Niska Gas Storage Partners (NKA) 10-Q 2013 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended December 31, 2012

OR

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 1-34733

Niska Gas Storage Partners LLC

(Exact name of registrant as specified in its charter)

Delaware	27-1855740
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification number)
1001 Fannin Street Suite 2500 Houston, TX	77002
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code:

(281) 404-1890

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 Date 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. (Check one):

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 Act).  Yes o  No x

As of February 1, 2013, there were 34,492,245 Common Units and 33,804,745 Subordinated Units outstanding.

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 generally 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 and in our Annual Report on Form 10-K for the fiscal year ended March 31, 2012, and those described from time to time in our future reports filed with the Securities and Exchange Commission.

i

TABLE OF CONTENTS

		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, 2012 and 2011	1
	Consolidated Balance Sheets as of December 31, 2012 and March 31, 2012	2
	Consolidated Statements of Cash Flows for the Nine Months Ended December 31, 2012 and 2011	3
	Consolidated Statements of Changes in Members’ Equity for the Nine Months Ended December 31, 2012 and 2011	4
	Notes to Unaudited Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 4.	Controls and Procedures	29
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	30
Item 6.	Exhibits	31

ii

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,
	2012			2011			2012			2011
Revenues:
Long-term contract	$	26,492		$	28,994		$	82,283		$	88,069
Short-term contract	14,763			8,228			37,031			19,532
Optimization, net	32,576			52,682			(23,725		)	103,726
	73,831			89,904			95,589			211,327
Expenses (income):
Operating	8,330			9,702			25,250			34,881
General and administrative	8,417			6,015			26,332			20,482
Depreciation and amortization	14,831			13,115			39,896			33,922
Loss on disposal of assets	15,072			—			15,072			—
Interest	17,279			19,598			50,459			57,620
Impairment of goodwill	—			250,000			—			250,000
Loss on extinguishment of debt	—			5,147			599			6,030
Foreign exchange losses (gains)	22			557			(314		)	939
Other expense (income)	3			(7		)	(182		)	(49		)
INCOME (LOSS) BEFORE INCOME TAXES	9,877			(214,223		)	(61,523		)	(192,498		)
Income tax benefit	(542		)	(593		)	(19,200		)	(11,084		)
NET EARNINGS (LOSS) AND COMPREHENSIVE INCOME(LOSS)	$	10,419		$	(213,630	)	$	(42,323	)	$	(181,414	)
Net earnings (loss) allocated to:
Managing Member	$	206		$	(4,230	)	$	(838	)	$	(3,595	)
Common unitholders	$	5,158		$	(105,754	)	$	(20,951	)	$	(89,804	)
Subordinated unitholder	$	5,055		$	(103,646	)	$	(20,534	)	$	(88,015	)
Earnings (loss) per unit allocated to common unitholders
- basic and diluted	$	0.15		$	(3.07	)	$	(0.61	)	$	(2.62	)
Earnings (loss) per unit allocated to subordinated unitholders
- basic and diluted	$	0.15		$	(3.07	)	$	(0.61	)	$	(2.62	)

(See Notes to Unaudited Consolidated Financial Statements)

1

Niska Gas Storage Partners LLC

Consolidated Balance Sheets

(in thousands of U.S. dollars)

(Unaudited)

	December 31,		March 31,
	2012		2012
ASSETS
Current assets
Cash and cash equivalents	$	11,660	$	13,342
Margin deposits	12,513		—
Trade receivables	4,542		2,468
Accrued receivables	50,054		49,046
Natural gas inventory	190,657		230,739
Prepaid expenses	1,851		3,162
Short-term risk management assets	74,205		140,670
	345,482		439,427
Long-term assets
Property, plant and equipment, net	924,949		968,128
Goodwill	245,604		245,604
Long-term natural gas inventory	15,264		15,264
Intangible assets, net	76,707		85,309
Deferred charges, net	15,254		15,182
Other assets	1,628		1,624
Long-term risk management assets	9,248		32,820
	1,288,654		1,363,931
TOTAL	$	1,634,136	$	1,803,358
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities
Revolving credit facility	$	124,000	$	150,000
Margin deposits	—		20,707
Current portion of obligations under capital lease	1,250		1,295
Trade payables	868		1,527
Current portion of deferred taxes	22,828		22,821
Deferred revenue	22,553		11,235
Accrued liabilities	52,208		37,293
Short-term risk management liabilities	20,857		58,870
	244,564		303,748
Long-term liabilities
Long-term risk management liabilities	7,311		21,596
Asset retirement obligations	1,925		1,554
Other long-term liabilities	1,451		234
Deferred income taxes	110,667		129,952
Obligations under capital lease	12,543		12,094
Long-term debt	643,790		643,790
	1,022,251		1,112,968
Members’ equity
Common units	334,799		391,585
Subordinated units	266,941		287,105
Managing Member’s interest	10,145		11,700
	611,885		690,390
Commitments and contingencies (Note 2)
TOTAL	$	1,634,136	$	1,803,358

(See Notes to Unaudited Consolidated Financial Statements)

2

Niska Gas Storage Partners LLC

Consolidated Statements of Cash Flows

(in thousands of U.S. dollars)

(Unaudited)

