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 December 31, 2013

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)

1001 Fannin Street, Suite 2500 Houston, TX (Address of principal executive offices)		77002 (Zip Code)

(281) 404-1890

(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 January 30, 2014, there were 35,301,200 Common Units outstanding.

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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						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012

Revenues:
Fee-based revenue	$	30,484		$	41,255		$	95,151		$	119,314
Optimization, net	(4,637		)	32,576			24,746			(23,725		)
	25,847			73,831			119,897			95,589
Expenses (income):
Operating	8,426			8,330			27,747			25,250
General and administrative	9,361			8,417			30,164			26,332
Depreciation and amortization	10,518			14,831			31,149			39,896
Interest	17,114			17,279			49,718			50,459
Loss on disposal of assets	—			15,072			—			15,072
Loss on extinguishment of debt	—			—			—			599
Foreign exchange losses (gains)	160			22			606			(314		)
Other (income) expense	(14		)	3			360			(182		)

EARNINGS (LOSS) BEFORE INCOME TAXES	(19,718		)	9,877			(19,847		)	(61,523		)
Income tax benefit	(6,309		)	(542		)	(6,561		)	(19,200		)

NET EARNINGS (LOSS) AND COMPREHENSIVE INCOME (LOSS)	$	(13,409	)	$	10,419		$	(13,286	)	$	(42,323	)

Net earnings (loss) allocated to:

Managing Member	$	(260	)	$	206		$	(256	)	$	(838	)
Common unitholders	$	(13,149	)	$	5,158		$	(13,030	)	$	(20,951	)
Subordinated unitholder (Notes 1 and 6)	$	—		$	5,055		$	—		$	(20,534	)

Earnings (loss) per unit allocated to common unitholders
- basic and diluted	$	(0.37	)	$	0.15		$	(0.37	)	$	(0.61	)

Earnings (loss) per unit allocated to subordinated unitholders
- basic and diluted (Notes 1 and 6)	$	—		$	0.15		$	—		$	(0.61	)

(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)

	December 31,		March 31,
	2013		2013
ASSETS
Current assets
Cash and cash equivalents	$	9,172	$	10,610
Margin deposits	53,658		18,474
Trade receivables	3,837		2,702
Accrued receivables	63,930		106,726
Natural gas inventory	182,459		83,416
Prepaid expenses and other current assets	3,489		4,688
Short-term risk management assets	16,947		21,159
	333,492		247,775
Long-term assets
Property, plant and equipment, net of accumulated depreciation	898,271		918,061
Goodwill	245,604		245,604
Long-term natural gas inventory	15,264		15,264
Intangible assets, net of accumulated amortization	68,381		73,998
Deferred charges, net of accumulated amortization	11,914		14,420
Other assets	2,643		2,677
Long-term risk management assets	6,654		6,593
	1,248,731		1,276,617
TOTAL	$	1,582,223	$	1,524,392

LIABILITIES AND MEMBERS’ EQUITY
Current liabilities
Revolving credit facility	$	127,000	$	65,000
Current portion of obligations under capital lease	1,289		1,259
Trade payables	785		1,048
Current portion of deferred taxes	7,743		14,303
Deferred revenue	887		568
Accrued liabilities	65,974		39,840
Short-term risk management liabilities	37,492		20,005
	241,170		142,023
Long-term liabilities
Long-term risk management liabilities	5,384		4,574
Asset retirement obligations	1,998		2,007
Other long-term liabilities	1,394		1,461
Deferred income taxes	121,003		120,935
Obligations under capital lease	11,255		12,225
Long-term debt	643,790		643,790
	1,025,994		927,015
Members’ equity
Common units	281,534		321,642
Subordinated units (Notes 1 and 6)	—		265,877
Managing Member’s interest	274,695		9,858
	556,229		597,377
Commitments and contingencies (Note 2)
TOTAL	$	1,582,223	$	1,524,392

(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)

	Nine Months Ended
	December 31,
	2013			2012

Operating Activities
Net loss	$	(13,286	)	$	(42,323	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Unrealized foreign exchange losses	830			30
Deferred income tax benefit	(6,561		)	(19,222		)
Unrealized risk management losses	22,447			37,739
Depreciation and amortization	31,149			39,896
Deferred charges amortization	2,506			2,577
Loss on disposal of assets	—			15,072
Loss on extinguishment of debt	—			599
Write-down of inventory	—			22,281
Changes in non-cash working capital	(67,961		)	32,416
Net cash (used in) provided by operating activities	(30,876		)	89,065

Investing Activities
Property, plant and equipment expenditures	(1,662		)	(29,244		)
Purchase of customer contracts	(2,007		)	—
Proceeds on sale of assets	—			2,200
Net cash used in investing activities	(3,669		)	(27,044		)

Financing Activities
Proceeds from revolver drawings	452,000			281,948
Revolver payments	(390,000		)	(307,948		)
Payment of deferred financing costs	—			(3,248		)
Proceeds from obligations under capital lease	—			947
Repayments of obligations under capital lease	(941		)	(408		)
Unit issuance costs	(100		)	—
Distributions to unitholders	(27,631		)	(35,043		)
Net cash provided by (used in) financing activities	33,328			(63,752		)

Effect of translation on foreign currency cash and cash equivalents	(221		)	49
Net decrease in cash and cash equivalents	(1,438		)	(1,682		)
Cash and cash equivalents, beginning of period	10,610			13,342
Cash and cash equivalents, end of period	$	9,172		$	11,660

(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			Subordinated			Member
	Units			Units			Interest			Total

Balance, April 1, 2012	$	391,585		$	287,105		$	11,700		$	690,390

Net loss	(20,951		)	(20,534		)	(838		)	(42,323		)

Distributions to unitholders	(35,835		)	370			(717		)	(36,182		)

Balance, December 31, 2012	$	334,799		$	266,941		$	10,145		$	611,885

Balance, April 1, 2013	$	321,642		$	265,877		$	9,858		$	597,377

Cancellation of subordinated units	—			(265,877		)	265,877			—

Net loss	(13,030		)	—			(256		)	(13,286		)

Distributions to unitholders	(38,938		)	—			(784		)	(39,722		)

Issuance of common units	11,860			—			—			11,860

Balance, December 31, 2013	$	281,534		$	—		$	274,695		$	556,229

(See Notes to Unaudited Consolidated Financial Statements)

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements

(Tabular amounts expressed in thousands of U.S. dollars 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/or 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 its own proprietary gas purchases.

