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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-K


ý

 

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

For the fiscal year ended March 31, 2011

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: 001-34733

Niska Gas Storage Partners LLC
(Exact name of registrant as specified in its charter)

Delaware
(Exact name of registrant
as specified in its charter)
  27-1855740
(I.R.S. Employer
Identification No.)

1001 Fannin Street, Suite 2500

 

 
Houston, Texas   77002
(Address of principal executive offices)   (Zip Code)

(281) 404-1890
(Registrant's telephone number, including area code)

None
(Former name, former address and former fiscal year, if changed since last report)

          Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class   Name of Exchange on which Registered
Common Units Representing Limited
Liability Company Interests
  New York Stock Exchange

          SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

 
  Title of Class    
    None    

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

          Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o    No ý

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

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

          Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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 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 o   Non-accelerated filer ý
(Do not check if a
smaller reporting company)
  Smaller reporting company o

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

          As of September 30, 2010, the aggregate market value of the registrant's common units held by non-affiliates was $339,500,000. This calculation of such market value should not be construed as an admission or conclusion by the registrant that any person is in fact an affiliate of the registrant.

          As of June 10, 2011, the registrant had 33,804,745 common units and 33,804,745 subordinated units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None


Table of Contents


TABLE OF CONTENTS

 
   
  Page  

 

PART I

     

Item 1.

 

Business

    1  

Item 1A.

 

Risk Factors

    15  

Item 1B.

 

Unresolved Staff Comments

    36  

Item 2.

 

Properties

    36  

Item 3.

 

Legal Proceedings

    37  

 

PART II

   
 

Item 4.

 

(Removed and Reserved)

    37  

Item 5.

 

Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

    37  

Item 6.

 

Selected Financial Data

    41  

Item 7.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

    43  

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risks

    69  

Item 8.

 

Financial Statements and Supplementary Data

    72  

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

    72  

Item 9A.

 

Controls and Procedures

    72  

Item 9B.

 

Other Information

    73  

 

PART III

       

Item 10.

 

Directors, Executive Officers and Corporate Governance

    73  

Item 11.

 

Executive Compensation

    81  

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management

    92  

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

    94  

Item 14.

 

Principal Accounting Fees and Services

    96  

 

PART IV

       

Item 15.

 

Exhibits, Financial Statement Schedules

    96  

 

FINANCIAL STATEMENTS

       

Niska Gas Storage Partners LLC Index to Financial Statements

    F-1  

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GLOSSARY OF KEY TERMS

        As used generally in the energy industry and in this report, the following terms have the meanings indicated below.

Basin   A geological province on land or offshore where hydrocarbons are generated and trapped.

Billion Cubic Feet ("Bcf")

 

The standard volume measure of gas products.

British Thermal Unit ("BTU")

 

British thermal unit, a traditional unit of heat measurement equal to the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit at one atmosphere pressure.

Contracted Capacity

 

The amount of working gas capacity reserved by third parties. Typically subject to fixed demand charges. May involve short-term contracts, typically less than one year, or long-term contracts, with terms longer than one year.

Cushion Gas

 

A quantity of natural gas held within the confines of the gas storage facility and used for pressure support and to maintain a minimum facility pressure. May consist of injected cushion gas or native cushion gas.

Cycle

 

A complete withdrawal and injection of working gas.

Dekatherm ("Dth")

 

Equivalent to one million Btus or one mmBtu. One therm equals one hundred thousand Btus.

Delta Pressuring

 

Operating a gas storage reservoir at a maximum pressure greater than the discovery pressure of the reservoir for the purpose of increasing both the working gas capacity and withdrawal deliverability. While not applicable to every reservoir, generally accepted Delta Pressuring in the gas storage reservoir is up to 160% of the hydrostatic pressure gradient for those reservoirs that have the right characteristics.

Effective Working Gas Capacity

 

The maximum volume of natural gas that can be cost-effectively injected into a storage reservoir and extracted during the normal operation of the storage facility. Effective working gas capacity excludes cushion gas and non-cycling working gas.

EnCana Corporation

 

EnCana Corporation includes its predecessor companies Alberta Energy Company Ltd. and PanCanadian Petroleum Ltd.

GAAP

 

Generally accepted accounting principles in the United States of America.

Gas storage capacity

 

See Effective Working Gas Capacity.

Gigajoule ("GJ")

 

Billion Joules.

Holdco

 

Niska Sponsor Holdings Coöperatief U.A.

Horizontal Well

 

A class of non-vertical wells where the wellbore axis is near horizontal (within approximately ten degrees of the horizontal), or undulating (fluctuating above and below 90 degrees deviation).

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Hub   Geographic location of a natural gas storage facility and multiple pipeline interconnections.

Independent Storage

 

Gas storage facilities owned and operated independently from the pipeline and distribution facilities to which they are interconnected.