	Nine Months Ended
	December 31,
	2012			2011
Operating Activities
Net loss	$	(42,323	)	$	(181,414	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Unrealized foreign exchange losses	30			88
Deferred income tax benefit	(19,222		)	(11,178		)
Unrealized risk management losses (gains)	37,739			(74,708		)
Depreciation and amortization	39,896			33,922
Deferred charges amortization	2,577			3,018
Loss on extinguishment of debt	599			6,030
Loss on disposal of assets	15,072			—
Write-down of inventory	22,281			—
Impairment of goodwill	—			250,000
Changes in non-cash working capital	32,416			8,077
Net cash provided by operating activities	89,065			33,835
Investing Activities
Capital expenditures	(29,244		)	(43,632		)
Proceeds on disposal of assets	2,200			—
Net cash used in investing activities	(27,044		)	(43,632		)
Financing Activities
Proceeds from revolver drawings	281,948			498,798
Revolver payments	(307,948		)	(414,798		)
Repurchase of long-term debt	—			(124,817		)
Payment of debt issuance costs	(3,248		)	—
Proceeds from capital lease obligations	947			—
Payments of capital lease obligations	(408		)	—
Net proceeds from issuance of common units	—			11,000
Distributions to unitholders	(35,043		)	(61,153		)
Acquisition of interest in parent company	—			(2,176		)
Net cash used in financing activities	(63,752		)	(93,146		)
Effect of translation on foreign currency cash and cash equivalents	49			(206		)
Net decrease in cash and cash equivalents	(1,682		)	(103,149		)
Cash and cash equivalents, beginning of period	13,342			117,742
Cash and cash equivalents, end of period	$	11,660		$	14,593

Supplemental cash flow disclosures (Note 11)

(See Notes to Unaudited Consolidated Financial Statements)

3

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, 2011	$	510,275		$	390,283		$	16,415		$	916,973
Net loss	(89,804		)	(88,015		)	(3,595		)	(181,414		)
Distributions to Unitholders	(36,212		)	(24,140		)	(1,229		)	(61,581		)
Acquisition of interest in parent company	(1,066		)	(1,066		)	(44		)	(2,176		)
Acquisition of assets from parent company	212			208			8			428
Issuance of common units	11,000			—			—			11,000
Tax benefit of offering costs	2,207			2,207			90			4,504
Balance December 31, 2011	$	396,612		$	279,477		$	11,645		$	687,734
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

(See Notes to Unaudited Consolidated Financial Statements)

4

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) that was formed on January 27, 2010 to acquire certain assets of Niska GS Holdings I, LP and Niska GS Holdings II, LP (collectively, “Niska Predecessor”). On May 11, 2010, Niska Partners priced its initial public offering (the “IPO”) of 17,500,000 common units at an offering price of $20.50 per unit. Upon closing of the IPO on May 17, 2010, Niska Partners received net proceeds of $333.5 million, after deducting the underwriters’ discount, structuring fees and offering expenses. Upon closing the IPO, Niska Predecessor’s parent Niska Sponsor Holdings Coöperatief U.A. (“Sponsor Holdings” or “Holdco”), exchanged 100% of its equity interest in Niska Predecessor for a 2% Managing Member’s interest, 33,804,745 subordinated units, 13,679,745 common units of Niska Partners, and all of the Company’s Incentive Distribution Rights (“IDRs”). As a result of these transactions, Niska Partners became the owner of substantially all of the assets of Niska Predecessor. Prior to the closing, Niska Partners had no activity.

As partial consideration for the contribution of 100% of Niska Predecessor’s equity interest to Niska Partners, Sponsor Holdings held the right to receive any common units not purchased pursuant to the expiration of a 30-day option granted to the underwriters of the IPO to purchase up to an additional 2,625,000 common units. Upon the close of business on June 10, 2010, the 30-day option granted to the underwriters expired unexercised. Pursuant to the Contribution Agreement, 2,625,000 common units were issued to Sponsor Holdings on June 11, 2010.

At December 31, 2012, Niska Partners had 34,492,245 common units and 33,804,745 subordinated units outstanding. Of these amounts, 16,992,245 common units and all of the subordinated units are owned by Sponsor Holdings, along with a 1.98% Managing Member’s interest in the Company and all of the Company’s IDRs. Including all of the common and subordinated units owned by Sponsor Holdings, along with the 1.98% Managing Member’s interest, Sponsor Holdings has a 74.88% ownership interest in the Company, excluding the IDRs. The remaining 17,500,000 common units, representing a 25.12% ownership interest excluding the IDRs, are owned by the public.

Niska Partners operates the Countess and Suffield gas storage facilities (collectively, the AECO Hub™) in Alberta, Canada, and the Wild Goose and Salt Plains gas storage facilities in California and Oklahoma, respectively. Each of these facilities markets gas storage services in addition to optimizing storage capacity with its own proprietary gas purchases.

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, 2012.

In the opinion of management, the accompanying consolidated financial statements of Niska Partners, which are unaudited except that the balance sheet at March 31, 2012 is derived from audited financial statements, include all adjustments necessary to present fairly Niska Partners’ financial position as of December 31, 2012, the results of Niska Partners’ operations for the three and nine months ended December 31, 2012 and 2011, along with its cashflows for the nine months ended December 31, 2012 and 2011. The results of operations for the three and nine months ended December 31, 2012 are not necessarily representative of the results to be expected for the full fiscal year ending March 31, 2013.  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, 2012.

5

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 March 2013 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,
	2012			2012
Senior Notes due 2018	$	643,790		$	643,790
Revolving credit facility	124,000			150,000
Total	767,790			793,790
Less portion classified as current	(124,000		)	(150,000		)
	$	643,790		$	643,790

Senior Notes

On March 5, 2010, Niska Partners, through its subsidiaries Niska Gas Storage US, LLC (“Niska US”) and Niska Gas Storage Canada ULC (“Niska Canada”), completed a non-public offering of 800,000 units, each unit consisting of $218.75 principal amount of 8.875% senior notes due 2018 of Niska US and $781.25 principal amount of 8.875% senior notes of Niska Canada (the “Senior Notes”). The Senior Notes were sold for par value of $800.0 million in an offering exempt from registration under the Securities Act. In March 2011 the notes were exchanged for new Senior Notes with identical terms, except that the new Senior Notes have been registered under the Securities Act of 1933 and generally do not contain restrictions on transfer.