On April 2, 2013, Niska Partners completed an equity restructuring with 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”). In the restructuring, all of the Company’s 33.8 million subordinated units and previous incentive distribution rights (all of which were owned by the Carlyle/Riverstone Funds) were combined into and restructured as a new class of incentive distribution rights (“new IDRs”). The equity restructuring, which did not require any further consents or approvals, was effective as of the same day. The transaction was unanimously approved by the Company’s Board of Directors on the unanimous approval and recommendation of its Conflicts Committee, which is composed solely of independent directors.

The restructuring permanently eliminated all of the Company’s subordinated units and previous incentive distribution rights in return for the new IDRs. Prior to completion of the restructuring, the Company would have been required to pay the full minimum quarterly distribution of $0.35 per unit on the subordinated units (requiring additional distributions of approximately $12 million per quarter) prior to increasing the quarterly distribution on common units. Quarterly distributions on the subordinated units had not been paid since the quarter ended September 30, 2011.

The new IDRs entitle the Carlyle/Riverstone Funds to receive 48% of any quarterly cash distributions after Niska Partners’ common unit holders have received the full minimum quarterly distribution ($0.35 per unit) for each quarter plus any arrearages from prior quarters (of which there are currently none). The previous incentive distribution rights entitled the Carlyle/Riverstone Funds to receive increasing percentages (ranging from 13% to 48%) of incremental cash distributions after the unit holders (both common and subordinated) exceeded quarterly distributions ranging from $0.4025 per unit to $0.5250 per unit. In addition, for a period of five years, and provided that the Carlyle/Riverstone Funds continue to own a majority of both the managing member and the new IDRs, the Carlyle/Riverstone Funds will be deemed to own 33.8 million “Notional Subordinated Units” in connection with votes to remove and replace the managing member. These Notional Subordinated Units are not entitled to distributions, but preserve the Carlyle/Riverstone Fund’s voting rights with respect to removal of the managing member.

At December 31, 2013, Niska Partners had 35,301,200 common units outstanding. Of this amount, 17,801,200 common units are owned by the Carlyle/Riverstone Funds, along with a 1.94% Managing Member’s interest in the Company and all of the Company’s new IDRs. Including all of the common units owned by the Carlyle/Riverstone Funds, along with the 1.94% Managing Member’s interest, the Carlyle/Riverstone Funds have a 51.39% ownership interest in the Company excluding the new IDRs, which are a variable interest. The remaining 17,500,000 common units, representing a 48.61% ownership interest in the Company excluding the new 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, 2013.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

1. Organization and 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, 2013 which is derived from audited financial statements, include all adjustments necessary to present fairly Niska Partners’ financial position as of December 31, 2013, the results of Niska Partners’ operations for the three and nine months ended December 31, 2013 and 2012, along with its cash flows for the nine months ended December 31, 2013 and 2012. The results of operations for the three and nine months ended December 31, 2013 are not necessarily representative of the results to be expected for the full fiscal year ending March 31, 2014. 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 Securities and Exchange Commission (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, 2013.

2. Commitments and Contingencies

Commitments

Niska Partners has entered into non-cancelable operating leases for 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 October 2014 and August 2056 and require the payment of taxes, insurance and maintenance by the lessee.

Contingencies

Niska Partners and its subsidiaries are subject to various legal proceedings and actions arising in the normal course of business. While the outcome of such legal proceedings and actions cannot be predicted with certainty, it is the view of management that the resolution of such proceedings and actions will not have a material impact on Niska Partners’ unaudited consolidated financial position or results of operations.

3. Debt

Niska Partners’ debt obligations consist of the following:

	December 31,			March 31,
	2013			2013

Senior Notes due 2018	$	643,790		$	643,790
Revolving credit facility	127,000			65,000
Total	770,790			708,790
Less portion classified as current	(127,000		)	(65,000		)
	$	643,790		$	643,790

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

3. Debt (continued)

Senior Notes

Interest on the Senior Notes is payable semi-annually on March 15 and September 15 at a rate of 8.875% per annum. The Senior Notes will mature on March 15, 2018. No principal payments on the Senior Notes are required prior to maturity except in certain instances of default. As at December 31, 2013, the estimated fair value of the Senior Notes was $665.3 million (March 31, 2013 - $669.5 million).

The indenture governing the Senior Notes limits Niska Partners’ ability to incur new debt or to pay distributions in respect of, repurchase or pay dividends on its membership interests (or other capital stock) or make other restricted payments. The limitations will apply differently depending on a fixed charge coverage ratio, which is defined as the ratio of cash flows (which is defined in the indenture in a manner substantially consistent with consolidated earnings before interest, taxes, depreciation and amortization (“EBITDA”)) to fixed charges, each as defined in the indenture governing the Senior Notes, and measured for the preceding four fiscal quarters.

Under this limitation, the indenture would have permitted the Company to distribute approximately $250.8 million as at December 31, 2013.

If the fixed charge coverage ratio is not less than 2.0 to 1.0 (after giving pro forma effect to the incurrence of the additional debt obligations and any debt repurchases), Niska Partners is generally permitted to incur additional debt obligations beyond the Senior Notes and its $400 million Credit Agreement (discussed below).

If the fixed charge coverage ratio is not less than 1.75 to 1.0, Niska Partners is permitted to make restricted payments if the aggregate restricted payments since the date of the closing of its IPO, excluding certain types or amounts of permitted payments, are less than the sum (which the Company refers to as the restricted payment basket) of a number of items including, most importantly:

· operating surplus (defined similarly to the definition in the Company’s operating agreement) calculated as of the end of its preceding fiscal quarter; and

· the aggregate net cash proceeds received as a capital contribution or from the issuance of equity interests.

If the fixed charge coverage ratio is less than 1.75 to 1.0, Niska Partners is permitted to make restricted payments if the aggregate restricted payments constituting distributions in respect of Niska Partners’ equity interests since the date of the closing of its IPO, excluding certain types or amounts of permitted payments, are less than the sum (which the Company refers to as the restricted payment basket) of a number of items including, most importantly:

· $75.0 million; and

· the aggregate net cash proceeds received as a capital contribution or from the issuance of equity interests, again including the net cash proceeds from the IPO, reduced by the amount distributed before the IPO.

The indenture does not prohibit certain types or amounts of restricted payments, including a general basket of $75.0 million of restricted payments.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

3. Debt (continued)

At December 31, 2013, the fixed charge coverage ratio was 2.44 to 1.0.

$400 Million Credit Agreement

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.