Injection Capacity

 

The amount of natural gas that can be injected into a storage facility. Usually stated in MMcf per day, Bcf per day, Mcf per day, Dth per day, mmBtu per day, GJ per day, TJ per day or PJ per day. Typically stated as the peak or maximum daily amount.

Inventory

 

An amount of Working Gas held within the gas storage facility. It may relate to third-party customer volumes or to owner/operator volumes of working gas.

Injection Rate

 

The rate at which a customer is permitted to inject natural gas into a natural gas storage facility.

Joule

 

A unit of energy equivalent to one watt second or the work done when a current of one ampere passes through a resistance of one ohm for one second. This can be expressed in units of one million joules, known as a Megajoule ("MJ"); one billion joules, known as a Gigajoule ("GJ"); one trillion joules, known as a Terajoule ("TJ"); and one thousand trillion joules, known as a Petajoule ("PJ").

LTF Contracts

 

Long term firm reserved storage contracts.

Manager

 

Niska Gas Storage Management LLC. Also referred to as our manager.

Mcf

 

Thousand cubic feet of natural gas.

MMbtu

 

Million British thermal units. A standard measure of natural gas for pricing purposes, particularly in the U.S.

MMcf

 

Million cubic feet of natural gas.

Natural Gas

 

Several hydrocarbons that occur naturally underground in a gaseous state. Natural gas is normally mostly methane, but other components also include ethane, propane, and butane.

Natural Gas Act

 

Federal law enacted in 1938 that established the Federal Energy Regulation's authority to regulate interstate pipelines.

NGPL

 

Natural Gas Pipeline of America Company

Niska Canada

 

Niska Gas Storage Canada ULC our wholly-owned subsidiary.

Niska Holdings

 

Niska GS Holdings US, L.P. and Niska GS Canada, L.P., collectively.

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Niska Predecessor   When used in a historical context, Niska Predecessor refers to Niska GS Holdings I, L.P. and Niska GS Holdings II, L.P. which were contributed to Niska Gas Storage Partners LLC in connection with our IPO. When used in the present tense or prospectively, Niska Predecessor refers to Niska Gas Storage Partners LLC.

Niska US

 

Niska Gas Storage U.S., LLC, our wholly-owned subsidiary.

Optimization

 

The purchase, storage and sale of natural gas by the storage owner for its own account in order to utilize storage capacity that is (1) not contracted to customers, (2) contracted to customers but underutilized by them or (3) available only on a short term basis.

Reservoir

 

A naturally occurring underground formation that originally contained crude oil or natural gas, or both.

Seismic Survey

 

A technique for mapping the subsurface structure of rocks by measuring the reflections of acoustic waves at various depths. Seismic surveys are used to locate potential oil and gas-bearing structures. Seismic surveys can either be two dimensional or three dimensional.

STF Contracts

 

Short term firm storage contracts.

Withdrawal Capacity

 

The amount of gas that is or can be removed from a natural gas storage facility. Usually stated in MMcf per day, Bcf per day, Mcf per day, Dth per day, MMbtu per day, GJ per day, TJ per day or PJ per day. Typically stated as maximum or peak daily withdrawal capacity.

Withdrawal Rate

 

The rate at which a customer is permitted to withdraw gas from a natural gas storage facility.

Working Gas

 

Natural gas in a storage facility in excess of Cushion Gas.

Working Gas Capacity

 

See Effective Working Gas Capacity.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

        This document includes forward-looking statements. Forward-looking statements are based on management's current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this document. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements 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 discussed elsewhere in this document.

        All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements, the factors described in "Item 1A. Risk Factors" and elsewhere in this report, our reports and registration statements filed from time to time with the SEC and other announcements we make from time to time.

        Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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PART I

        Unless the context clearly indicates otherwise, references in this report to "Niska Predecessor," "we," "our," "us" or similar terms when used in a historical context refer to Niska GS Holdings I, L.P. and Niska GS Holdings II, L.P., which were contributed to Niska Gas Storage Partners LLC in connection with its initial public offering, which was completed on May 17, 2010 (the "IPO"). When used in the present tense or prospectively, those terms refer to Niska Gas Storage Partners LLC and its subsidiaries. References to our "manager" refer to Niska Gas Storage Management LLC. References to the "Carlyle/Riverstone Funds" refer to Carlyle/Riverstone Global Energy and Power Fund II, L.P. and Carlyle/Riverstone Global Energy Power Fund III, L.P. and affiliated entities, collectively. Unless otherwise indicated, all references to "dollars" and "$" in this document are to, and amounts are presented in, U.S. dollars. Unless otherwise indicated, references to storage capacity refer to effective working gas storage capacity.

Item 1.    Business.