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, 2012, the estimated fair value of the Senior Notes was $653.4 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 flow (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 $197.1 million as at December 31, 2012.

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), Niska Partners is generally permitted to incur additional debt obligations beyond the Senior Notes and its $400 million Credit Agreement (discussed below).

6

3. Debt (continued)

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.

At December 31, 2012, the fixed charge coverage ratio was 2.2 to 1.0 and Niska Partners was permitted to pay the distribution described in Note 13. When the ratio declines below 2.0 to 1.0 the Company is restricted in its ability to issue new debt.

$400 Million Credit Agreement

On June 29, 2012, Niska Partners, through its subsidiaries, Niska Gas Storage US, LLC and AECO Gas Storage Partnership, completed an amendment and restatement of its senior secured asset-based revolving credit facilities, consisting of a U.S. revolving credit facility and a Canadian revolving credit facility (the “Credit Facilities” or the “$400 million Credit Agreement”). The $400 million Credit Agreement provides for revolving loans and letters of credit in an aggregate principal amount of up to $200 million for each of the U.S. revolving credit facility and the Canadian revolving credit facility. Subject to certain conditions, each of the revolving credit facilities may be expanded up to a maximum of $100.0 million in additional commitments, and the commitments in each facility may be reallocated on terms and according to procedures to be determined. Loans under the U.S. revolving facility will be denominated in U.S. dollars and loans under the Canadian revolving facility may be denominated, at the Company’s option, in either U.S. or Canadian dollars. Each revolving credit facility matures on June 29, 2016. A loss related to this transaction amounted to $0.6 million representing a portion of the deferred financing costs associated with the original agreement that were written off.

As at December 31, 2012, $124.0 million in borrowings, with a weighted average interest rate of 3.64%, were outstanding under the Credit Facilities. Amounts committed in support of letters of credit totaled $3.3 million at December 31, 2012 (March 31, 2012 - $5.8 million). Any borrowings under the $400 million Credit Agreement are classified as current.

Borrowings under the Credit Facilities are limited to a borrowing base calculated as the sum of specified percentages of eligible cash and cash equivalents, eligible accounts receivable, the net liquidating value of hedge positions in broker accounts, eligible inventory, issued but unused letters of credit, and certain fixed assets minus the amount of any reserves and other priority claims. Borrowings will bear interest at prevailing market rates, which (1) in the case of U.S. dollar loans can be either fixed rate plus an applicable margin or, at the Company’s option, a base rate plus an applicable margin, and (2) in the case of Canadian dollar loans can be either the bankers’ acceptance rate plus an applicable margin or, at the Company’s option, a prime rate plus an applicable margin. 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, 2012, the borrowing base collateral totaled $376.0 million.

7

3. Debt (continued)

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, 2012, Niska Partners was in compliance with all covenant requirements under 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, 2012.

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 risk. 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.

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.

8

4. Risk Management Activities and Financial Instruments (continued)

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, 2012, 63.1 Bcf of natural gas inventory was offset with financial contracts, representing 98.7% 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, 2012 are 3.4 Bcf and 0.0 Bcf, respectively. As of December 31, 2012 and March 31, 2012, the volumes of inventories which were economically hedged using each type of contract were:

	December 31,	March 31,
	2012	2012
Forwards	(0.2) Bcf	—
Futures	36.1 Bcf	8.5 Bcf
Swaps	27.2 Bcf	60.3 Bcf
Options	—	—
	63.1 Bcf	68.8 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, 2012 and 2011, no trade receivables were deemed to be uncollectible. It is management’s opinion that no allowance for doubtful accounts is required at December 31, 2012 or March 31, 2012 on 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 24.2% of revenues for the nine months ended December 31, 2012 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 66.3% of Niska Partners’ commodity risk management assets at December 31, 2012. 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.

9

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 December 31, 2012, Niska Partners was only exposed to interest rate risk resulting from the variable rates associated with its $400 million Credit Agreement of which $124.0 million was drawn at December 31, 2012.

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 US dollar could positively or negatively affect earnings. Niska Partners is exposed to cash flow risk to the extent that Canadian currency outflows do not match 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, 2012 was $73.0 million (March 31, 2012 - $115.4 million). These contracts expire on various dates between January 1, 2013 and August 1, 2014. Niska Partners has not elected hedge accounting treatment for financial reporting purposes and, 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, 2012 and March 31, 2012:

	Energy			Currency
December 31, 2012	Contracts			Contracts			Total
Short-term risk management assets	$	74,018		$	187		$	74,205
Long-term risk management assets	9,248			—			9,248
Short-term risk management liabilities	(20,396		)	(461		)	(20,857		)
Long-term risk management liabilities	(7,116		)	(195		)	(7,311		)
	$	55,754		$	(469	)	$	55,285

	Energy			Currency
March 31, 2012	Contracts			Contracts			Total
Short-term risk management assets	$	140,323		$	347		$	140,670
Long-term risk management assets	32,683			137			32,820
Short-term risk management liabilities	(58,415		)	(455		)	(58,870		)
Long-term risk management liabilities	(21,243		)	(353		)	(21,596		)
	$	93,348		$	(324	)	$	93,024

10

4. Risk Management Activities and Financial Instruments (continued)

The Company expects to recognize risk management assets and liabilities outstanding at December 31, 2012 into net earnings and comprehensive income in the fiscal periods as follows:

	Energy		Currency
	Contracts		Contracts			Total
Fiscal year ending March 31, 2013	$	42,236	$	187		$	42,423
Fiscal year ending March 31, 2014	11,537		(461		)	11,076
Fiscal year ending March 31, 2015	1,618		(195		)	1,423
Thereafter	363		—			363
	$	55,754	$	(469	)	$	55,285

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,
	2012			2011			2012			2011			Classification
Energy contracts
Realized	$	(24,079	)	$	7,200		$	7,356		$	27,699		Optimization, net
Unrealized	41,515			64,093			(37,616		)	66,606			Optimization, net
Currency contracts
Realized	(146		)	(592		)	(134		)	(5,487		)	Optimization, net
Unrealized	603			(2,357		)	(145		)	8,102			Optimization, net
	$	17,893		$	68,344		$	(30,539	)	$	96,920

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.