At December 31, 2013, $127.0 million in borrowings, with a weighted average interest rate of 3.93% (March 31, 2013 - $65.0 million of borrowings had a weighted average interest rate of 3.69%), were outstanding under the credit facilities. Amounts committed in support of letters of credit totaled $34.1 million at December 31, 2013 (March 31, 2013 - $3.3 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, 2013, the borrowing base collateral totaled $486.4 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 dividends on its membership interests (or other capital stock) or make other restricted payments. These limitations are similar to those contained in the indenture governing the Senior Notes, but contain certain substantive differences. As a result of these differences, the limitations on restricted payments contained in the Credit Agreement should be less restrictive than the limitations contained in the indenture. As of December 31, 2013, Niska Partners was in compliance with all covenant requirements under the indenture governing the Senior Notes and the $400 million Credit Agreement.

Niska Partners has no independent assets or operations other than its investments in its subsidiaries. Both the Senior Notes and the $400 million Credit 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, which are prepared and measured on a consolidated basis, and have no restricted assets as of December 31, 2013.

4. Risk Management Activities and Financial Instruments

Risk Management Overview

Niska Partners has exposure to commodity price, 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.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

4. Risk Management Activities and Financial Instruments (continued)

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.

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 December 31, 2013, 56.4 Bcf of natural gas inventory was offset with financial contracts, representing 100% of total current inventory. Non-cycling working gas, which is included in long-term inventory, and fuel gas used for operating the facilities are excluded from the coverage requirement. Total volumes of long-term inventory and fuel gas at December 31, 2013 are 3.4 Bcf and 0.0 Bcf, respectively. As of December 31, 2013 and March 31, 2013, the volumes of inventories which were economically hedged using each type of contract were:

	December 31,		March 31,
	2013		2013

Forwards	0.9	Bcf	1.6	Bcf
Futures	55.1	Bcf	14.1	Bcf
Swaps	0.0	Bcf	10.0	Bcf
Options	—		—
	56.0	Bcf	25.7	Bcf

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 nine months ended December 31, 2013 and 2012, no trade receivables were deemed to be uncollectible. It is management’s opinion that no allowance for doubtful accounts is required at December 31, 2013 or March 31, 2013 on accrued and trade accounts receivable.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

4. Risk Management Activities and Financial Instruments (continued)

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 December 31, 2013 was $57.5 million (March 31, 2013 - $84.0 million). These contracts expire on various dates from January 1, 2014 through June 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 December 31, 2013 and March 31, 2013:

	Energy			Currency
December 31, 2013	Contracts			Contracts			Total

Short-term risk management assets	$	16,217		$	730		$	16,947
Long-term risk management assets	6,376			278			6,654
Short-term risk management liabilities	(37,450		)	(42		)	(37,492		)
Long-term risk management liabilities	(5,383		)	(1		)	(5,384		)
	$	(20,240	)	$	965		$	(19,275	)

	Energy			Currency
March 31, 2013	Contracts			Contracts			Total

Short-term risk management assets	$	20,383		$	776		$	21,159
Long-term risk management assets	6,593			—			6,593
Short-term risk management liabilities	(19,792		)	(213		)	(20,005		)
Long-term risk management liabilities	(4,477		)	(97		)	(4,574		)
	$	2,707		$	466		$	3,173

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars 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 are as follows:

December 31, 2013	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
Assets
Commodity derivatives	$	106,713		$	(84,120	)	$	22,593		$	(13,262	)	$	9,331
Currency derivatives	1,132			(124		)	1,008			(1,008		)	—
Total assets	107,845			(84,244		)	23,601			(14,270		)	9,331
Liabilities
Commodity derivatives	126,954			(84,121		)	42,833			(28,904		)	13,929
Currency derivatives	166			(123		)	43			(43		)	—
Total liabilities	127,120			(84,244		)	42,876			(28,947		)	13,929

Net	$	(19,275	)	$	—		$	(19,275	)	$	14,677		$	(4,598	)

March 31, 2013	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
Assets
Commodity derivatives	$	88,682	$	(61,706	)	$	26,976	$	(15,030	)	$	11,946
Currency derivatives	881		(105		)	776		(776		)	—
Total assets	89,563		(61,811		)	27,752		(15,806		)	11,946
Liabilities
Commodity derivatives	85,975		(61,706		)	24,269		(16,861		)	7,408
Currency derivatives	415		(105		)	310		(164		)	146
Total liabilities	86,390		(61,811		)	24,579		(17,025		)	7,554

Net	$	3,173	$	—		$	3,173	$	1,219		$	4,392

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

4. Risk Management Activities and Financial Instruments (continued)

The Company expects to recognize risk management assets and liabilities outstanding at December 31, 2013 into net earnings and comprehensive income in the fiscal periods as follows:

	Energy			Currency
	Contracts			Contracts		Total

Fiscal year ending March 31, 2014	$	(22,774	)	$	317	$	(22,457	)
Fiscal year ending March 31, 2015	3,217			371		3,588
Fiscal year ending March 31, 2016	(771		)	179		(592		)
Thereafter	88			98		186
	$	(20,240	)	$	965	$	(19,275	)

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

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012

Energy contracts
Realized	$	(559	)	$	(24,079	)	$	7,131		$	7,356
Unrealized	(29,803		)	41,515			(22,947		)	(37,616		)
Currency contracts
Realized	116			(146		)	1,712			(134		)
Unrealized	870			603			500			(145		)
	$	(29,376	)	$	17,893		$	(13,604	)	$	(30,539	)

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. 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 based on valuations of similar debt at the balance sheet date and supported by observable market transactions when available. See Note 3 for disclosures regarding the fair value of debt.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

5. Fair Value Measurements (continued)

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

December 31, 2013	Level 1		Level 2			Level 3		Total
Assets
Commodity derivatives	$	—	$	22,593		$	—	$	22,593
Currency derivatives	—		1,008			—		1,008
Total assets	—		23,601			—		23,601
Liabilities
Commodity derivatives	—		42,833			—		42,833
Currency derivatives	—		43			—		43
Total liabilities	—		42,876			—		42,876

Net	$	—	$	(19,275	)	$	—	$	(19,275	)

March 31, 2013	Level 1		Level 2		Level 3		Total
Assets
Commodity derivatives	$	—	$	26,976	$	—	$	26,976
Currency derivatives	—		776		—		776
Total assets	—		27,752		—		27,752
Liabilities
Commodity derivatives	—		24,269		—		24,269
Currency derivatives	—		310		—		310
Total liabilities	—		24,579		—		24,579

Net	$	—	$	3,173	$	—	$	3,173

The Company’s financial 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 December 31, 2013 and March 31, 2013.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

6. Members’ Equity

Equity restructuring

As described in Note 1, the Company completed an equity restructuring on April 2, 2013 to eliminate its subordinated units and previous IDRs in exchange for new IDRs. This was accounted for as an exchange of equity between the subordinated unit holder and the Managing Member.

