggregated its operating segments into one reportable segment as at ~~September~~December 3031, 2015 and March 31, 2015 and for each of the three and ~~six~~nine months ended ~~September~~December 3031, 2015 and 2014.

Information pertaining to the Company’s short-term and long-term contract services and net optimization revenues is presented in the consolidated statements of earnings (loss) and comprehensive income (loss). All facilities have the same types of customers: major companies in the energy industry, industrial, commercial, local distribution companies and municipal energy consumers.

Table of Contents

Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Thousands of U.S. dollars, except per Unit amounts and unless otherwise noted)

1213. Segment Disclosures (continued)

The following tables summarize the net revenues and long lived assets by geographic area:

	Three Months Ended						~~Six~~Nine Months Ended
	September 30,						September 30,
	December 31,						December 31,
	2015			2014			2015			2014
Net realized revenues
U.S.	$	79,~~046~~745		$	86,~~022~~028		$	1222,~~358~~103		$	1218,~~066~~094
Canada	10,~~671~~168			1216,~~068~~613			2435,~~935~~103			6481,~~552~~165
Net unrealized revenues
U.S.	(~~513~~2,092		)	(129,~~486~~989		)	(911,~~853~~945		)	~~873~~29,159
Canada	~~132~~1,399			218,~~486~~289			~~(859~~540		)	(118,~~024~~968		)
Write-down of inventory
Write-downs of inventory
U.S.	—(600		)	(62,~~400~~800		)	—(600		)	(69,~~400~~200		)
Canada	—			(428,~~100~~900		)	—			(433,~~100~~000		)
Inter-entity
U.S.	~~3,711~~709			—1,703			34,~~557~~266			—1,703
Canada	(~~3,711~~709		)	—(1,703		)	(34,~~557~~266		)	—(1,703		)
	$	1718,~~336~~620		$	1039,~~590~~219		$	2645,~~581~~201		$	65105,~~967~~186

	September 30,		March 31,
	December 31,		March 31,
	2015		2015
Long-lived assets (at period end)
U.S.	$	~~361~~358,~~796~~706	$	367,920
Canada	~~488~~474,~~353~~105		508,706
	$	~~850~~832,~~149~~811	$	876,626

14. Subsequent Events

Subsequent to the announcement of the proposed acquisition of the Company by Brookfield Infrastructure Partners L.P. and its institutional partners on June 14, 2015, alleged unitholders of Niska Gas Storage Partners LLC (the “Plaintiffs”) filed four class action lawsuits against Niska Gas Storage Partners LLC, Niska Gas Storage Management LLC, Niska Sponsor Holdings Coöperatief U.A. (collectively “Niska”), Brookfield Infrastructure Partners L.P., Swan Holdings LP, Swan Merger Sub LLC, and the members of Niska’s Board of Directors (collectively with Niska, the “Defendants”) in the Court of Chancery of the State of Delaware. These lawsuits are styled (a) Eddie Barringer vs. Niska Gas Storage Partners LLC, et al. (Case No. 11210); (b) David Raul vs. Niska Gas Storage Partners LLC, et al. (Case No. 11220); (c) Nathan Peterson vs. Niska Gas Storage Partners LLC, et al., (Case No. 11234); and (d) Fred Pappey vs. William H. Shea, Jr. et al., (Case No. 11238) (collectively, the “Litigation”). The above styled lawsuits have been consolidated for all purposes and captioned In re Niska Gas Storage Partners LLC Public Unitholders Litigation, CONSOL. C.A. No. 11210-CB (the “Action”). On February 5, 2016, the Plaintiffs filed a notice of voluntary dismissal of the Litigation without prejudice as to any individual or class claims, with each party to bear its own costs.

Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following information should be read in conjunction with our unaudited consolidated financial statements and accompanying notes included in this report. The following information and such unaudited consolidated financial statements should also be read in conjunction with the consolidated financial statements and related notes, management’s discussion and analysis of financial condition and results of operations and other information included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2015.

Overview of Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with GAAP requires estimates and judgments to be made regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Our most critical accounting estimates, which involve the judgment of our management, were fully disclosed in our Annual Report on Form 10-K for the fiscal year ended March 31, 2015 and remained unchanged as of ~~September~~December 3031, 2015.

Overview of Our Business

We operate the AECO HubTM, which consists of the Countess and Suffield gas storage facilities in Alberta, Canada, and the Wild Goose and Salt Plains gas storage facilities in California and Oklahoma, respectively. Niska Partners markets gas storage services of working gas capacity in addition to optimizing storage capacity with its own proprietary gas purchases at each of these facilities. We also operate a natural gas marketing business which is an extension of our propriety optimization activities in Canada.

We earn revenues by leasing storage on a long-term firm (“LTF”) contract basis for which we receive monthly reservation fees for fixed amounts of storage, leasing storage on a short-term firm (“STF”) contract basis, where a customer pays a fixed fee to inject a specified quantity of natural gas on a specified date or dates and a fixed fee to withdraw on a specified future date or dates, and optimization, where we purchase and sell gas on an economically hedged basis in order to improve facility utilization at margins that can be higher than those from third-party contracts. Proprietary optimization activities occur when the Company purchases and sells natural gas for its own account. Our revenues related to our marketing business are included in proprietary optimization activities.

The Company has a total of 244.9 Bcf of working gas capacity among its facilities, including 2.9 Bcf leased from a third-party pipeline company.

We have aggregated all of our activities in one reportable operating segment for financial reporting purposes. Our consolidated financial statements are prepared in accordance with GAAP.

Factors that Impact Our Business

In June 2015, the Company and Niska Gas Storage Management LLC, its Managing Member, entered into a definitive agreement to be acquired by Brookfield. Under the terms of the Merger Agreement, Brookfield will acquire all of the Company’s outstanding common units for $4.225 per common unit in cash and will acquire the Managing Member and the IDRs in the Company. ~~The~~prior ~~closing of the Transaction is expected~~ to ~~occur in the calendar year 2016 and is subject to customary closing conditions and regulatory approvals~~June 14, ~~including approval by the CPUC~~2017. A period provided for in the Merger Agreement for unsolicited consideration of alternative acquisition proposals expired on July 29, 2015.

The Merger Agreement, which includes a commitment by the Company not to make cash distributions until the earlier of the date of closing or termination of the Transaction, was approved by the Company Board and the Conflicts Committee. Affiliates of the Carlyle/Riverstone Funds delivered a written consent approving the Transaction. No additional unitholder action is required to approve the Transaction.

InThe ~~connection~~closing ~~with~~of the ~~entry~~Transaction ~~into~~is dependent on the ~~Merger~~satisfaction ~~Agreement~~of certain conditions related to regulatory requirements, including the approval of the CPUC. The process that the Company and Brookfield ~~agreed~~must undertake to ~~lend~~obtain upCPUC approval to ~~$50~~transfer control of Niska Partners’ facility in California, Wild Goose, is potentially lengthy.0 ~~million~~Broadly, toit encompasses filing an application with the ~~Company~~CPUC, ~~under~~obtaining acomments ~~short-term~~from ~~credit~~interested ~~facility~~parties, addressing any objections from third parties or the CPUC, potentially undertaking regulatory hearings and obtaining the Commission’s formal approval of the transfer of control of Wild Goose to beBrookfield ~~used~~based ~~for~~on ~~working~~a ~~capital~~written ~~purposes~~decision from an administrative law judge (“ALJ”). Each step in the process is ultimately at the discretion of the ALJ and the Commission. To date, the following formal actions have been taken:

· Niska Partners and Brookfield filed their joint application with respect to the transfer of control of Wild Goose to Brookfield with the CPUC on August 3, 2015. The application was subsequently made available on the CPUC’s website for comments from interested parties. Five parties filed comments during the public comment period for the application which closed on September 11, 2015;