11

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, 2012	Level 1		Level 2		Level 3		Total
Assets
Commodity derivatives	$	—	$	83,266	$	—	$	83,266
Currency derivatives	—		187		—		187
Total assets	—		83,453		—		83,453
Liabilities
Commodity derivatives	—		27,512		—		27,512
Currency derivatives	—		656		—		656
Total liabilities	—		28,168		—		28,168
Net	$	—	$	55,285	$	—	$	55,285

March 31, 2012	Level 1		Level 2		Level 3		Total
Assets
Commodity derivatives	$	—	$	173,006	$	—	$	173,006
Currency derivatives	—		484		—		484
Total assets	—		173,490		—		173,490
Liabilities
Commodity derivatives	—		79,658		—		79,658
Currency derivatives	—		808		—		808
Total liabilities	—		80,466		—		80,466
Net	$	—	$	93,024	$	—	$	93,024

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 nine months ended December 31, 2012 or 2011.

6. Members’ Equity

Limited Liability

No member of Niska Partners will be obligated personally for any obligation of the Company solely by reason of being a member.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Limited Liability Company Act, or the Delaware Act, Niska Partners may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, members who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the distribution amount.  A purchaser of common units will be liable for the obligations of the transferor to make contributions to us that are known to such purchaser at the time it became a member and for unknown obligations if the liabilities could be determined from the Company’s Operating Agreement.

12

6. Members’ Equity (Continued)

Phantom Unit Performance Plan (the “PUPP”)

The Company maintains a compensatory PUPP plan (“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. During the nine months ended December 31, 2012, 695,349 Phantom Units were granted at a weighted average price of $9.99.  During the nine months ended December 31, 2011, 518,425 Phantom Units were granted at a weighted average price of $21.95.

The Plan is administered by the Compensation Committee of the Board of Directors.  The Plan currently 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, 2012, 2,076,398 units (March 31, 2012 - 2,862,049 units) were available for grant.

The following is a reconciliation of Phantom Units Outstanding as of December 31, 2012:

			Number of
	Number of Time-		Performance-Based
	Based Units		Units		Total Units
Balance at March 31, 2012	159,681		197,165		356,846
Granted	409,812		285,537		695,349
Forfeited	(32,038	)	(209,157	)	(241,195	)
Distribution equivalent rights	65,551		24,751		90,302
Balance at December 31, 2012	603,006		298,296		901,302

Unit-based compensation costs for the three and nine months ended December 31, 2012 were $1.3 million and $5.0 million respectively ($nil and $0.3 million for the three and nine months ended December 31, 2011, respectively).

13

6. Members’ Equity (Continued)

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.

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2012			2011			2012			2011
Numerator:
Net earnings (loss) attributable to Niska Partners	$	10,419		$	(213,630	)	$	(42,323	)	$	(181,414	)
Less:
Managing Member’s interest	(206		)	4,230			838			3,595
Net earnings (loss) attributable to common and subordinated unitholders	$	10,213		$	(209,400	)	$	(41,485	)	$	(177,819	)
Denominator:
Basic:
Weighted average units outstanding	68,296,990			68,296,990			68,296,990			67,915,046
Diluted:
Weighted average units outstanding	68,296,990			68,296,990			68,296,990			67,915,046
Earnings (loss) per unit:
Basic	$	0.15		$	(3.07	)	$	(0.61	)	$	(2.62	)
Diluted	$	0.15		$	(3.07	)	$	(0.61	)	$	(2.62	)

7. Optimization Revenue

Optimization, net consists of the following:

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2012			2011			2012			2011
Realized optimization revenue, net	$	(9,542	)	$	(9,054	)	$	36,316		$	29,018
Unrealized risk management gains (losses)	42,118			61,736			(37,760		)	74,708
Write-down of inventory	—			—			(22,281		)	—
Total	$	32,576		$	52,682		$	(23,725	)	$	103,726

8. Income Taxes

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

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2012			2011			2012			2011
Income tax benefit	$	(542	)	$	(593	)	$	(19,200	)	$	(11,084	)
Effective income tax rate	(5		)%	0		%	31		%	6		%

14

8. Income Taxes (Continued)

Income tax (benefit) expense was a benefit of $19.2 million for the nine months ended December 31, 2012 compared to a benefit of $11.1 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 taxable Canadian entities.

The effective tax rate for the three and nine months ended December 31, 2012 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 tax rate.