Distribution Reinvestment Plan

Niska Partners filed a registration statement with the SEC to authorize the issuance of up to 7,500,000 common units in connection with a distribution reinvestment plan (“DRIP”). The DRIP provides unitholders of record and beneficial owners of common units a voluntary means by which unitholders can increase the number of common units owned by reinvesting the quarterly cash distributions unitholders would otherwise receive in the purchase of additional common units. This registration statement became effective on July 31, 2013. Common units purchased under the DRIP will come from the Company’s authorized but unissued common units or from common units purchased on the open market.

During the nine months ended December 31, 2013, the Carlyle/Riverstone Funds elected to participate in the DRIP and were issued 808,955 common units in lieu of receiving cash distributions of $12.0 million.

Phantom Unit Performance Plan

Effective April 1, 2011, the Company maintains a compensatory phantom unit performance plan (the “PUPP” or “the Plan”) to provide long-term incentive compensation for certain employees and directors and to align their economic interest with those of common unitholders.

A Phantom Unit is a notional unit granted under the PUPP that represents the right to receive a cash payment equal to the fair market value of a unit of the Company’s common units, following the satisfaction of certain time periods and/or certain performance criteria. Phantom Units are granted unvested and subject to both time and performance conditions. The default time period over which a Phantom Unit vests is three years from the date of grant. The performance measure is based upon total unitholder return (“TUR”) metrics compared to such metrics of a select group of peer companies. The TUR metrics are calculated based on the Company’s percentile ranking during the applicable performance period compared to the peer group. Provided that the Company has satisfied its minimum quarterly distribution targets for the underlying units, the Phantom Units will vest variably according to the Company’s performance relative to its peer group.

The plan was amended effective April 1, 2012. The performance measure for Phantom Units granted after that date is based on TUR metrics compared to such metrics of a select group of peer companies. The TUR metrics are calculated based on the Company’s percentile ranking during the applicable performance period compared to a peer group. Provided that the Company has satisfied its minimum quarterly distribution targets for the common units, the Phantom Units will vest variably according to the Company’s performance relative to its peer group.

During the nine months ended December 31, 2013, 438,036 Phantom Units were granted at a weighted average price of $12.68. During the nine months ended December 31, 2012, 695,349 Phantom Units were granted at a weighted average price of $9.99.

The Plan is administered by the Compensation Committee of the Board of Directors. The Plan permits the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, other unit-based awards, distribution equivalent rights and substitution awards covering an aggregate of 3,380,474 units. As of December 31, 2013, 1,519,679 units (March 31, 2013 - 2,045,693 units) were available for grant.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

6. Members’ Equity (continued)

The following is a reconciliation of Phantom Units Outstanding as of December 31, 2013:

	Number of Time- Based Units		Number of Performance-Based Units		Total Units
Balance at March 31, 2013	624,518		307,489		932,007
Granted	219,018		219,018		438,036
Vested and paid	(61,498	)	(61,498	)	(122,996	)
Forfeited	(23,718	)	(23,719	)	(47,437	)
Distribution equivalent rights	55,260		32,718		87,978
Balance at December 31, 2013	813,580		474,008		1,287,588

Unit-based compensation costs for the three and nine months ended December 31, 2013 were $2.1 million and $8.7 million respectively ($1.3 million and $5.0 million for the three and nine months ended December 31, 2012, respectively).

Earnings per unit:

Niska Partners uses the two-class method for allocating earnings per unit. The two-class method requires the determination of net income allocated to member interests as shown below. Net income for the three and nine months ended December 31, 2013, after the allocation to Managing Member’s interest, was only attributable to common unitholders as a result of cancellation of the Company’s subordinated units at the beginning of the current fiscal year. The cancellation of subordinated units has not impacted the prior-period calculation of earnings per unit.

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
*Numerator:*
Net earnings (loss) attributable to Niska Partners	$	(13,409	)	$	10,419		$	(13,286	)	$	(42,323	)
Less:
Managing Member’s interest	260			(206		)	256			838
Net earnings (loss) attributable to common unitholders	$	(13,149	)	$	5,158		$	(13,030	)	$	(20,951	)
Net earnings (loss) attributable to subordinated unitholders	$	—		$	5,055		$	—		$	(20,534	)

*Denominator:*
Basic:
Weighted average units outstanding	35,077,239			68,296,990			34,756,989			68,296,990

Diluted:
Weighted average units outstanding	35,077,239			68,296,990			34,756,989			68,296,990

Earnings (loss) per unit allocated to common unitholders - basic and diluted	$	(0.37	)	$	0.15		$	(0.37	)	$	(0.61	)
Earnings (loss) per unit allocated to subordinated unitholders - basic and diluted	$	—		$	0.15		$	—		$	(0.61	)

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

7. Revenues

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

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2013		2012		2013		2012

Long-term contract revenue	$	21,278	$	26,492	$	62,161	$	82,283
Short-term contract revenue	9,206		14,763		32,990		37,031
Total	$	30,484	$	41,255	$	95,151	$	119,314

Optimization, net consists of the following:

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012

Realized optimization revenue, net	$	24,296		$	(9,542	)	$	47,193		$	36,316
Unrealized risk management (losses) gains	(28,933		)	42,118			(22,447		)	(37,760		)
Write-down of inventory	—			—			—			(22,281		)
Total	$	(4,637	)	$	32,576		$	24,746		$	(23,725	)

8. Income Taxes

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

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012

Income tax benefit	$	(6,309	)	$	(542	)	$	(6,561	)	$	(19,200	)

Effective income tax rate	32		%	-5		%	33		%	31		%

Income tax benefit was $6.6 million for the nine months ended December 31, 2013 compared to a benefit of $19.2 million in the same period of the prior year. The income tax benefit in the current period is due mainly to the recognition of losses in certain foreign taxable entities.