    Overview

        We are a Delaware limited liability company formed in 2006 to own and operate natural gas storage assets. We own or contract for approximately 204.5 billion cubic feet, or Bcf, of total gas storage capacity. Our assets are located in key North American natural gas producing and consuming regions and are connected at strategic points on the gas transmission network, providing access to multiple end-use markets. Our locations provide us and our customers with substantial liquidity, meaning access to multiple counterparties for transactions to buy and sell gas. Since our inception in 2006, we have added 60.3 Bcf of new storage capacity through low cost organic expansions, an increase of approximately 42%, bringing our total working gas capacity to 204.5 Bcf at the end of March 31, 2011. This year alone, we were able to organically add 19 Bcf of working gas capacity at an average cost of $1.86 Mcf. We are the largest independent owner and operator of natural gas storage assets in North America, based on our analysis of working gas capacity owned by other storage owners, adjusted according to each such owner's percentage ownership of its respective storage facilities.

        Because the supply of natural gas remains relatively stable over the course of a year compared to the demand for natural gas, which fluctuates seasonally, natural gas storage facilities are needed to reallocate excess gas supply from periods of low demand to periods of high demand. We capitalize on the imbalance between supply of and demand for natural gas by providing our customers and ourselves with the ability to store gas for resale or use in a higher value period. Our natural gas storage facilities allow us to offer our customers "multi-cycle" gas contracts, which permit them to inject and withdraw their natural gas multiple times in one year, providing more flexibility to capture market opportunities. Since our inception, our storage contracts have provided cyclability rates ranging from 1.0 to 6.0 times per year, with an average of 2.2 times.

        Our common units are listed on the New York Stock Exchange, or the NYSE, under the symbol "NKA." You may find more information about us on our website at http://www.niskapartners.com. Our headquarters is located in Houston, TX, and our operations center is located in Calgary, Alberta, Canada.

Recent Developments

        None.


Table of Contents

Organizational Structure

        The following diagram depicts our simplified organizational and ownership structure as at March 31, 2011:

GRAPHIC

Our Relationship with Holdco

        As a result of our IPO, Niska Sponsor Holdings Coöperatief U.A., or Holdco, owns our manager, approximately 48.2% of our outstanding common units, all of our subordinated units and all of our incentive distribution rights

        Over 95% of the equity in Holdco is owned by the Carlyle/Riverstone Funds, with the balance owned by our current and former officers and employees. The Carlyle/Riverstone Funds are affiliated with Riverstone Holdings LLC, or Riverstone. Riverstone, an energy- and power-focused private equity firm founded in 2000, has approximately $17 billion of assets under management across six investment funds. Riverstone conducts buyout and growth capital investments in the midstream, exploration and production, oilfield service, power and renewable sectors of the energy industry. With offices in New York, London and Houston, Riverstone has committed approximately $15.9 billion to 78 investments in North America, Latin America, Europe and Asia. Riverstone's management has substantial experience in identifying, evaluating, negotiating and financing acquisitions and investments.

Management

        Niska Gas Storage Management LLC, or our manager, has a 2% managing member interest in us. Our manager has sole responsibility for conducting our business and for managing our operations. Pursuant to our Operating Agreement, our manager has delegated the power to conduct our business and manage our operations to our board of directors, all of the members of which are appointed by our manager. References to our board refer to the board of directors of Niska Gas Storage Partners LLC as long as the delegation is in effect (or to the board of directors of our manager if such delegation is not in effect). Our board directs the management of our business and presently consists of eight members. Our manager appoints all members to our board, and three of our directors are independent as defined under the independence standards established by the NYSE. For more information about our directors, see "Management—Directors and Executive Officers."

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Our Operations

    Third-Party Gas Storage Contracts

        We store natural gas for a broad range of customers, including financial institutions, marketers, pipelines, power generators, utilities and producers of natural gas. From inception to March 31, 2011, we utilized an average of approximately 84.3% of our operated capacity for storage services provided to third-party customers, and our third-party storage contracts contributed an average of 63.9% of our total realized revenue.

    Long-Term Firm Storage Contracts

        We provide multi-year, multi-cycle storage services to our customers under LTF contracts. The volume-weighted average life of our LTF contracts at March 31, 2011 was 2.6 years. Under our LTF contracts our customers are obligated to pay us monthly reservation fees in exchange for the right to inject, store and withdraw volumes of natural gas on days and for periods selected by them at injection or withdrawal rates up to maximums specified in the contract. The reservation fees are fixed charges owed to us regardless of the actual amount of storage capacity utilized by customers. When customers utilize the capacity that is reserved under these contracts we also collect variable fees based upon the actual volumes of natural gas injected or withdrawn. These variable fees are designed to allow us to recover our variable operating costs and make up a small percentage of the total fees we receive under our LTF contracts.