9. Accrued Liabilities

Niska Partners’ accrued liabilities consist of the following:

	December 31,		March 31,
	2012		2012
Accrued gas purchases	$	18,495	$	17,688
Accrued interest	17,188		3,727
Other accued liabilities	16,525		15,878
	$	52,208	$	37,293

10. Changes in Non-Cash Working Capital

Changes in non-cash working capital for the nine months ended December 31, 2012 and 2011 consists of the following:

	Nine Months Ended
	December 31,
	2012			2011
Margin deposits	$	(33,215	)	$	94,746
Trade receivables	(2,003		)	(1,231		)
Accrued receivables	16,776			3,531
Natural gas inventory	17,801			(125,550		)
Prepaid expenses	1,310			1,158
Other assets	367			(392		)
Trade payables	454			(1,198		)
Accrued liabilities	19,608			31,793
Deferred revenue	11,318			5,118
Other long-term liabilities	—			102
Total	$	32,416		$	8,077

During the nine months ended December 31, 2012, changes in non-cash working capital include the receipt of proceeds of $18.0 million and an increase in accrued receivables of $14.6 million 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.

15

11. Supplemental Cash Flow Disclosures

	Nine Months Ended
	December 31,
	2012			2011
Interest paid	$	37,332		$	41,638
Taxes (recovered) paid	$	(38	)	$	1,107
Interest capitalized	$	2,928		$	2,910
Non-cash increase in working capital related to property, plant and equipment classified as operating activity	$	14,648		$	—
Non-cash increase (decrease) in working capital related to property, plant and equipment classified as investing activities	$	5,560		$	(5,745	)

12. Segment Disclosures

Niska Partners’ 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.

Since inception, Niska Partners has operated along functional lines in their commercial, engineering, and operations teams for operations in Alberta, California, and the U.S. Midcontinent. All operating areas and facilities offer the same services: long-term firm contracts, short-term firm contracts, and optimization. All services are delivered using reservoir storage. Niska Partners measures profitability consistently at each operating area based on revenues and earnings before interest, taxes, depreciation and amortization, and unrealized risk management gains and losses. Niska Partners has aggregated its operating segments into one reportable segment for all periods presented.

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

16

12. Segment Disclosures (continued)

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

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2012		2011		2012			2011
Net realized revenues
U.S.	$	7,633	$	16,708	$	38,368		$	55,599
Canada	24,080		11,460		94,981			81,020
Net unrealized revenues
U.S.	16,476		15,561		(11,617		)	26,279
Canada	25,642		46,175		(26,143		)	48,429
Inter-entity
U.S.	—		—		—			—
Canada	—		—		—			—
	$	73,831	$	89,904	$	95,589		$	211,327

	December 31,		March 31,
	2012		2012
Long-lived assets (at period end)
U.S.	$	414,792	$	413,862
Canada	864,614		917,249
	$	1,279,406	$	1,331,111

13. Subsequent Events

Distributions

On January 30, 2013, the Board of Directors of Niska Partners approved a distribution of $0.35 per common unit, payable on February 15, 2013 to unitholders of record on February 11, 2013. The total distribution is expected to be approximately $12.3 million. No distribution was declared on the Company’s subordinated units.

17

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 our Annual Report on Form 10-K for the fiscal year ended March 31, 2012.

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, 2012 and remained unchanged as of December 31, 2012.

Overview of Our Business

We operate the Countess and Suffield gas storage facilities (collectively, the AECO HubTM) 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 225.5 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

There have been no material changes in the disclosure made in our Annual Report on Form 10-K for the fiscal year ended March 31, 2012 regarding this matter.

18

Results of Operations

A summary of financial data for each of the three and nine months ended December 31, 2012 and 2011 is as follows:

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2012			2011			2012			2011
	(unaudited)						(unaudited)
Consolidated Statement of Earnings (Loss) and Comprehensive Income (Loss) Data:
Revenues
Long-term contract	$	26,492		$	28,994		$	82,283		$	88,069
Short-term contract	14,763			8,228			37,031			19,532
Optimization, net	32,576			52,682			(23,725		)	103,726
	73,831			89,904			95,589			211,327
Expenses (income)
Operating	8,330			9,702			25,250			34,881
General and administrative	8,417			6,015			26,332			20,482
Depreciation and amortization	14,831			13,115			39,896			33,922
Loss on disposal of assets	15,072			—			15,072			—
Interest	17,279			19,598			50,459			57,620
Impairment of goodwill	—			250,000			—			250,000
Loss on extinguishment of debt	—			5,147			599			6,030
Foreign exchange losses (gains)	22			557			(314		)	939
Other expense (income)	3			(7		)	(182		)	(49		)
Income (loss) before income taxes	9,877			(214,223		)	(61,523		)	(192,498		)
Income tax benefit	(542		)	(593		)	(19,200		)	(11,084		)
Net earnings (loss) and comprehensive income (loss)	$	10,419		$	(213,630	)	$	(42,323	)	$	(181,414	)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Earnings (Loss)
Net earnings (loss)	$	10,419		$	(213,630	)	$	(42,323	)	$	(181,414	)
Add/(deduct):
Interest expense	17,279			19,598			50,459			57,620
Income tax benefit	(542		)	(593		)	(19,200		)	(11,084		)
Depreciation and amortization	14,831			13,115			39,896			33,922
Unrealized risk management (gains) losses	(42,118		)	(61,736		)	37,739			(74,708		)
Loss on disposal of assets	15,072			—			15,072			—
Impairment of goodwill	—			250,000			—			250,000
Loss on extinguishment of debt	—			5,147			599			6,030
Foreign exchange losses (gains)	22			557			(314		)	939
Other expense (income)	3			(7		)	(182		)	(49		)
Write-down of inventory	—			—			22,281			—
Adjusted EBITDA	14,966			12,451			104,027			81,256
Less:
Cash interest expense, net	16,421			18,626			47,882			54,602
Income taxes (recovered) paid	(31		)	352			(38		)	1,107
Maintenance capital expenditures	193			1,274			1,107			1,436
Other expense (income)	3			(7		)	(182		)	(49		)
Cash Available for Distribution	$	(1,620	)	$	(7,794	)	$	55,258		$	24,160

19

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 and the effects of unrealized gains or losses on interest rate swaps), 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.