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~~During~~· The ~~the~~Company ~~six months ended September 30, 2015, the difference between summer~~ and ~~winter~~Brookfield ~~prices~~responded ~~in the natural gas futures market, referred~~ to as the ~~seasonal~~comments ~~spread,~~on remained extremely narrow and reduced levels of volatility persisted in the cash market. These conditions resulted from numerous factors, including, but not limited to: (i) a material year-over-year increase in natural gas production in the Lower 48 states as well as in Western Canada; (ii) higher overall levels of natural gas in storage; (iii) real or perceived changes in overall supply and demand fundamentals; and (iv) the development of new pipeline infrastructure connecting new supply to markets. These market conditions have negatively impacted our revenues during the six months ended September 3021, 2015 ~~by eroding the prices we can charge for long~~ and ~~short~~subsequently ~~term~~worked ~~firm~~to ~~contracting~~satisfy ~~services, as well as reducing~~ the ~~profitability~~questions ofraised ~~our optimization activities, where we make economically hedged natural gas purchases for our own account. As STF and LTF contracts expire~~ in ~~future years, new contracts could be entered into at lower rates than~~ the ~~expiring~~parties’ ~~contracts~~comments; and the impact on revenues could be material. If low levels of volatility and narrow seasonal spreads persist, our future revenues and profitability will continue to be adversely affected to a material extent.

· A prehearing conference was held on December 8, 2015, open to all parties and presided over by the assigned ALJ. At this prehearing conference, the ALJ ruled that no hearings would be required for this application and that no further testimony or evidence was necessary.

Consequently, we expect the Transaction to be consummated in calendar year 2016; however, the timing of the process remains within the purview of the CPUC and the Transaction remains subject to other non-regulatory closing conditions.

The Company is presently in the process of negotiating an amendment and extension of its existing $400.0 million Credit Agreement which if completed will, among other things, permit the Merger Agreement to proceed without triggering a change-of-control provision in the Credit Agreement, and extend the term of the Credit Agreement beyond June 29, 2016 to September 30, 2016, or to December 31, 2016, if the Transaction closes on or before September 16, 2016. It is likely that any such amendment and extension will result in a reduction in the maximum availability under the $400.0 million Credit Agreement. However, in the event that an extension of the agreement is not consummated, the Company will be required to raise additional funds in order to repay the Credit Agreement at its maturity in June 2016. If the extension of the agreement is consummated as contemplated, the Company will be required to further extend the maturity date or raise additional funds to repay the Credit Agreement at its final maturity date. We can provide no assurance that we will be able to further extend the maturity date or raise additional funds to repay the Credit Agreement upon its revised maturity.

During the first half of the fiscal year, the difference between summer and winter prices in the natural gas futures market, referred to as the seasonal spread, remained extremely narrow and reduced levels of volatility persisted in the cash market. These conditions resulted from numerous factors, including, but not limited to: (i) a material year-over-year increase in natural gas production in the United States as well as in Western Canada; (ii) higher overall levels of natural gas in storage; (iii) real or perceived changes in overall supply and demand fundamentals; (iv) the development of new pipeline infrastructure connecting new supply to markets; and (v) the weather during the first part of winter being milder than normal. These market conditions have negatively impacted our revenues during the nine months ended December 31, 2015 by eroding the prices we can charge for long and short-term firm contracting services, as well as reducing the profitability of our optimization activities, where we make economically hedged natural gas purchases for our own account.

The combination of reductions in natural gas prices, collateral required to support our retail marketing operations, costs associated with the requirements for temporary reservoir pressure support and unfavorable market conditions which have prevented us from realizing additional revenues and earnings have reduced the liquidity available under the Company’s $400 million revolving credit facilities. Continued reduction in amounts available under the revolving credit facilities may restrict our ability to pursue optimization strategies. The inability to pursue such revenue strategies may have a material adverse effect on the Company’s revenues and profitability.

Market conditions for natural gas storage can change rapidly as a result of a number of factors, including weather patterns, overall storage levels across North America in the markets we serve, current and anticipated levels of natural gas supply and demand, and constraints on pipeline infrastructure capacity. Accordingly, current market conditions may not be a reliable predictor of future market conditions. Longer term, we believe several factors may contribute to meaningful growth in North American natural gas demand, including: (i) exports of North American Liquefied Natural Gas; (ii) fuel switching for power generation from coal to natural gas; (iii) construction of new gas-fired power plants; (iv) growing exports to Mexico; and (v) growth in base-load industrial demand, all of which could bolster the demand for, and the commercial value of, natural gas storage. We are unable to predict the timing or magnitude of such events nor can we predict the ultimate impact they may have on our results of operations.

Our ~~storage~~financial ~~facilities~~statements ~~may~~include ~~require additional~~ natural gas toinventory ~~provide~~valued ~~temporary~~at ~~pressure~~the ~~support~~lower ~~during~~of ~~periods~~cost or market of ~~high~~$81.0 ~~activity~~million toas ~~meet~~of ~~cycling~~December 31, ~~requirements~~2015. ~~and~~We ~~performance~~calculate ~~demands~~the ~~related~~market tovalue of our ~~gas~~inventory inusing ~~storage.~~forward ~~These~~prices ~~volumes~~along ~~fluctuate~~with ~~from~~the ~~year~~associated tofinancial ~~year~~hedges ~~along~~over ~~with~~the ~~our~~timeframe ~~cycling~~of ~~requirements.~~the ~~These~~scheduled ~~cycling~~physical ~~requirements~~withdrawals. ~~are~~Market ~~managed~~conditions ~~through~~during athe ~~combination~~final quarter of ~~strategies~~the ~~which~~fiscal ~~are~~year ~~adapted~~will impact our decision to ~~changes~~sell inor ~~natural~~hold ~~gas~~significant ~~market~~volumes ~~conditions~~of inventory into fiscal 2017. ~~Typically,~~During the ~~use~~three ofmonths ~~gas~~ending toMarch 31, ~~provide~~2016, ~~temporary~~if ~~pressure~~we ~~support~~decide ~~results~~to inhold ~~net~~on ~~revenue~~to ~~gains~~our ~~because~~inventory ~~the~~at ~~cost~~year end to ~~acquire~~capture ~~natural~~additional ~~gas~~values inand ~~the~~as ~~nearer~~our ~~term~~current ishedge positions settle, we may enter into new hedge positions at lower ~~than~~values. These decisions may result in the ~~price~~market value of our natural gas ~~for~~inventory ~~future~~becoming ~~delivery~~less than its carrying cost at March 31, 2016 and any resulting inventory write-down could be material.

To mitigate the cost of our forecasted cycling requirements over the next five years, we implemented a hedging program to purchase and lease gas. Over the upcoming five years, the expected cumulative cost of temporary pressure support gas is approximately $6.6 million. This cost relates to our commitments to lease certain volumes of natural gas to address our future temporary pressure support needs. In the event that natural gas storage market conditions become more favorable, the cost of managing our operational requirements could be reduced. However, if the conditions deteriorate, the cost of managing our operational requirements will increase.

The Company’s functional currency is the U.S. dollar. The Company generates revenues from its Canadian operations in Canadian dollars. Cash inflows from revenues are offset, in part, by natural gas inventory purchases, operating, general and administrative and capital costs that are also transacted in Canadian dollars. The majority of the Company’s hedges are transacted in U.S. dollars on the NYMEX or with private counterparties. The Company’s financial instruments, principally its Common Units, 6.50% Senior Notes and revolving credit facilities, are principally denominated in U.S. dollars. The Company hedges its net exposure to the Canadian dollar by entering into currency hedges for the substantial majority of its net exposure for existing transactions. The Company does not hedge its net Canadian dollar exposure for potential future transactions, because the timing and amount of those transactions, which include proprietary optimization purchases and sales, are difficult to predict. The Company does not believe that declines in the Canadian dollar have materially impacted the Company’s results of operations during the six months ended September 30, 2015 because lower level of revenues has been offset by lower expenses and hedging gains realized during the period.