The effective tax rate for the three and nine months ended December 31, 2013 and 2012 differs from the U.S. statutory federal rate of 35% primarily due to the recognition of losses in some entities which have a lower statutory tax rate as well as income attributable to subsidiaries exempt from U.S. Federal income taxes.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

9. Accrued Liabilities

Niska Partners’ accrued liabilities consist of the following:

	December 31,		March 31,
	2013		2013

Accrued gas purchases	$	24,733	$	14,213
Employee-related accruals	16,840		13,836
Accrued interest	17,573		2,845
Other accrued liabilities	6,828		8,946
	$	65,974	$	39,840

10. Changes in Non-Cash Working Capital

Changes in non-cash working capital for the nine months ended December 31, 2013 and 2012 consist of the following:

	Nine Months Ended
	December 31,
	2013			2012

Margin deposits	$	(35,184	)	$	(33,215	)
Trade receivables	(1,273		)	(2,003		)
Accrued receivables	42,165			16,776
Natural gas inventory	(99,043		)	17,801
Prepaid expenses and other current assets	1,199			1,310
Other assets	(88		)	367
Trade payables	(218		)	454
Accrued liabilities	24,222			19,608
Deferred revenue	319			11,318
Other long-term liabilities	(60		)	—
Total	$	(67,961	)	$	32,416

During the nine months ended December 31, 2012, changes in non-cash working capital included the receipt of proceeds of $18.0 million (December 31, 2013 - $ nil) and an increase in accrued receivables of $14.6 million (December 31, 2013 - $ nil) from sales of cushion gas. The Company included such proceeds in cash flows from operations since the predominant source of cash flows for natural gas purchases and sales are operating in nature.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

11. Supplemental Cash Flow Disclosures

	Nine Months Ended
	December 31,
	2013			2012

Interest paid	$	32,484		$	37,332
Taxes paid (recovered)	$	73		$	(38	)
Interest capitalized	$	—		$	2,928

Non-cash increase in working capital related to property, plant and equipment classified as operating activity	$	—		$	14,648

Non-cash (decrease) increase in working capital related to property, plant and equipment classified as investing activities	$	(1,993	)	$	5,560

Non-cash earnings distribution and reinvestment	$	12,039		$	—

12. 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: fee-based revenue 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 December 31, 2013 and March 31, 2013 and for each of the three months and nine months period ended December 31, 2013 and 2012.

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 and comprehensive income. All facilities have the same types of customers: major companies in the energy industry, industrial, commercial, local distribution companies and municipal energy consumers.

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Niska Gas Storage Partners LLC

Notes to Unaudited Consolidated Financial Statements (continued)

(Tabular amounts expressed in thousands of U.S. dollars unless otherwise noted)

12. Segment Disclosures (continued)

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

	Three Months Ended					Nine Months Ended
	December 31,					December 31,
	2013			2012		2013			2012

Net realized revenues
U.S.	$	16,556		$	7,633	$	36,330		$	38,368
Canada	38,224			24,080		106,014			94,981
Net unrealized revenues
U.S.	(15,333		)	16,476		(9,025		)	(11,617		)
Canada	(13,600		)	25,642		(13,422		)	(26,143		)
Inter-entity
U.S.	—			—		—			—
Canada	—			—		—			—
	$	25,847		$	73,831	$	119,897		$	95,589

	December 31,		March 31,
	2013		2013
Long-lived assets (at period end)

U.S.	$	402,085	$	411,420
Canada	839,992		858,604
	$	1,242,077	$	1,270,024

13. Subsequent Events

Distributions

On January 29, 2014, the Board of Directors of Niska Partners approved a distribution of $0.35 per common unit, payable on February 18, 2014 to unitholders of record as of February 10, 2014. The total distribution is expected to be approximately $12.6 million.

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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, 2013.

Overview of Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America (“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, 2013 and remained unchanged as of December 31, 2013.

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 customers inject and withdraw specified amounts of gas and pay fees on specific dates, and optimization, where we purchase and sell gas on an economically hedged basis in order to improve facility utilization at margins 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 250.5 billion cubic feet (“Bcf”) of working gas capacity among its facilities, including 8.5 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

During the past year, future market values for natural gas storage in North America have continued to decline, led primarily by a narrowing of the difference between summer and winter prices in the natural gas futures market, which we refer to as the seasonal spread. These market conditions affect the prices that we are able to charge for contracted storage services, as well as revenues realizable by us in our optimization activities. If current market conditions persist, our results of operation could be adversely impacted to a material extent.

Market conditions can change rapidly as a result of a number of factors, including weather, overall storage levels across North America and in the markets we serve, current and anticipated levels of natural gas supply and demand, and pipeline infrastructure capacity. Accordingly, current market conditions may not be a reliable predictor of future events. Longer term, we believe several factors will contribute to meaningful growth in North American natural gas demand, including: (i) exports of North American volumes of Liquefied Natural Gas, or LNG; (ii) sustained fuel switching from coal to natural gas; (iii) construction of new gas-fired power plants; and (iv) growth in base-level industrial demand, all of which would bolster the market need for, and the commercial value of, natural gas storage. However, we are unable to predict the timing or magnitude of such events and the ultimate impact they may have on our results of operations.

In addition, our largest volumetric customer is party to a storage services agreement which contains an option to terminate (by either party) every five years, with one year’s notice. This option is exercisable at the end of fiscal 2014 and it is unclear whether our customer will exercise its option. If the contract is terminated and a new contract is negotiated, we would expect that the terms of the contract would be more favorable to the customer than the current terms. However, if a party exercises its option to terminate, which would be effective at the end of fiscal 2015, that party is required to pay a substantial early termination fee. If the contract is terminated, the adverse effect of such termination would not impact our results of operation until fiscal 2016.

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Results of Operations

A summary of financial data for each of the three and nine months ended December 31, 2013 and 2012 is as follows:

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
	(unaudited)						(unaudited)
Consolidated Statement of Earnings (Loss) and Comprehensive Income (Loss) Data:
Revenues:
Fee-based revenue	$	30,484		$	41,255		$	95,151		$	119,314
Optimization, net	(4,637		)	32,576			24,746			(23,725		)
	25,847			73,831			119,897			95,589
Expenses (income):
Operating	8,426			8,330			27,747			25,250
General and administrative	9,361			8,417			30,164			26,332
Depreciation and amortization	10,518			14,831			31,149			39,896
Interest	17,114			17,279			49,718			50,459
Loss on disposal of assets	—			15,072			—			15,072
Loss on extinguishment of debt	—			—			—			599
Foreign exchange losses (gains)	160			22			606			(314		)
Other (income) expense	(14		)	3			360			(182		)
Loss before income taxes	(19,718		)	9,877			(19,847		)	(61,523		)

Income tax benefit	(6,309		)	(542		)	(6,561		)	(19,200		)

Net earnings (loss) and comprehensive income (loss)	$	(13,409	)	$	10,419		$	(13,286	)	$	(42,323	)