20

Revenues

Revenues for the three and nine months ended December 31, 2012 and 2011, respectively, consisted of the following:

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2012			2011			2012			2011
	(unaudited)						(unaudited)
Long-term contract revenue	$	26,492		$	28,994		$	82,283		$	88,069
Short-term contract revenue	14,763			8,228			37,031			19,532
Realized optimization, net	(9,542		)	(9,054		)	36,316			29,018
Unrealized risk management gains (losses)	42,118			61,736			(37,760		)	74,708
Write-down of inventory	—			—			(22,281		)	—
Total revenue	$	73,831		$	89,904		$	95,589		$	211,327

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

LTF Revenues.  LTF revenues for the three months ended December 31, 2012 declined by $2.5 million (9%) compared to the three months ended December 31, 2011. LTF revenues for the nine months ended December 31, 2012 declined by $5.8 million (7%) compared to the nine months ended December 31, 2011. Lower average rates for LTF contracts were obtained in the three and nine months ended December 31, 2012 compared to the three and nine months ended December 31, 2011. These lower contract rates were largely offset by additional storage capacity which we allocated to our LTF strategy in the current fiscal year.  In addition, lower volumes of gas cycled in the current year resulted in $1.2 million and $2.1 million less fuel and commodity fee revenue in the three and nine months ended December 31, 2012. Fluctuations in exchange rates between the Canadian and U.S. dollar increased revenues in the three months ended December 31, 2012 by $0.2 million and reduced revenues in the nine months ended December 31, 2012 by $0.7 million, compared to the same periods last year.

STF Revenues.  STF revenues for the three months ended December 31, 2012 increased by $6.5 million (79%) compared to the three months ended December 31, 2011. STF revenues for the nine months ended December 31, 2012 increased by $17.5 million (90%) compared to the nine months ended December 31, 2011.  These increases resulted from more capacity being utilized for this strategy compared to the respective periods in the prior year.

Optimization Revenues.  Net optimization revenue, including realized and unrealized gains and losses, along with write downs of proprietary optimization inventories, for the three months ended December 31, 2012 decreased by $20.1 million (38%) compared to the three months ended December 31, 2011. Net optimization revenue for the nine months ended December 31, 2012 decreased to a loss of $23.7 million from net optimization revenue of $103.7 million for the nine months ended December 31, 2011. 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 any inventory write downs, which cause our reported revenues to fluctuate from period to period. However, because substantially all inventory is economically hedged, any inventory write downs are offset by hedging gains and any unrealized hedging losses will be offset by realized gains from the future sale of physical inventory. The components of optimization revenues are as follows:

·Natural gas market conditions. During the first quarter of the fiscal year, natural gas prices fell in response to high levels of supply. During the second and third quarters, prices trended upward as hot weather and low natural gas prices contributed to record coal-to-gas switching in the power generation sector. Low natural gas prices in the first quarter created a favorable spread environment that encouraged us to capture incremental revenues through the repositioning of inventory deliveries and related economic hedges to higher priced months later in the summer and into winter. In doing so, we recognized financial gains in the first two quarters and losses in the third quarter of the fiscal year.

21

·Realized Optimization Revenue, net.  During the three month period ended December 31, 2012, we realized losses on financial hedges 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 losses realized in the third quarter only partially offset the gains realized during the first two quarters of the fiscal year. As a result, over the nine month period ended December 31, 2012, we realized a net gain on financial hedges. Limited physical deliveries occurred during the three and nine month periods because the overall market was characterized by increasing prices in future periods. These conditions caused us to position physical deliveries, with associated new hedges, in future periods.  By contrast, in the three and nine month periods ended December 31, 2011, we realized gains on physical sales of optimization inventory as a result of a strong spot market for natural gas. The three month and nine month periods ended December 31, 2012 include $2.8 million and $7.7 million in optimization revenue related to our marketing business, compared to $3.0 and $8.5 million realized during the three month and nine month periods ended December 31, 2011.

·Unrealized Risk Management Gains (Losses).  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. In the prior year, unrealized risk management gains resulted from increases in the value of financial hedges due to decreases in natural gas prices relative to the average contract price for the three and nine month period. The three month and nine month periods ended December 31, 2012 include $0.2 million in unrealized risk management losses and $3.7 million in unrealized risk management gains related to our marketing business, compared to $0.2 million in unrealized risk management gains and $1.9 million in unrealized risk management losses during the three month and nine month periods ended December 31, 2011.

·Write-Down of Inventory. 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 to the lower of cost or market value. This resulted in adjustments of $22.3 million, all of which occurred in the three months ended June 30, 2012.

Operating Expenses

Operating expenses for the three and nine months ended December 31, 2012 and 2011 consisted of the following:

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2012		2011		2012		2011
	(unaudited)				(unaudited)
General operating costs, including insurance, lease costs, safety and training costs	$	4,383	$	4,214	$	13,054	$	15,922
Salaries and benefits	1,837		1,463		5,475		4,929
Fuel and electricity	1,591		3,490		5,232		11,999
Maintenance	519		535		1,489		2,031
Total operating expenses	$	8,330	$	9,702	$	25,250	$	34,881

22

Operating expenses for the quarter ended December 31, 2012 decreased by $1.4 million (14%) compared to the quarter ended December 31, 2011. Operating expenses for the nine months ended December 31, 2012 decreased by $9.6 million (28%) compared to the same period last year. Lower lease costs, which are included in general operating expenses, resulted from the sublease and renegotiation of certain third-party lease agreements. These changes reduced lease costs by $0.9 million and $2.6 million, respectively in the three and nine month periods ended December 31, 2012 compared to the comparable periods in the prior year.  Higher storage inventories in the beginning of our fiscal year reduced current year inventory cycling by over fifty seven percent in the current fiscal year compared to the same period last year.  The reduction in inventory cycling, coupled with significantly lower electricity prices in the current year, resulting from the absence of significant price spikes that were seen in the prior year, contributed to reductions in fuel, electricity and other operating costs of $1.7 million and $8.3 million in the three and nine month periods ended December 31, 2012, respectively, compared to the same periods in the prior year. Offsetting these savings was an increase in property and pipeline taxes of $1.1 million and $1.3 million in the three months and nine months ended December 31, 2012 largely driven by the absence of a prior year property tax settlement that resulted in a refund last year.