In the intermediate term, any declines in value of the Canadian dollar versus the U.S. dollar will reduce positive cash flows measured in U.S. dollars to the extent Niska Partners is not able to hedge these transactions in advance. Because of the matters discussed above, the Company is unable to predict the impact of any such declines should they occur.

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~~Results~~Our storage facilities may require additional natural gas to provide temporary pressure support during periods of ~~Operations~~high activity to meet cycling requirements and performance demands related to our gas in storage. These volumes fluctuate from year to year along with our cycling requirements. These cycling requirements are managed through a combination of strategies which are adapted to changes in natural gas market conditions. Typically, the use of gas to provide temporary pressure support results in net revenue gains because the cost to acquire natural gas in the nearer term is lower than the price of natural gas for future delivery.

ATo ~~summary~~mitigate the cost of ~~financial~~our ~~data~~forecasted ~~for~~cycling ~~each~~requirements ofover the ~~three~~next five years, we implemented a hedging program to purchase and ~~six~~lease ~~months~~gas. ~~ended~~Over ~~September 30~~the upcoming five years, ~~2015~~the ~~and~~expected ~~2014~~cumulative cost of temporary pressure support gas is asapproximately ~~follows~~$6.0 ~~(in~~million. ~~thousands):~~This cost relates to our commitments to lease certain volumes of natural gas to address our future temporary pressure support needs. In the event that natural gas storage market conditions become more favorable, the cost of managing our operational requirements could be reduced. However, if the conditions deteriorate, the cost of managing our operational requirements will increase.

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
	(unaudited)						(unaudited)
Consolidated Statement of Earnings (Loss) and Comprehensive Income (Loss) Data:
Revenues:
Fee-based revenue	$	12,652		$	15,633		$	26,914		$	58,387
Optimization, net	4,684			(5,043		)	(333		)	7,580
	17,336			10,590			26,581			65,967
Expenses (income):
Operating	8,626			12,062			16,583			23,015
General and administrative	6,730			6,205			17,960			16,279
Depreciation and amortization	14,805			16,012			25,539			65,978
Interest	12,965			12,735			25,706			25,047
Loss on disposal of assets	240			20			240			6
Foreign exchange losses (gains)	79			(262		)	135			(312		)
Other income	(6		)	(2		)	(11		)	(3		)
Earnings (loss) before income taxes	(26,103		)	(36,180		)	(59,571		)	(64,043		)
Income tax benefit	(6,494		)	(7,348		)	(2,555		)	(16,240		)
Net earnings (loss) and comprehensive income (loss)	$	(19,609	)	$	(28,832	)	$	(57,016	)	$	(47,803	)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Earnings (Loss)
Net earnings (loss)	$	(19,609	)	$	(28,832	)	$	(57,016	)	$	(47,803	)
Add/(deduct):
Interest expense	12,965			12,735			25,706			25,047
Income tax benefit	(6,494		)	(7,348		)	(2,555		)	(16,240		)
Depreciation and amortization	14,805			16,012			25,539			65,978
Non-cash compensation	130			993			713			1,243
Unrealized risk management losses (gains)	381			(999		)	10,712			151
Loss on disposal of assets	240			20			240			6
Foreign exchange losses (gains)	79			(262		)	135			(312		)
Other income	(6		)	(2		)	(11		)	(3		)
Write-down of inventory	—			10,500			—			10,500
Adjusted EBITDA	2,491			2,817			3,463			38,567
Less:
Cash interest expense, net	12,007			11,822			23,834			23,222
Income taxes paid	—			288			251			288
Maintenance capital expenditures	655			1,061			810			1,460
Other income	(6		)	(2		)	(11		)	(3		)
Cash Available for Distribution	$	(10,165	)	$	(10,352	)	$	(21,421	)	$	13,600

The Company’s functional currency is the U.S. dollar. The Company generates revenues from its Canadian operations in Canadian dollars. Cash inflows from revenues are offset, in part, by natural gas inventory purchases, operating, general and administrative and capital costs that are also transacted in Canadian dollars. The majority of the Company’s hedges are transacted in U.S. dollars on the NYMEX or with private counterparties. The Company’s financial instruments, principally its Common Units, 6.50% Senior Notes and revolving credit facilities, are principally denominated in U.S. dollars. The Company hedges its net exposure to the Canadian dollar by entering into currency hedges for the substantial majority of its net exposure for existing transactions. The Company does not hedge its net Canadian dollar exposure for potential future transactions, because the timing and amount of those transactions, which include proprietary optimization purchases and sales, are difficult to predict. The Company does not believe that declines in the Canadian dollar have materially impacted the Company’s results of operations during the nine months ended December 31, 2015 because its impact on revenues has been offset by lower expenses and hedging gains realized during the period.

In the intermediate term, any declines in value of the Canadian dollar compared to the U.S. dollar will reduce positive cash flows measured in U.S. dollars to the extent Niska Partners is not able to hedge these transactions in advance. Because of the matters discussed above, the Company is unable to predict the impact of any such declines should they occur.

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Results of Operations

A summary of financial data for each of the three and nine months ended December 31, 2015 and 2014 is as follows (in thousands):

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2015			2014			2015			2014
	(unaudited)						(unaudited)
Consolidated Statement of Earnings (Loss) and Comprehensive Income (Loss) Data:
Revenues:
Fee-based revenue	$	13,227		$	15,628		$	40,141		$	74,015
Optimization, net	5,393			23,591			5,060			31,171
	18,620			39,219			45,201			105,186
Expenses (income):
Operating	7,709			9,434			24,292			32,451
General and administrative	5,718			4,233			23,678			20,513
Depreciation and amortization	17,392			41,752			42,931			107,730
Interest	13,265			13,182			38,971			38,229
Impairment of goodwill	—			245,604			—			245,604
Losses (gains) on disposals of assets	28			(70		)	268			(64		)
Foreign exchange losses	197			344			332			32
Other expense (income)	7			(2		)	(4		)	(8		)
Earnings (loss) before income taxes	(25,696		)	(275,258		)	(85,267		)	(339,301		)

Income tax benefit	(4,704		)	(15,635		)	(7,259		)	(31,875		)

Net earnings (loss) and comprehensive income (loss)	$	(20,992	)	$	(259,623	)	$	(78,008	)	$	(307,426	)

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Earnings (Loss)
Net earnings (loss)	$	(20,992	)	$	(259,623	)	$	(78,008	)	$	(307,426	)
Add/(deduct):
Interest expense	13,265			13,182			38,971			38,229
Income tax benefit	(4,704		)	(15,635		)	(7,259		)	(31,875		)
Depreciation and amortization	17,392			41,752			42,931			107,730
Non-cash compensation	560			444			1,273			1,687
Unrealized risk management losses (gains)	693			(48,278		)	11,405			(48,127		)
Losses (gains) on disposals of assets	28			(70		)	268			(64		)
Impairment of goodwill	—			245,604			—			245,604
Foreign exchange losses	197			344			332			32
Other expense (income)	7			(2		)	(4		)	(8		)
Write-downs of inventory	600			31,700			600			42,200
Adjusted EBITDA	7,046			9,418			10,509			47,982

Less:
Cash interest expense, net	12,256			12,269			36,090			35,491
Income taxes paid (recovered)	1,212			(519		)	1,463			(231		)
Maintenance capital expenditures	1,134			1,780			1,944			3,240
Other expense (income)	7			(2		)	(4		)	(8		)
Cash Available for Distribution	$	(7,563	)	$	(4,110	)	$	(28,984	)	$	9,490

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Non-GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution

We use the non-GAAP financial measures Adjusted EBITDA and Cash Available for Distribution in this report. A reconciliation of Adjusted EBITDA and Cash Available for Distribution to net earnings (loss), the most directly comparable financial measure as calculated and presented in accordance with GAAP, is shown above.