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Earnings (Loss)
Net earnings (loss)	$	(13,409	)	$	10,419		$	(13,286	)	$	(42,323	)
Add/(deduct):
Interest expense	17,114			17,279			49,718			50,459
Income tax benefit	(6,309		)	(542		)	(6,561		)	(19,200		)
Depreciation and amortization	10,518			14,831			31,149			39,896
Unrealized risk management losses (gains)	28,933			(42,118		)	22,447			37,739
Loss on disposal of assets	—			15,072			—			15,072
Loss on extinguishment of debt	—			—			—			599
Foreign exchange losses (gains)	160			22			606			(314		)
Other (income) expense	(14		)	3			360			(182		)
Write-down of inventory	—			—			—			22,281
Adjusted EBITDA	36,993			14,966			84,433			104,027

Less:
Cash interest expense, net	16,278			16,421			47,212			47,882
Income taxes paid (recovered)	67			(31		)	73			(38		)
Maintenance capital expenditures	123			193			1,082			1,107
Other (income) expense	(14		)	3			360			(182		)
Cash Available for Distribution	$	20,539		$	(1,620	)	$	35,706		$	55,258

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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, the most directly comparable financial measure as calculated and presented in accordance with GAAP, is shown above.

We define Adjusted EBITDA as net earnings 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, 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. 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 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 optimization revenue, net. 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 the three and nine months ended December 31, 2013 and 2012, respectively, consisted of the following:

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
	(unaudited)						(unaudited)

Long-term contract revenue	$	21,278		$	26,492		$	62,161		$	82,283
Short-term contract revenue	9,206			14,763			32,990			37,031
Fee-based revenue	30,484			41,255			95,151			119,314

Realized optimization, net	24,296			(9,542		)	47,193			36,316
Unrealized risk management (losses) gains	(28,933		)	42,118			(22,447		)	(37,760		)
Write-down of inventory	—			—			—			(22,281		)
Optimization revenue, net	$	(4,637	)	$	32,576		$	24,746		$	(23,725	)

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

Long-term contract revenue. LTF revenues for the three months ended December 31, 2013 declined by $5.2 million (20%) compared to the three months ended December 31, 2012. LTF revenues for the nine months ended December 31, 2013 declined by $20.1 million (24%) compared to the same period last year. This decline was due in part to our decision to allocate 22 Bcf less storage capacity to this strategy than in the previous year. In addition, the realization of lower average rates for LTF contracts combined with a weaker Canadian dollar in the current period versus the prior year contributed to the decline in LTF revenues year over year.

Short-term contract revenue. STF revenues for the three months ended December 31, 2013 declined by $5.6 million (38%) when compared to the three months ended December 31, 2012. STF revenues for the nine months ended December 31, 2013 decreased by $4.0 million (11%) compared to the same period last year. These decreases resulted from a weaker spread environment in the current period compared to the respective period in the prior year.

Optimization Revenues. Optimization revenues for the three months ended December 31, 2013 decreased to net losses of $4.6 million from net gains of $32.6 million in the third quarter of fiscal 2013. Optimization revenues for the nine months ended December 31, 2013 increased to a net gain $24.7 million from net losses of $23.7 million in the nine months ended December 31, 2012. 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. For financial reporting purposes, our net optimization revenues include the impact of unrealized economic hedging gains and losses and inventory write-downs, which cause our reported revenues to fluctuate from period to period. However, because all inventory is economically hedged, any inventory write-downs are offset by hedging gains and any unrealized hedging losses are offset by realized gains from the sale of physical inventory. The components of optimization revenues are as follows:

Realized Optimization Revenue, net. Net realized optimization revenue of $24.3 million in the current quarter increased by $33.8 million from a net loss of $9.5 million in the third quarter of the previous year. Net realized optimization revenue for the nine months ended December 31, 2013 of $47.2 million increased by $10.9 million from $36.3 million for the nine months ended December 31, 2012. The increase for the three months ended December 31, 2013 resulted from incremental gains realized from short-term opportunities related to cold weather as increased heating demand had a significant impact on cash prices across North America. These price fluctuations resulted in significant withdrawals of natural gas inventory at all of our facilities, and provided near-term opportunities to reposition hedged inventory at a gain.

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During the three months ended December 31, 2012, realized losses on financial hedges were incurred as a result of increases in natural gas prices relative to the sales contracts that settled during the period. These losses were partially offset by gains on physical deliveries. The increase for the nine months ended December 31, 2013 results from weather related opportunities as well as the timing of financial hedge realizations compared to the nine months ended December 31, 2012. During the nine months ended December 31, 2012 the losses realized in the third quarter only partially offset the gains realized on financial hedges for the first two quarters, resulting in a net gain on financial hedges during this period. The three and nine month periods ended December 31, 2013 included $2.4 million and $7.0 million in optimization revenue related to our retail marketing business, compared to $2.8 million and $7.7 million realized during the three and nine month periods ended December 31, 2012.

· Unrealized Risk Management Gains (Losses). Unrealized risk management losses in the three month period ended December 31, 2013 resulted from decreases in the value of financial hedges as a result of natural gas prices increasing relative to average sales contract prices in future months. Unrealized risk management gains in the three month period ended December 31, 2012 resulted from increases in the value of financial hedges as a result of natural gas prices decreasing relative to average sales contract prices in future months. The realization of losses totaling $23.6 million related to the settlement of economic hedges in the three month period also increased these unrealized gains. Unrealized risk management losses in the nine month period ended December 31, 2012 resulted from decreases in the value of financial hedges resulting from increases in forward prices of natural gas relative to the beginning of our fiscal year, combined with the realization of gains of $9.1 million in economic hedges. The three and nine month periods ended December 31, 2013 also included $0.6 million in unrealized risk management gains and $0.4 million of unrealized risk management gains related to our retail marketing business, compared to a $0.2 million loss and $3.7 million in unrealized risk management gains during the three and nine month period ended December 31, 2012.

· Write-Down of Inventory. No write-down of inventory occurred in the current fiscal year. During the fourth quarter of fiscal 2012, near-term prices of natural gas fell dramatically. This reduction increased the value of our economic hedges and decreased the value of the proprietary optimization inventory underlying those hedges. Concurrently, the steepening of the forward curve at that time as noted above encouraged us to realize incremental revenues through the repositioning of inventory deliveries from the fourth quarter of fiscal 2012 into future periods in fiscal 2013 or beyond. Natural gas prices continued to fall during the first quarter of fiscal 2013. Consequently, the market value of our inventories fell below the carrying cost by the end of the first quarter and we wrote down our proprietary inventories by $22.3 million to the lower of cost or market value.