General and Administrative Expenses

General and administrative expenses for the three and nine months ended December 31, 2012 and 2011 consisted of the following:

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2012		2011		2012		2011
	(unaudited)				(unaudited)
Compensation costs	$	5,520	$	1,945	$	16,759	$	10,169
General costs, including office and information technology costs	1,077		1,225		3,316		2,832
Legal, audit and regulatory costs	1,820		2,845		6,257		7,481
Total general and administrative expenses	$	8,417	$	6,015	$	26,332	$	20,482

General and administrative expenses for the quarter ended December 31, 2012 increased by $2.4 million (40%) compared to the quarter ended December 31, 2011. General and administrative expenses for the nine months ended December 31, 2012 increased by $5.9 million (29%) compared to the same period last year. Compensation costs increased principally as a result of higher incentive compensation accruals of $2.7 million on a quarterly basis and $5.6 million on a year to date basis.  These increases were partially offset by lower professional fees incurred during the three and nine months ended December 31, 2012 compared to the same periods last year.

Depreciation and Amortization Expense

Depreciation and amortization expense for the quarter ended December 31, 2012 increased by $1.7 million (13%) compared to the quarter ended December 31, 2011. Depreciation and amortization expense for the nine months ended December 31, 2012 increased by $6.0 million (18%) compared to the same period last year.  The increase for the three and nine month periods was primarily attributable to the additional depreciation from equipment purchased as part of the capacity expansion on of our facilities and higher cushion gas migration at one of our facilities which is recorded in depreciation and amortization expense.

23

Interest Expense

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2012			2011			2012			2011
	(unaudited)						(unaudited)
Interest on senior notes	$	14,284		$	15,794		$	42,852		$	51,033
Interest on revolving credit facility	2,078			3,457			7,202			5,653
Amortization of deferred charges	834			972			2,577			3,018
Other interest	225			490			756			826
	17,421			20,713			53,387			60,530
Less: Capitalized interest	(142		)	(1,115		)	(2,928		)	(2,910		)
Total interest expenses	$	17,279		$	19,598		$	50,459		$	57,620

Interest expense for the three months ended December 31, 2012 decreased by $2.3 million (12%) compared to the three months ended December 31, 2011. Interest expense for the nine months ended December 31, 2012 decreased by $7.2 million (12%) compared to the same period last year.  The repurchase of $156.2 million in Senior Notes during the prior fiscal year reduced interest costs by $2.4 million for the three months ended December 31, 2012 and $8.2 million for the nine months ended December 31, 2012. This decrease was partially offset by higher interest costs incurred due to increased use of our $400 million revolving credit facility to finance our optimization strategy. Capitalized interest decreased by $1.0 million in the three month period ended December 31, 2012 compared to the three month period ended December 31, 2011 due to the completion of the Company’s capacity expansion at its Wild Goose facility.

Loss on Disposal of Assets

During the quarter ended December 31, 2012, we sold excess cushion gas with a recorded cost of $33.6 million for $18.5 million at the AECO and Salt Plain facilities, which resulted in a loss of $15.1 million.

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 for the nine months ended December 31, 2012. The loss in the prior year resulted from the repurchase of Senior Notes at a premium during that period.

Income Taxes

Income tax benefit was $0.5 million for the three months ended December 31, 2012 compared to a benefit of $0.6 million for the same period of the prior year.  We had an income tax benefit of $19.2 million for the nine months ended December 31, 2012, compared to a benefit of $11.1 million for the nine months ended December 31, 2011. Income tax benefit in the current three and nine month periods is primarily due to the Canadian subsidiaries having aggregate losses for tax purposes for the period.

The effective tax rate for the three and nine months ended December 31, 2012 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.

24

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. As of December 31, 2012, we do not anticipate any expansion projects or acquisitions that would require additional debt or equity financing.

Our principal debt covenant is our fixed charge coverage ratio (“FCCR”), which is included in both our $400 million Credit Agreement and the indenture on 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.  At December 31, 2012, our FCCR was 2.2 to 1.0.  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.

In order to enhance our financial flexibility, in June 2012 we amended and restated our $400 million Credit Agreement.  The new agreement is substantially the same as the prior agreement, except that the maturity has been extended from March 5, 2014 to June 29, 2016, and pricing has been improved due to a more favorable pricing grid based on leverage levels and the elimination of a floor of 150 basis points on LIBOR-based borrowings.  At December 31, 2012, the unutilized capacity related to our credit facility amounts to $253.7 million.

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.