We define Adjusted EBITDA as net earnings (loss) before interest, income taxes, depreciation and amortization, unrealized risk management gains and losses, loss on extinguishment of debt, foreign exchange gains and losses, inventory impairment write-downs, gains and losses on asset dispositions, non-cash compensation, asset impairments and other income. We believe the adjustments for other income are similar in nature to the traditional adjustments to net earnings used to calculate EBITDA and adjustment for these items results in an appropriate representation of this financial measure. Cash Available for Distribution is defined as Adjusted EBITDA reduced by interest expense (excluding amortization of deferred financing costs), income taxes paid, maintenance capital expenditures and other income. Adjusted EBITDA and Cash Available for Distribution are used as supplemental financial measures by our management and by external users of our financial statements, such as commercial banks and ratings agencies, to assess:

· the financial performance of our assets, operations and return on capital without regard to financing methods, capital structure or historical cost basis;

· the ability of our assets to generate cash sufficient to pay interest on our indebtedness and make distributions to our equity holders;

· repeatable operating performance that is not distorted by non-recurring items or market volatility; and

· the viability of acquisitions and capital expenditure projects.

The non-GAAP financial measures of Adjusted EBITDA and Cash Available for Distribution should not be considered as alternatives to net earnings (loss). Adjusted EBITDA and Cash Available for Distribution are not presentations made in accordance with GAAP and have important limitations as analytical tools. Neither Adjusted EBITDA nor Cash Available for Distribution should be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and Cash Available for Distribution exclude some, but not all, items that affect net earnings (loss) and are defined differently by different companies, our definition of Adjusted EBITDA and Cash Available for Distribution may not be comparable to similarly titled measures of other companies.

We recognize that the usefulness of Adjusted EBITDA as an evaluative tool may have certain limitations, including:

· Adjusted EBITDA does not include interest expense. Because we have borrowed money in order to finance our operations, interest expense is a necessary element of our costs and impacts our ability to generate profits and cash flows. Therefore, any measure that excludes interest expense may have material limitations;

· Adjusted EBITDA does not include depreciation and amortization expense. Because we use capital assets, depreciation and amortization expense is a necessary element of our costs and ability to generate profits. Therefore, any measure that excludes depreciation and amortization expense may have material limitations;

· Adjusted EBITDA does not include provision for income taxes. Because the payment of income taxes is a necessary element of our costs, any measure that excludes income tax expense may have material limitations;

· Adjusted EBITDA does not reflect cash expenditures or future requirements for capital expenditures or contractual commitments;

· Adjusted EBITDA does not reflect changes in, or cash requirements for, working capital needs; and

· Adjusted EBITDA does not allow us to analyze the effect of certain recurring and non-recurring items that materially affect our net earnings or loss.

Similarly, Cash Available for Distribution has certain limitations because it accounts for some, but not all, of the above limitations.

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Revenues

Revenues include fee-based revenue and net optimization revenue. Fee-based revenue consists of long-term contracts for storage fees that are generated when we lease storage capacity on a term basis and short-term fees associated with specified injections and withdrawals of natural gas. Optimization revenue results from the purchase of natural gas inventory and its forward sale to future periods through financial and physical energy trading contracts, with our facilities being used to store the inventory between acquisition and disposition of the natural gas inventory.

Revenues for each of the three and ~~six~~nine months ended ~~September~~December 3031, 2015 and 2014 consisted of the following (in thousands):

	Three Months Ended						~~Six~~Nine Months Ended
	September 30,						September 30,
	December 31,						December 31,
	2015			2014			2015			2014
	(unaudited)						(unaudited)
Long-term contract revenue	$	8,~~928~~754		$	1413,~~101~~373		$	1827,~~573~~327		$	5467,~~584~~956
Short-term contract revenue	34,~~724~~473			12,~~532~~255			812,~~341~~814			36,~~803~~059
Fee-based revenue	$	1213,~~652~~227		$	15,~~633~~628		$	2640,~~914~~141		$	5874,~~387~~015
Realized optimization, net	$	56,~~065~~686		$	47,~~458~~013		$	1017,~~379~~065		$	1825,~~231~~244
Unrealized risk management (losses) gains	(~~381~~693		)	~~999~~48,278			(1011,~~712~~405		)	~~(151~~48,127		)
Write-down of inventory	—			(10,500		)	—			(10,500		)
Write-downs of inventory	(600		)	(31,700		)	(600		)	(42,200		)
Optimization revenue, net	$	45,~~684~~393		$	(523,~~043~~591	)	$	~~(333~~5,060	)	$	731,~~580~~171

Changes in revenue in the quarter were primarily attributable to the following:

Long-term contract revenue. LTF revenue for the three months ended ~~September~~December 3031, 2015 decreased by $54.26 million ~~(37%)~~ compared to the three months ended ~~September~~December 3031, 2014 principally as a result of lower fees realized ~~and a weaker Canadian dollar in the current period compared to the same period in fiscal 2015~~. LTF revenue for the ~~six~~nine months ended ~~September~~December 3031, 2015 decreased by $3640.06 million ~~(66%)~~ compared to the ~~six~~nine months ended ~~September~~December 3031, 2014 primarily due to the one-time, early termination payment of $26.0 million received from TransCanada in May 2014. Excluding the impact of this transaction in the prior~~-period~~ ~~transaction~~period, revenues declined by $1014.06 million. This decline was mainly due to lower fees realized for equivalent storage volumes as a result of the ongoing compression of the seasonal spread which reduced revenues by $710.49 million,. ~~combined~~A ~~with a~~ weaker Canadian dollar ~~which~~ reduced revenues at our Canadian facilities by an additional $12.98 million. ~~The erosion of prices charged for LTF services resulted from the ongoing compression of the seasonal spread.~~

Short-term contract revenue. STF revenue for the three months ended ~~September~~December 3031, 2015 increased by $2.2 million ~~(143%)~~ when compared to the three months ended ~~September~~December 3031, 2014. STF revenue for the ~~six~~nine months ended ~~September~~December 3031, 2015 ~~increased~~more bythan doubled to $412.58 million ~~(119%)~~ when compared to the ~~six~~nine months ended ~~September~~December 3031, 2014. ADuring ~~higher~~fiscal ~~volume~~2016, ofwe ~~STF~~increased ~~transactions during~~ the ~~three~~storage ~~and~~capacity ~~six~~allocated ~~months ended September 30, 2015 compared~~ to ~~the~~this ~~volume in the prior periods increased STF~~ revenue strategy. In addition, during the year ended March 31, 2014, certain transactions with lower contract rates were entered into to mitigate withdrawal risk during the winter of fiscal 2014. The effects of ~~this~~lower rates continued into the first quarter of fiscal 2015. The lack of similar transactions in the ~~six~~nine months ended ~~September~~December 3031, 2015 resulted in higher STF revenue when compared to the ~~same~~prior ~~period last~~ year-to-date period.