Operating Expenses

Operating expenses for the three and nine months ended December 31, 2013 and 2012 consisted of the following:

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2013		2012		2013		2012
	(unaudited)				(unaudited)

Lease costs and property taxes	$	3,375	$	3,525	$	10,583	$	10,538
Fuel and electricity	1,782		1,606		7,285		5,274
Salaries and benefits	1,728		1,744		5,431		5,161
Maintenance	984		964		2,586		2,402
General operating costs	557		491		1,862		1,875
Total operating expenses	$	8,426	$	8,330	$	27,747	$	25,250

Operating expenses for the three months ended December 31, 2013 increased by $0.1 million (1%) compared to the three months ended December 31, 2012. Operating expenses for the nine months ended December 31, 2013 increased by $2.5 million (10%) compared to the nine months ended December 31, 2012. An increase in cycled volumes during the current fiscal year resulted in increased fuel and power consumption, combined with high power prices led to an increase of $2.0 million in fuel and electricity costs compared to the same nine month period in the prior year.

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General and Administrative Expenses

General and administrative expenses for the three and nine months ended December 31, 2013 and 2012 consisted of the following:

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2013		2012		2013		2012
	(unaudited)				(unaudited)

Compensation costs	$	5,322	$	5,520	$	19,254	$	16,759
General costs, including office and information technology costs	1,141		1,077		3,154		3,316
Legal, audit and regulatory costs	2,898		1,820		7,756		6,257
Total general and administrative expenses	$	9,361	$	8,417	$	30,164	$	26,332

General and administrative expenses for the three months ended December 31, 2013 increased by $0.9 million (11%) compared to the three months ended December 31, 2012. General and administrative expenses for the nine months ended December 31, 2013 increased by $3.8 million (15%) compared to the nine months ended December 31, 2012. The increase for the three months ended December 31, 2013 is primarily due to higher legal and regulatory costs in the current period. The increase for the nine months ended December 31, 2013 is primarily due to increased compensation costs as a result of higher incentive compensation accruals related to long-term compensation plans.

Depreciation and Amortization Expense

Depreciation and amortization expense for the three months ended December 31, 2013 decreased by $4.3 million (29%) compared to the three months ended December 31, 2012. Depreciation and amortization expense for the nine months ended December 31, 2013 decreased by $8.7 million (22%) compared to the same period last year. The decreases were primarily attributable to a reduction in cushion gas migration at one of our facilities, offset by additional depreciation from equipment purchased as part of our capacity expansion at our Wild Goose facility.

Interest Expense

Interest expense for the three and nine months ended December 31, 2013 and 2012 consisted of the following:

	Three Months Ended					Nine Months Ended
	December 31,					December 31,
	2013		2012			2013		2012
	(unaudited)					(unaudited)

Interest on senior notes	$	14,284	$	14,284		$	42,853	$	42,852
Interest on revolving credit facility	1,808		2,078			3,756		7,202
Amortization of deferred charges	836		834			2,506		2,577
Other interest	186		225			603		756
	17,114		17,421			49,718		53,387

Less: Capitalized interest	—		(142		)	—		(2,928		)
Total interest expenses	$	17,114	$	17,279		$	49,718	$	50,459

Interest expense for the three months ended December 31, 2013 decreased by $0.2 million (1%) compared to the three months ended December 31, 2012. Interest expense for the nine months ended December 31, 2013 decreased by $0.7 million (1%) compared to the same period last year. Reduced interest expense from lower rates on our credit facilities coupled with reduced utilization were offset by the absence of capitalized interest.

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Loss on Extinguishment of Debt

We amended and restated our $400 million Credit Agreement on June 29, 2012. The write-off of a portion of deferred financing costs associated with the prior agreement resulted in a loss on debt extinguishment of $0.6 million last year.

Income Taxes

Income taxes for the three and nine month periods ended December 31, 2013 reflect the recognition of tax effects in certain foreign taxable entities.

The effective tax rate for the three and nine months ended December 31, 2013 differs from the U.S. statutory federal rate of 35% primarily due to the recognition of losses in taxable entities which have a lower statutory rate.

Liquidity and Capital Resources

Sources and Uses of Liquidity

Our primary short-term liquidity needs are to pay interest and principal payments under our $400 million Credit Agreement and interest payments on our 8.875% Senior Notes due 2018 (the “Senior Notes”), to fund our operating expenses and maintenance capital expenditures, to pay for the acquisition of proprietary optimization inventory along with associated margin requirements and to pay quarterly distributions, to the extent declared by our board of directors. We fund these expenditures through a combination of cash on hand, cash from operations and borrowings under our $400 million Credit Agreement.

Our medium-term and long-term liquidity needs primarily relate to potential debt repurchases, organic expansion opportunities and asset acquisitions. We expect to finance the cost of any expansion projects and acquisitions from borrowings under our existing and possible future credit facilities or a mix of borrowings and additional equity offerings as well as cash on hand and cash from operations.

Our principal debt covenant is our fixed charge coverage ratio (“FCCR”), which is included in both our $400 million Credit Agreement and the indenture governing our Senior Notes. When our FCCR, which is calculated on a trailing-twelve month basis by dividing Adjusted EBITDA (defined substantially the same as presented herein) by fixed charges (which are measured as interest expense plus the amount of interest capitalized, but giving pro forma credit for the all of the previous twelve months for certain debt purchases and acquisitions), is less than 2.0 to 1.0, we are restricted in our ability to issue new debt. However, this restriction does not impact our ability to access our existing $400 million credit facility, or to amend, extend or replace that facility. When our FCCR is below 1.75 to 1.0, we are restricted in our ability to pay distributions. If our fixed charge coverage ratio were to fall below 1.75 to 1.0, we would be permitted thereafter to pay $75 million of distributions. This $75 million amount is cumulative for all periods that our FCCR is below 1.75 to 1.0. The appropriateness and amount of distributions are determined by our board of directors on a quarterly basis. At December 31, 2013, our FCCR was 2.44 to 1.0.

The $400 million Credit Agreement has a maturity date of June 29, 2016. Borrowing costs under this agreement are based off of a pricing grid which relates to certain leverage levels to determine interest rates. At December 31, 2013, we had $127.0 million in borrowings, $34.1 million committed in support of letters of credit and $238.9 million of unutilized capacity related to our credit facility.

We believe that our existing sources of liquidity described above will be sufficient to fund our short-term liquidity needs through the upcoming twelve month period. Funding of material acquisitions and longer-term liquidity needs will depend on the availability and cost of capital in the debt and equity markets, as well as compliance with our debt covenants. Accordingly, the availability of any such potential funding on economic terms is uncertain.