25

Cash Flows from Operations and Investing Activities

The following table summarizes our sources and uses of cash for the nine months ended December 31, 2012 and 2011, respectively:

	Nine Months Ended
	December 31,
	2012			2011
	(unaudited)
Operating Activities:
Net loss	$	(42,323	)	$	(181,414	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Unrealized foreign exchange losses	30			88
Deferred income tax benefit	(19,222		)	(11,178		)
Unrealized risk management losses (gains)	37,739			(74,708		)
Depreciation and amortization	39,896			33,922
Deferred charges amortization	2,577			3,018
Loss on extinguishment of debt	599			6,030
Loss on disposal of assets	15,072			—
Write-down of inventory	22,281			—
Impairment of goodwill	—			250,000
Changes in non-cash working capital	32,416			8,077
Net cash provided by operating activities	89,065			33,835
Net cash used in investing activities	(27,044		)	(43,632		)
Net cash used in financing activities	(63,752		)	(93,146		)
Effect of translation of foreign currency on cash and cash equivalents	49			(206		)
Net decrease in cash and cash equivalents	$	(1,682	)	$	(103,149	)

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 under each of our LTF, STF and optimization activities and 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, 2012, we realized a significant increase in cash from operations compared to the nine months ended December 31, 2011.  This variance resulted from the increase in Adjusted EBITDA recognized in the current period compared to last year, as well as the large variances in non-cash working capital discussed below.

26

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

	Nine Months Ended
	December 31,
	2012			2011
	(unaudited)
Changes in non-cash working capital:
Margin deposits	$	(33,215	)	$	94,746
Trade receivables	(2,003		)	(1,231		)
Accrued receivables	16,776			3,531
Natural gas inventory	17,801			(125,550		)
Prepaid expenses	1,310			1,158
Other assets	367			(392		)
Trade payables	454			(1,198		)
Accrued liabilities	19,608			31,793
Deferred revenue	11,318			5,118
Other long-term liabilities	—			102
Net changes in non-cash working capital	$	32,416		$	8,077

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 increased to $32.4 million compared to $8.1 million in the same period of the prior year, largely as a result of changes in our inventory and margin deposit balances. For the period ended December 31, 2012, consistent with the same period in the prior year, we continued to allocate a significant proportion of our capacity to our optimization strategy, accumulating inventory and economically hedging it forward to future periods. However, unlike the prior year, where we purchased a net amount of $125.6 million in inventory, we entered the current fiscal year ending March 31, 2013 with substantially larger balances of proprietary inventories (approximately 69 Bcf of inventory at March 31, 2012 compared to approximately 32 Bcf at March 31, 2011). Accordingly, substantially less cash was invested in inventory during the first three quarters of fiscal 2013.  In addition, softer forward commodity prices during the prior period resulted in a return of substantial cash that had been posted as margin deposits in the prior year.

27

Investing Activities

Substantially all of our cash used for investing activities consisted of capital expenditures in each of the nine months ended December 31, 2012 and 2011. Capital expenditures in each nine month period consisted of the following:

	Nine Months Ended
	December 31,
	2012			2011
	(unaudited)
Maintenance capital	$	1,107		$	1,436
Expansion capital	22,577			47,941
Total capital expenditures	23,684			49,377
Change in accrued capital expenditures	5,560			(5,745		)
Proceeds on disposal of assets	(2,200		)	—
Net cash used in investing activities	$	27,044		$	43,632

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 relates to a project at our Wild Goose facility, including $0.8 million relating to a capital lease.

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. Total expansion capital spending during the twelve months ending March 31, 2013 is currently expected to be $25.0 million.

Proceeds on disposal of assets represent cash received for excess pipe material, acquired as part of a development project, sold at its carrying value of $2.2 million.

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, 2012 regarding this matter.

At December 31, 2012, 63.1 Bcf of natural gas inventory was economically hedged, representing 98.7% 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 that inventory would increase by $64.0 million, the fair value or mark-to-market value of our economic hedges would decrease by $63.1 million, and the impact due to the non-economically hedged position would be $0.9 million. Similarly, if the price of natural gas declined by $1.00 per Mcf, the value of that inventory would decrease by $64.0 million while the fair value of our economic hedges would increase by $63.1 million and the impact due to the non-economically hedged position would be $0.9 million. 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, 2012 are 3.4 Bcf and 0.0 Bcf, respectively.

At December 31, 2012, we were exposed to interest rate risk resulting from the variable rates associated with our $400 million Credit Agreement. A balance of $124.0 million was drawn on the Credit Facilities at December 31, 2012.  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, 2012, a one percent increase or decrease in interest rates would have an impact of approximately $1.2 million on our interest expense.

28

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, 2012. 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 Exchange Act is recorded, processed, summarized and reported, within the time periods specified in 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 Securities Exchange Act of 1934) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

29

PART II—OTHER INFORMATION

Item 1.  Legal Proceedings

For information on legal proceedings, see Part 1, 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

There have been no material changes from the risk factors described previously in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, 2012, filed on June 11, 2012.

30

Item 6.  Exhibits

Exhibit Number		Description
3.1	—	Certificate of formation of Niska Gas Storage Partners LLC (incorporated by reference to exhibit 3.1 to Amendment No. 2 to the Company’s registration statement on Form S-1 (Registration No. 333-165007), filed on April 15, 2010)
3.2	—	First Amended and Restated Operating Agreement of Niska Gas Storage Partners LLC dated May 17, 2010 (incorporated by reference to exhibit 3.1 of the Company’s Current Report on Form 8-K filed on May 19, 2010)
10.1	—	Amended and Restated Credit Agreement dated June 29, 2012 among Niska Gas Storage US, LLC, as US Borrower, and AECO Gas Storage Partnership, as Canadian Borrower, Niska Gas Storage Partners LLC, as Holdings, Royal Bank of Canada, as Administrative Agent and Collateral Agent and the other lenders party thereto (incorporated by reference to exhibit 10.1 of the Company’s Current Report on Form 8-K filed on March 29, 2010)
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.

31

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: February 4, 2013	By:	/s/ VANCE E. POWERS
		Vance E. Powers
		Chief Financial Officer
		(Principal Accounting Officer)

32