Optimization Revenue. Optimization activities for the three months ended ~~September~~December 3031, 2015 resulted in a net gain of $45.74 million compared to a ~~loss~~net gain of $523.06 million infor the three months ended ~~September~~December 3031, 2014. Optimization revenue for the ~~six~~nine months ended ~~September~~December 3031, 2015 decreased to ~~a loss of~~ $05.31 million from ~~a net gain of~~ $731.62 million during the ~~six~~nine months ended ~~September~~December 3031, 2014. When evaluating the performance of our optimization business, we focus on our realized optimization margins, excluding the impact of unrealized economic hedging gains and losses and inventory write-downs. Our net optimization revenue includes the impact of unrealized economic hedging gains and losses and inventory write-~~down~~downs, which cause our reported revenue to fluctuate from period to period. The components of optimization revenues are as follows:

Realized Optimization Revenue, net. Net realized optimization revenue for the three months ended September 30, 2015 increased by $0.6 million compared to the three months ended September 30, 2014. Net realized optimization revenue for the six months ended September 30, 2015 decreased by $7.9 million compared to the six months ended September 30, 2014. A reduction of in-the-money settlement of financial hedges combined with lower levels of proprietary inventory principally caused a decrease in revenues from our storage operations for the six months ended September 30, 2015. This was partially offset by higher revenue from 29

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~~our~~Realized ~~marketing~~Optimization ~~business~~Revenue, ~~which~~net. ~~generated~~Net realized optimization revenue offor the three months ended December 31, 2015 decreased by $30.83 million ~~and~~compared to the three months ended December 31, 2014. Net realized optimization revenue for the nine months ended December 31, 2015 decreased by $8.2 million ~~for~~compared to the nine months ended December 31, 2014. During the nine months ended December 31, 2015, lower storage capacity was allocated to this revenue strategy compared to the prior year. Decreased revenues from our storage operations during the nine months ended December 31, 2015 was partially offset by higher revenue from our marketing business. During the three and ~~six~~nine months ended ~~September~~December 3031, 2015, our marketing business generated $3.9 million and $12.1 million of revenues compared to $24.70 million and $610.1 million realized during the three and ~~six~~nine months ended ~~September~~December 3031, 2014. Revenue from the marketing business during the nine months ended December 31, 2015 exceeded last year as a result of an expansion of our residential market in Western Canada as well as our commercial market in Eastern Canada.

Unrealized Risk Management Gains (Losses). Unrealized risk management gains and losses are recorded based on the market value of derivative contracts. For the three and ~~six~~nine months ended ~~September~~December 3031, 2015, unrealized risk management losses resulted from the reversal of gains from previous periods associated with in-the-money contracts that settled in the current period ~~along~~combined with lower values of futures contracts for our storage and marketing businesses.

During the three and ~~six~~nine months ended ~~September~~December 3031, 2015, our marketing business recognized $10.35 million of unrealized risk management gains and $21.49 million of unrealized risk management losses compared to $1.4.5 million in unrealized risk management losses and $50.38 million in unrealized risk management gains during the three and ~~six~~nine months ended ~~September~~December 3031, 2014. ~~Lower~~Larger ~~gains~~year-to-date losses resulted from decreases in the value of futures contracts asdue ato ~~result~~lower ~~of a decline in~~ natural gas prices relative to average contract prices for future months.

Write-~~Down~~Downs of Inventory. Natural gas prices fell during the ~~quarter~~three and nine months ended ~~September~~December 3031, 2015 and 2014. This reduction increased the value of our economic hedges and decreased the value of the proprietary optimization inventory underlying those hedges. With the realization of hedges positioned during the ~~quarter~~three and nine months ended ~~September~~December 3031, ~~2014~~2015 and the positioning of new hedges at lower values in the then future periods, the market value of our inventories became less than the carrying cost. Accordingly, we wrote down our proprietary inventories by $100.56 million infor the three and ~~six~~nine months ended ~~September~~December 3031, 2015, and $31.7 million and $42.2 million during the three and nine months ended December 31, 2014, respectively.

Operating Expenses

Operating expenses for the three and ~~six~~nine months ended ~~September~~December 3031, 2015 and 2014 consisted of the following (in thousands):

Three Months Ended

~~Six~~Nine Months Ended

September 30,

December 31,

2015

2014

2015

2014

(unaudited)

Lease costs and property taxes

3,~~210~~332

4,~~088~~146

69,~~439~~771

711,~~781~~928

Fuel and electricity

1,~~735~~714

51,~~028~~745

35,~~582~~296

810,~~553~~298

Salaries and benefits

1,~~373~~345

1,~~364~~472

24,~~800~~145

34,~~039~~511

Maintenance

~~899~~564

1,~~006~~344

12,~~447~~011

23,~~058~~403

General operating costs

~~1,409~~754

~~576~~727

23,~~315~~069

12,~~584~~311

Total operating expenses

87,~~626~~709

129,~~062~~434

1624,~~583~~292

2332,~~015~~451

Operating expenses for the three months ended ~~September~~December 3031, 2015 decreased by $31.47 million ~~(28%)~~ compared to the three months ended ~~September~~December 3031, 2014. Operating expenses for the ~~six~~nine months ended ~~September~~December 3031, 2015 decreased by $68.42 million ~~(28%)~~ compared to the ~~six~~nine months ended ~~September~~December 3031, 2014. Reductions in operating expenses for the ~~three~~nine ~~and six~~ months ended ~~September~~December 3031, 2015 were principally the result of lower injections of gas into storage which ~~resulted in~~ reduced fuel and electricity ~~costs~~. ~~Additionally,~~Leased ~~the~~storage ~~Canadian~~capacity ~~dollar~~was ~~depreciated~~reduced ~~approximately~~by ~~15%~~5.6 ~~compared~~Bcf toat ~~the~~April 1, ~~U.S.~~2015, ~~dollar~~resulting in ~~the~~a ~~current~~decrease ~~period. A weaker Canadian dollar resulted~~ in ~~expenses~~lease ~~associated~~costs ~~with our Canadian facility being lower by $0.5 million and $1.0 million~~ for both the three and ~~six~~nine months ended ~~September~~December 3031, 2015. ~~compared~~Maintenance tocosts in the ~~three~~prior ~~and~~period ~~six~~were ~~months~~higher ~~ended~~because ~~September 30,~~heavy ~~2014.~~equipment Ausage ~~decline~~during inthe ~~lease~~winter ~~costs~~of ~~due~~fiscal to2014 ~~leased~~required ~~storage~~significantly ~~capacity~~higher ~~being~~equipment ~~reduced~~repairs bythroughout 5fiscal 2015.6 ~~Bcf~~In ~~since April 1~~addition, ~~2015~~a ~~also~~weaker ~~contributed~~Canadian todollar reduced expenses. ~~These~~associated ~~reductions~~with ~~were~~our ~~partially~~Canadian ~~offset~~facilities by ~~higher~~$0.4 ~~emission~~million ~~offset costs~~ and ~~costs~~$1.3 ofmillion ~~leasing~~for ~~additional~~the ~~cushion~~three toand ~~manage~~nine ~~our~~months ~~temporary~~ended ~~pressure~~December 31, ~~support requirements~~2015.

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General and Administrative Expenses

General and administrative expenses for the three and ~~six~~nine months ended ~~September~~December 3031, 2015 and 2014 consisted of the following (in thousands):

Three Months Ended

~~Six~~Nine Months Ended

September 30,

December 31,

2015

2014

2015

2014

(unaudited)

Compensation costs

32,~~686~~869

~~2,683~~695

710,~~460~~329

~~8,909~~$

9,604

General costs, including office and information technology costs

~~907~~934

1,~~137~~108

12,~~912~~846

23,~~290~~398

Legal, audit and regulatory costs

21,~~137~~915

2,~~385~~430

810,~~588~~503

57,~~080~~511

Total general and administrative expenses

65,~~730~~718

64,~~205~~233

1723,~~960~~678

1620,~~279~~513

General and administrative expenses for the three months ended ~~September~~December 3031, 2015 increased by $01.5 million ~~(8%)~~ compared to the three months ended ~~September~~December 3031, 2014. General and administrative expenses for the ~~six~~nine months ended ~~September~~December 3031, 2015 increased by $13.72 million ~~(10%)~~ compared to the ~~six~~nine months ended ~~September~~December 3031, 2014. ~~The~~Increased ~~increase~~incentive ~~for~~compensation accruals in the three and nine months ended ~~September~~December 3031, 2015 ~~was~~were ~~primarily due to reductions in incentive compensation accruals recorded in fiscal 2015 which was~~ partially offset by ~~reductions of $0.8 million in response to~~ the impact of a weaker Canadian dollar. ~~General~~Legal, audit and ~~administrative~~regulatory costs for the ~~six~~three and nine months ended ~~September~~December 3031, 2015 ~~increased~~included ~~principally~~$0.2 asmillion ~~a result of higher legal~~ and ~~consulting~~$4.3 ~~costs~~million ~~incurred~~of expenses related to the Transaction. Excluding these costs, total general and administrative expenses for the ~~six~~three and nine months ended ~~September~~December 3031, 2015 would have been $135.85 million. ~~The~~and ~~increased~~$19.4 ~~costs~~million, ~~were~~respectively. ~~partially~~The ~~offset by lower~~ overall ~~compensation~~increase ~~costs~~for ~~due~~the tonine ~~reduced~~months ~~staffing~~ended ~~levels~~December 31, ~~and~~2015 ~~the~~was ~~impact~~partially ofoffset by a ~~weaker~~reduction ~~Canadian dollar which resulted~~ in ~~expenses~~costs ~~being~~of ~~lower by~~ $12.97 million ~~compared~~resulting tofrom the ~~same~~impact ~~period~~of ina ~~fiscal~~weaker ~~2015~~Canadian dollar.