Management does not believe that the operation of its existing business is impacted by the availability of capital for expansion projects or acquisitions.

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Cash Flows from Operations and Investing Activities

The following table summarizes our sources and uses of cash for the nine months ended December 31, 2013 and 2012, respectively:

	Nine Months Ended
	December 31,
Operating Activities:	2013			2012
	(unaudited)

Net loss	$	(13,286	)	$	(42,323	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Unrealized foreign exchange losses	830			30
Deferred income tax benefit	(6,561		)	(19,222		)
Unrealized risk management losses	22,447			37,739
Depreciation and amortization	31,149			39,896
Deferred charges amortization	2,506			2,577
Loss on disposal of assets	—			15,072
Loss on extinguishment of debt	—			599
Write-down of inventory	—			22,281
Changes in non-cash working capital	(67,961		)	32,416
Net cash (used in) provided by operating activities	(30,876		)	89,065

Net cash used in investing activities	(3,669		)	(27,044		)

Net cash provided by (used in) financing activities	33,328			(63,752		)

Effect of translation of foreign currency on cash and cash equivalents	(221		)	49

Net Decrease in Cash and Cash Equivalents	$	(1,438	)	$	(1,682	)

The variability in net cash provided by operating activities is primarily due to fluctuating market conditions that exist in any particular fiscal period, which impacts the margins and fees for of our fee-based and optimization activities. This impacts our decision to buy or sell significant volumes of inventory or hold existing inventories over a fiscal period end and sell them in the future if there is an economic incentive to do so.

During the nine months ended December 31, 2013, we realized a decrease in cash from operations compared to the nine months ended December 31, 2012. The decrease resulted principally from the purchase of proprietary inventory and the timing of collections from our customers.

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Changes in non-cash working capital consisted of the following:

	Nine Months Ended
	December 31,
	2013			2012
	(unaudited)

Margin deposits	$	(35,184	)	$	(33,215	)
Trade receivables	(1,273		)	(2,003		)
Accrued receivables	42,165			16,776
Natural gas inventory	(99,043		)	17,801
Prepaid expenses and other current assets	1,199			1,310
Other assets	(88		)	367
Trade payables	(218		)	454
Accrued liabilities	24,222			19,608
Deferred revenue	319			11,318
Other long-term liabilities	(60		)	—

Net changes in non-cash working capital	$	(67,961	)	$	32,416

As noted above, working capital can change 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. Non-cash working capital decreased by $67.9 million compared to an increase of $32.4 million in the same period of the prior year.

Investing Activities

Substantially all of our cash used for investing activities consisted of capital expenditures in each of the nine months ended December 31, 2013 and 2012. Capital expenditures in each nine month period consisted of the following:

	Nine Months Ended
	December 31,
	2013			2012
	(unaudited)

Maintenance capital	$	1,082		$	1,107
Expansion capital	2,573			22,577
Total capital expenditures	3,655			23,684

Change in accrued capital expenditures	(1,993		)	5,560
Purchase of customer contracts	2,007			—
Proceeds from sale of assets	—			(2,200		)
Net cash used in investing activities	$	3,669		$	27,044

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 made to acquire additional assets to grow our business, to expand and upgrade our facilities and to acquire similar operations or facilities. During the nine months ended December 31, 2012, we spent a total of $22.6 million on expansion capital, the majority of which related to a project at our Wild Goose facility. The project was completed and put into service during fiscal 2013, leading to a significant reduction in expansion capital in fiscal 2014.

Under our current plan, we expect to continue to spend between approximately $1.0 million and $2.0 million per year for maintenance capital expenditures 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 the balance of fiscal 2014 is expected to be less than $5.0 million and relates principally to enhancing existing capacity and developing new projects.

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In fiscal 2014, we received approval from the California Public Utilities Commission to add 25 Bcf of capacity at our Wild Goose facility from 50 Bcf to 75 Bcf. Because most of the equipment required to support this expansion had been purchased and installed previously, costs required to complete this current expansion are not significant. The current expansion is now in service.

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, 2013 regarding this matter.

At December 31, 2013, 56.4 Bcf of natural gas inventory was economically hedged, representing 100% 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 $56.4 million, the fair value or mark-to-market value of our economic hedges would decrease by $56.4 million, and the impact due to the non-economically hedged position would be $ nil. Similarly, if the price of natural gas declined by $1.00 per Mcf, the value of inventory would decrease by $56.4 million while the fair value of our economic hedges would increase by $56.4 million and the impact due to the non-economically hedged position would be $ nil. Long-term inventory and fuel gas used for operating our facilities are not offset. Total volumes of long-term inventory and fuel gas at December 31, 2013 are 3.4 Bcf and 0.0 Bcf, respectively.

At December 31, 2013, we were exposed to interest rate risk resulting from the variable rates associated with our $400 million Credit Agreement. A balance of $127.0 million was drawn on the credit facilities at December 31, 2013. 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 December 31, 2013, a one percent increase or decrease in interest rates would have an impact of approximately $1.3 million on our interest expense.

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 December 31, 2013. 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.

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Item 6. Exhibits

Exhibit Number		Description
3.1	—	Certificate of formation of Niska Gas Storage Partners LLC (incorporated by reference to Exhibit 3.1 of Amendment 2 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).

31.1*	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2*	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

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.

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.INS*	—	XBRL Instance Document.

101.SCH*	—	XBRL Taxonomy Extension Schema Document.

101.CAL*	—	XBRL Taxonomy Extension Calculation 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.

		Page
	PART I. FINANCIAL INFORMATION

Item 1.	*Financial Statements (unaudited)*	1

	Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss) for the Three and Nine Months Ended December 31, 2013 and 2012	1
	Consolidated Balance Sheets as of December 31, 2013 and March 31, 2013	2
	Consolidated Statements of Cash Flows for the Nine Months Ended December 31, 2013 and 2012	3
	Consolidated Statements of Changes in Members’ Equity for the Nine Months Ended December 31, 2013 and 2012	4
	Notes to Unaudited Consolidated Financial Statements	5

Item 2.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*	21

Item 3.	*Quantitative and Qualitative Disclosures About Market Risk*	30

Item 4.	*Controls and Procedures*	30

	PART II. OTHER INFORMATION

Item 1.	*Legal Proceedings*	31

Item 1A.	*Risk Factors*	31

Item 6.	*Exhibits*	32

	NISKA GAS STORAGE PARTNERS LLC


Date: January 30, 2014	By:	/s/ VANCE E. POWERS
		Vance E. Powers
		Chief Financial Officer
		(Principal Accounting Officer)