Depreciation and Amortization Expense

Depreciation and amortization expense for the three and ~~six~~nine months ended ~~September~~December 3031, 2015 decreased by $124.2 4 million and $4064.4 8 million, respectively, compared to the three and ~~six~~nine months ended ~~September~~December 3031, 2014. Depreciation expense for the three and ~~six~~nine months ended ~~September~~December 3031, 2015 included $69.4 1 million and $817.6 7 million, respectively, related to migration of cushion gas at our Canadian facilities, compared to $531.7 2 million and $3364.6 7 million for the three and ~~six~~nine months ended ~~September~~December 3031, 2014. The provisions for cushion gas migration represent our estimated costs associated with proprietary cushion gas that no longer provides effective pressure support.

Amortization of intangible assets during the ~~six~~nine months ended ~~September~~December 3031, 2014 included $11.7 million of amortization related to the termination of the prior storage agreement with TransCanada and the establishment of a new contract. The recorded amortization charges reflected the revised pattern of cash flows associated with this customer relationship.

30Impairment of Goodwill

During the three and nine months ended December 31, 2014, we concluded that a number of factors, including the continued narrow seasonal spread environment, combined with the significant reduction in natural gas price volatility, and a strong decline in our unit price were impairment indicators. As a result of this determination, we performed an impairment test and concluded that the remaining balance of our goodwill was fully impaired. As a result, an impairment charge of $245.6 million was recorded.

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Interest Expense

Interest expense for the three and nine months ended ~~September~~December 3031, 2015 and 2014 consisted of the following (in thousands):

	Three Months Ended				~~Six~~Nine Months Ended
	September 30,				September 30,
	December 31,				December 31,
	2015		2014		2015		2014
	(unaudited)				(unaudited)
Interest on Senior Notes	$	9,~~344~~343	$	9,344	$	1828,~~688~~031	$	1828,~~687~~031
Interest on revolving credit facilities	2,379		2,324		4,790		4,303
Interest on credit facilities	2,806		2,774		7,596		7,077
Amortization of deferred financing costs	~~958~~1,009		913		12,~~872~~881		12,~~825~~738
Other interest	~~284~~107		~~154~~151		~~356~~463		~~232~~383
Total interest expenses	$	1213,~~965~~265	$	1213,~~735~~182	$	2538,~~706~~971	$	2538,~~047~~229

Interest expense for the three and ~~six~~nine months ended ~~September~~December 3031, 2015 increased by $0.21 million ~~(2%)~~ and $0.7 million, ~~(3%)~~respectively, compared to the same periods in fiscal 2015. ~~mainly~~Higher asaverage ainterest ~~result~~rates ofwere apartially ~~higher~~offset ~~average~~by ~~interest~~the ~~rate~~impacts onof ~~our~~lower ~~revolving~~average balances of our credit facilities compared to the level of drawings during the three and nine months ended December 31, 2014.

Income Taxes

Income tax benefit for the three and ~~six~~nine months ended ~~September~~December 3031, 2015 decreased by $010.9 million and $1324.76 million compared to the three and ~~six~~nine months ended ~~September~~December 3031, 2014. ~~The~~These ~~change~~changes ~~for~~were ~~three months ended was~~ primarily due to ~~lower~~a ~~recognized~~reduction in losses in certain taxable entities. ~~Lower~~An ~~income~~increase ~~tax~~in ~~benefit~~Canadian ~~for~~provincial ~~the~~income ~~six~~tax ~~months~~rates ~~ended~~which ~~September 30,~~impacted ~~2015 was primarily due to lower recognized losses in~~ certain Canadian taxable entities ~~and~~also ancontributed ~~increase~~to inlower ~~Canadian provincial income~~ tax ~~rates~~benefit ~~which~~for ~~impacted~~the ~~certain~~nine ~~Canadian~~months ~~taxable~~ended ~~entities~~December 31, 2015.

Liquidity and Capital Resources

Sources and Uses of Liquidity

As discussed above, on June 14, 2015 the Company agreed to be acquired by Brookfield. As part of the Merger Agreement associated with the Transaction, Brookfield agreed to lend the Company up to $50.0 million to support ongoing operations of the business. The definitive agreement associated with this commitment was signed on July 28, 2015 and is discussed further in Note 3 to the Company’s financial statements.

Also as discussed in Note 3, when the Company’s FCCR is below 1.1 to 1.0 times, as defined in the Company’s Credit Agreement on a trailing twelve month basis, the Company is unable to borrow the last 15% of availability under its Credit Agreement without triggering an event of default. At ~~September~~December 3031, 2015 the Company’s FCCR was 0.6 to 1.0 and therefore, the Company continued to be subject to this limitation. Based on the Company’s estimates of its cash flows coupled with the availability of borrowings under the agreement with Brookfield, the Company believes that it has adequate cash availability to support its operations for the next twelve months.

As of ~~November~~February 21, ~~2015~~2016, the Company’s availability under its Credit Agreement was $3931.4 million, including reductions resulting from its FCCR falling below 1.1 to 1.0 times. In addition, the remaining capacity under the Company’s Short-term Credit Facility with Brookfield amounted to $3029.04 million.

OnAs ~~November 4,~~noted ~~2015~~above, the Company’s ~~Board~~is presently in the process of ~~Directors~~negotiating ~~continued~~an ~~the~~amendment ~~suspension~~and extension of ~~Niska~~its ~~Partners’~~existing ~~quarterly~~$400.0 ~~distribution~~million Credit Agreement which if completed will, among other things, permit the Merger Agreement to ~~common~~proceed ~~unitholders~~without ~~for~~triggering a change-of-control provision the ~~second~~Credit ~~quarter~~Agreement and extend the term of ~~fiscal~~the Credit Agreement beyond June 29, 2016 to September 30, 2016, or to December 31, 2016, if the Transaction closes on or before September 16, 2016. It is likely that such amendment and extension, if completed, will result in ~~compliance~~a ~~with~~reduction in the ~~Company’s~~maximum ~~commitment~~availability under the $400.0 million Credit Agreement. Niska Partners does not anticipate that any such reduction will impair its ability to ~~make~~operate ~~distributions~~its ~~until~~business to a material extent. The Company is highly confident that the ~~earlier~~amendment and extension will be completed. Our estimates of future cash flows, continuing availability of the ~~date~~remainder of ~~closing~~the orShort-term ~~termination~~Credit Facility provided by Brookfield, and the amendment and further extensions of ~~its~~the ~~Merger~~credit ~~Agreement~~agreement ~~with~~are ~~Brookfield~~expected to provide adequate funds to support the business for the next twelve months. However, in the event that an extension of the agreement is not consummated, the Company will be required to raise additional funds in order to repay the Credit

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Agreement at its maturity in June 2016. If the extension of the agreement is consummated as contemplated, the Company will be required to further extend the maturity date or raise additional funds to repay the Credit Agreement at its final maturity date. We can provide no assurance that we will be able to further extend the maturity date or raise additional funds to repay the Credit Agreement upon its revised maturity.

On February 3, 2016, the Company’s Board of Directors continued the suspension of Niska Partners’ quarterly distribution to common unitholders for the third quarter of fiscal 2016 in compliance with the Company’s commitment not to make distributions until the earlier of the date of closing or termination of its Merger Agreement with Brookfield.

Cash Flows from Operations and Investing Activities

The following table summarizes our sources and uses of cash for the ~~six~~nine months ended ~~September~~December 3031, 2015 and 2014, respectively (in thousands):

Operating Activities:

	Six Months Ended
	Nine Months Ended
	September 30,
	December 31,
	2015			2014
	(unaudited)
Net earnings (loss)	$	(5778,~~016~~008	)	$	(47307,~~803~~426	)
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Adjustments to reconcile net earnings (loss) to net
Unrealized foreign exchange losses (gains)	171			(66		)
cash provided by (used in) operating activities:
Deferred income tax benefit	(3,738		)	(16,249		)
Unrealized foreign exchange losses	329			260
Unrealized risk management losses	10,712			151
Deferred income tax benefit	(9,009		)	(31,938		)
Depreciation and amortization	25,539			65,978
Unrealized risk management losses (gains)	11,405			(48,127		)
Deferred charges amortization	1,872			1,825
Depreciation and amortization	42,931			107,730
Loss (gain) on disposal of assets	240			(14		)
Amortization of deferred financing costs	2,881			2,738
Non-cash compensation	713			1,243
Losses (gains) on disposals of assets	268			(64		)
Write-down of inventory	—			10,500
Non-cash compensation	1,273			1,687
Changes in non-cash working capital	54,054			(122,901		)
Impairment of goodwill	—			245,604
Net cash provided by (used in) operating activities	32,547			(107,336		)
Write-downs of inventory	600			42,200
Net cash used in investing activities	(881		)	(1,684		)
Changes in non-cash working capital	61,667			(105,338		)
Net cash (used in) provided by financing activities	(24,407		)	108,762
Net cash provided by (used in) operating activities	34,337			(92,674		)
Effect of translation of foreign currency on cash and cash equivalents	(129		)	(112		)
Net cash used in investing activities	(2,288		)	(5,452		)
Net Increase (Decrease) in Cash and Cash Equivalents	$	7,130		$	(370	)
Net cash (used in) provided by financing activities	(37,543		)	99,045
Effect of translation of foreign currency on cash and cash equivalents	(156		)	(243		)
Net (Decrease) Increase in Cash and Cash Equivalents	$	(5,650	)	$	676

The variability in net cash provided by operating activities is primarily due to (1) changes in market conditions that exist during any given fiscal period, which impacts the margins earned under each of our fee-based and optimization activities; and (2) market conditions at the end of any given fiscal period, which impacts our decision to sell significant volumes of inventory or hold them over a fiscal period end. When we purchase and store natural gas, we borrow under our credit facilities to pay for it, which negatively impacts operating cash flow. Cash flow from operating activities increases when we collect the cash from the sale of inventories.

Cash provided by operating activities during the six months ended September 30, 2015 was $32.5 million compared to a use of $107.3 million during the same period in fiscal 2015. The higher amount of cash provided by operating activities was principally due to our decision to hold proprietary inventories over the end of fiscal 2015, a portion of which were sold during the six months ended September 30, 2015. Inventory sales were partially offset by lower profitability during the first half of fiscal 2016 compared to the same period last year. During the six months ended September 30, 2014, cash flows from operating activities were materially impacted by significant proprietary inventory purchases as well as the purchase of natural gas for our retail entities in a falling market which required us to post higher margin deposits.33

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Cash provided by operating activities during the nine months ended December 31, 2015 was $34.3 million compared to a use of $92.7 million during the same period in fiscal 2015. The higher amount of cash provided by operating activities was principally due to our decision to hold proprietary inventories over the end of fiscal 2015, a portion of which were sold during the nine months ended December 31, 2015. Excluding the impacts of non-cash gains, losses and expenses, the impact of lower profitability during the nine months ended December 31, 2015 compared to the same period last year partially offset the proceeds received from the sale of inventory. During the nine months ended December 31, 2014, cash flows from operating activities were materially impacted by significant proprietary inventory purchases as well as the purchase of natural gas for our retail entities in a falling market which required us to post higher margin deposits.

Net changes in non-cash working capital consisted of the following (in thousands):

	Six Months Ended
	Nine Months Ended
	September 30,
	December 31,
	2015			2014
	(unaudited)
Margin deposits	$	(53,~~390~~558	)	$	~~(25~~29,~~360~~434	)
Trade receivables	~~1,245~~337			42,~~093~~769
Accrued receivables	2113,~~977~~523			~~122~~112,~~578~~573
Natural gas inventory	2554,~~178~~681			(~~209~~176,~~331~~425		)
Prepaid expenses and other current assets	~~711~~754			1(3,~~148~~103		)
Other assets	8067			—(437		)
Trade payables	(15486		)	(~~278~~299		)
Accrued liabilities	10(4,~~319~~247		)	(2767,~~010~~187		)
Deferred revenue	47(6,430		)	11(2,~~904~~029		)
Other long-term liabilities	(9890		)	(~~645~~634		)
Total	$	5461,~~054~~667		$	(~~122~~105,~~901~~338	)

As noted above, net changes in non-cash working capital can fluctuate significantly from period to period and is primarily affected by timing differences between the purchase and sale of natural gas inventory, including margin requirements and cash settlement on related risk management instruments, and the timing of collections from our customers.

Investing Activities

Substantially all of our cash used for investing activities consisted of capital expenditures in each of the ~~six~~nine months ended ~~September~~December 3031, 2015 and 2014. Our capital expenditures in each ~~six~~nine month period consisted of the following (in thousands):

	Six Months Ended
	Nine Months Ended
	September 30,
	December 31,
	2015			2014
	(unaudited)
Maintenance capital	$	~~810~~1,944		$	13,~~460~~240
Expansion capital	7582			~~633~~510
Total capital expenditures	~~885~~2,026			23,~~093~~750
Changes in accrued capital expenditures	(4262		)	~~(395~~1,716		)
Proceeds from sale of assets	—			(14		)
Net cash used in investing activities	$	~~881~~2,288		$	15,~~684~~452

Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives. Expansion capital expenditures are investments that serve to increase operating income over the long term through greater capacity or improved efficiency in Niska Partners’s operations, whether through construction or acquisition.

Under our current plan, we expect to spend between $3.0 million to $5.0 million in fiscal 2016 for maintenance capital to maintain the integrity of our storage facilities and ensure the reliable injection, storage and withdrawal of natural gas for our customers. Expansion capital for fiscal 2016 is expected to be less than $1.0 million.34

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Under our current plan, we expect to spend between $3.0 million to $4.0 million in fiscal 2016 for maintenance capital to maintain the integrity of our storage facilities and ensure the reliable injection, storage and withdrawal of natural gas for our customers. Expansion capital for fiscal 2016 is expected to be less than $1.0 million.

Regulation

Adoption of the Clean Power Plan Regulations

In August 2015, the U.S. Environmental Protection Agency (the “EPA”) issued its final Clean Power Plan rules that establish carbon pollution standards for power plants, called CO2 emission performance rates. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the Clean Power Plan. The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour or mass-based tonnage) limits for CO2.

The state plans are due in September 2016, subject to potential extensions of up to two years for final plan submission. The compliance period begins in 2022, and emission reductions will be phased in up to 2030. The EPA also proposed a federal compliance plan to implement the Clean Power Plan in the event that an approvable state plan is not submitted to the EPA. Judicial challenges have already been filed, which may result in a stay of the implementation of the rules. We are currently assessing the impact of the Clean Power Plan on the Company.

Final Rule for the Waters of the United States

In May 2015, the EPA issued a final rule that sets forth changes to its definition of “waters of the United States” under the Clean Water Act (“CWA”). In August 2015, a federal district judge in North Dakota enjoined implementation of the rule in 13 states. Federal district court judges in West Virginia and Georgia have denied similar motions for injunctions, while district court judges in other jurisdictions have stayed their cases until the Judicial Panel on Multidistrict Litigation ruled on whether to consolidate all of the district court cases in a single court. In October 2015, the Judicial Panel on Multidistrict Litigation declined to consolidate the various district court cases in a single court. In addition, in October 2015 the Sixth Circuit issued a nationwide stay of the rule until it determines whether it has jurisdiction over the petitions for review brought in the federal appellate courts. It remains to be seen how the various proceedings in more than a dozen federal district courts and possibly in the Sixth Circuit will affect the substance of the final rule and its implementation. Any expansion to CWA jurisdiction could impose additional permitting obligations on our operations, which may adversely affect any development or expansion we may plan to undertake.

New National Ambient Air Quality Standards for Ozone

The EPA on October 1, 2015 finalized both the 8-hour primary and secondary air quality standards for ground level ozone to 70 parts per billion from 75 parts per billion. ~~States~~The ~~must~~EPA will now evaluate ~~their~~the states’ attainment status and the states must determine whether additional control measures are needed in order to meet this standard. If states where we operate ~~determine that they~~ are not in attainment with this new standard, they may enact additional regulations beyond those currently contemplated to further control emissions of volatile organic compounds and nitrogen oxides from certain sources, which could apply to our operations and could result in increased compliance costs. Niska Partners cannot predict the financial impact of the revised ozone standards at this time.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

There were no material changes to the disclosures made in our Annual Report on Form 10-K for the fiscal year ended March 31, 2015 regarding this matter.

At ~~September~~December 3031, 2015, 4234.93 Bcf of natural gas inventory was economically hedged, representing 98.08% of our total current inventory. Because inventory is recorded at the lower of cost or market, not fair value, if the price of natural gas increased by $1.00 per Mcf the value of inventory would increase by $4334.87 million, the fair value or mark-to-market value of our economic hedges would decrease by $4234.93 million, and the impact due to the non-economically hedged position would be $0.94 million. Similarly, if the price of natural gas declined by $1.00 per Mcf, the value of inventory would decrease by $4334.87 million while the fair value of our economic hedges would increase by $4234.93 million and the impact due to the non-economically hedged position would be $0.94 million.

At ~~September~~December 3031, 2015, we were exposed to interest rate risk resulting from the variable rates associated with our $400 million Credit Agreement, on which a balance of $~~153~~140.57 million was drawn. The interest rate applicable on the credit facilities is subject to change based on certain ratios and the magnitude of our drawings on the facility. At ~~September~~December 3031, 2015, a one percent increase or decrease in interest rates would have an annualized impact of approximately $1.54 million on our interest expense.

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

Our principal executive officer (“CEO”) and principal financial officer (“CFO”) undertook an evaluation of our disclosure controls and procedures as of the end of the period covered by this report. The CEO and the CFO have concluded that our controls and procedures were effective as of ~~September~~December 3031, 2015. For purposes of this section, the term “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. However, a controls system cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

For information on legal proceedings, see Part I, Item 1, Financial Statements, Note 2, “Commitments and Contingencies” in the Notes to Unaudited Consolidated Financial Statements included in this quarterly report, which is incorporated into this item by reference.

Item 1A. Risk Factors

Our business faces many risks. Any of the risks discussed in this Quarterly Report or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. For a detailed discussion of the risk factors that should be understood by any investor contemplating investment in our securities, please refer to Part I—Item 1A—Risk Factors in our Annual Report and Part II — Item 1A — Risk Factors in our Q1 Quarterly Report. There have been no material changes to the risk factors set forth in our Annual Report, other than those updated by our Q1 Quarterly Report.

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Item 6. Exhibits

Exhibit Number		~~Description~~	Description
2.1	—	Agreement and Plan of Merger and Membership Interest Transfer Agreement, dated as of June 14, 2015, by and among Niska Gas Storage Partners LLC, Niska Gas Storage Management LLC, Niska Sponsor Holdings Coöperatief U.A., Swan Holdings LP and Swan Merger Sub LLC (incorporated by reference to Exhibit 2.1 of the Company’s current report on Form 8-K filed on June 18, 2015)—	Agreement and Plan of Merger and Membership Interest Transfer Agreement, dated as of June 14, 2015, by and among Niska Gas Storage Partners LLC, Niska Gas Storage Management LLC, Niska Sponsor Holdings Coöperatief U.A., Swan Holdings LP and Swan Merger Sub LLC (incorporated by reference to Exhibit 2.1 of the Company’s current report on Form 8-K filed on June 18, 2015)
3.1	—	Certificate of Formation of Niska Gas Storage Partners LLC (incorporated by reference to Exhibit 3.1 of Amendment to the Company’s registration statement on Form S-1 (Registration No. 333-165007) filed on April 15, 2010).—	Certificate of Formation of Niska Gas Storage Partners LLC (incorporated by reference to Exhibit 3.1 of Amendment to the Company’s registration statement on Form S-1 (Registration No. 333-165007) filed on April 15, 2010).
3.2	—	Second Amended and Restated Operating Agreement of Niska Gas Storage Partners LLC dated April 2, 2013 (incorporated by reference to Exhibit 3.2 of the Company’s current report on Form 8-K filed on April 3, 2013).—	Second Amended and Restated Operating Agreement of Niska Gas Storage Partners LLC dated April 2, 2013 (incorporated by reference to Exhibit 3.2 of the Company’s current report on Form 8-K filed on April 3, 2013).
10.1	—	Credit Agreement, dated as of July 28, 2015, by and between Niska Gas Storage Partners LLC, as the borrower, Swan Finance LP, as Administrative Agent and Collateral Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s current report on Form 8-K filed on July 31, 2015)
31.1*		—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15D-14(A) under the Securities Exchange Act of 1934.
10.2	—	Separation Agreement and General Release of Claims, executed on July 31, 2015, between Bruce D. Davis, Jr., Niska Gas Storage Partners LLC, Niska Gas Transport Inc. and Niska Holdings L.P. (incorporated by reference to Exhibit 10.1 of the Company’s current report on Form 8-K filed on August 4, 2015)
31.2*		—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15D-14(A) under the Securities Exchange Act of 1934.
10.3	—	Agreement Regarding Niska Gas Storage Partners LLC Phantom Unit Performance Plan Awards, executed on July 31, 2015, between Bruce D. Davis, Jr. and Niska Gas Storage Partners LLC (incorporated by reference to Exhibit 10.2 of the Company’s current report on Form 8-K filed on August 4, 2015)
32.1**		—	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
31.1*	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15D-14(A) under the Securities Exchange Act of 1934.
32.2**		—	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
31.2*	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15D-14(A) under the Securities Exchange Act of 1934.
101.INS*		—	XBRL Instance Document.
32.1**	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.SCH*		—	XBRL Taxonomy Extension Schema Document.
32.2**	—	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.CAL*		—	XBRL Taxonomy Extension Calculation Linkbase Document.
101.INS*	—	XBRL Instance Document.
101.LAB*		—	XBRL Taxonomy Extension Label Linkbase Document.
101.SCH*	—	XBRL Taxonomy Extension Schema Document.
101.PRE*		—	XBRL Taxonomy Extension Presentation Linkbase Document.
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*		—	Taxonomy Extension Definition Linkbase Document.
101.LAB*	—	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF*	—	Taxonomy Extension Definition Linkbase Document.

* Filed herewith.

** Furnished herewith.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	NISKA GAS STORAGE PARTNERS LLC
Date: November 6, 2015	By:	/s/ VANCE E. POWERS
Date: February 9, 2016	By:	/s/ VANCE E. POWERS
		Vance E. Powers
		Chief Financial Officer
		(Principal Accounting Officer)

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Filing Compare · Niska Gas Storage Partners LLC