        Under LTF contracts, the customer has the right, but not the obligation, to store gas in the facility during the term of the contract, up to a specified volume or "inventory capacity." In addition to the total amount of inventory capacity, LTF contracts specify a customer's daily withdrawal and injection rights which increase or decrease as the customer's inventory changes. The maximum injection rate that a customer is typically entitled to is highest when that customer's inventory capacity is empty, reducing as that customer's inventory increases. When a customer's contracted inventory capacity is full, it has no further injection rights. A customer's maximum withdrawal rate is typically highest when its inventory is full, declining incrementally to zero when the customer's inventory is empty. LTF contracts provide the customer with the flexibility to use all, a portion, or none of its capacity and the freedom to inject or withdraw gas up to its daily injection or withdrawal rate, but obligate the customer to remove any injected gas by the end of the contract term.

        Reservation fees comprise over 90% of the revenue received from LTF storage customers, and thus represent a steady and predictable baseline cash flow stream. From inception to March 31, 2011, we utilized an average of approximately 67.6% of our operated capacity for our LTF strategy, and LTF contracts contributed an average of 46.1% of our total realized revenue. Our LTF contracts generated average revenues, including both reservation and variable fees of $1.03 per Mcf.

    Short-Term Firm Storage Contracts

        We also provide services for customers under STF contracts. STF contracts typically have terms of less than one year. Under an STF contract, a customer pays a fixed fee to inject a specified quantity of natural gas on a specified date or dates and to store that gas in our storage facilities until withdrawal on a specified future date or dates. An STF contract differs from an LTF contract in that the customer is obligated to inject and withdraw specified quantities of natural gas on specified dates rather than entitled to utilize injection and withdrawal capacity at its option. Because STF contracts set forth specified future injection and withdrawal dates, we can enter into offsetting transactions to lock in incremental fees as spot and future natural gas prices fluctuate prior to that activity date. From inception to March 31, 2011, we utilized an average of approximately 16.7% of our operated capacity for our STF strategy, and STF contracts contributed an average of 17.8% of our total realized revenue. From inception to March 31, 2011, our STF contracts generated average revenues of $1.61 per Mcf.

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        An example of an STF transaction is when a customer contracts with us in April to inject gas at a steady daily rate in July, when gas prices are low, and to withdraw the same quantity at a steady daily rate in January, when gas prices are higher. This allows the customers to lock in value in April based on the difference between the January and July prices for natural gas and pay us a fee based on this difference.

        Under STF contracts the customer is obligated to perform the injection and withdrawal activities as specified in the contract, thus enabling us to enter into offsetting transactions to capture incremental opportunities as spot and future natural gas prices fluctuate prior to the specified withdrawal date. For example, if, after a customer enters into an STF contract to inject gas in July and to withdraw that gas in January, gas futures prices for January fall below February prices, we might enter into an offsetting STF transaction for the same quantities, with the same or another customer, to inject in January and withdraw in February for a fee based on the January to February spread. The result in January would be that the second transaction offsets the first transaction resulting in no net flow obligation on our storage facility during January, and therefore, a fuel savings. By entering into offsetting transactions, we are able to capture additional opportunities as they are created throughout the year by the volatile gas futures prices.

    Proprietary Optimization

        Our portfolio of third-party customers consists of a strategic mix of customer types, each of which tends to have a storage usage pattern that is different from those of other customers at the facility. This means that even though the withdrawal or injection capability of a facility may be fully contracted, it will generally not be fully utilized on any given day. We purchase, store and sell natural gas for our own account in order to utilize, or optimize, storage capacity and injection and withdrawal capacity that is: (1) not contracted to customers; (2) contracted to customers, but underutilized by them; or (3) available only on a short-term basis. We have a stringent risk policy that limits, among other things, our exposure to commodity price fluctuations by requiring us to promptly enter into a forward sale contract or other hedging transaction whenever we enter into a proprietary purchase contract. Therefore, inventory purchases are matched with forward sales or are otherwise economically hedged so that a margin is effectively locked in promptly after we enter into the purchase. As a result, there are no speculative positions beyond the minimal operational tolerances specified in our risk policy. From inception to March 31, 2011, we utilized an average of approximately 15.7% of our operated capacity for our proprietary optimization strategy, and proprietary optimization revenue, after deducting cost of goods sold, contributed an average of 36.1% of our total realized revenue. From inception to March 31, 2011, our proprietary optimization business generated average margins of $2.61 per Mcf on a realized basis before mark to market gains and losses and inventory writedowns.

        We purchase gas for our own account, inject it and subsequently withdraw and sell the gas. The flexibility arising from purchasing and selling gas for our own account allows us to generate incremental value through our proprietary optimization strategy by capturing spot and intraday opportunities. Unlike STF and LTF storage transactions, proprietary optimization requires us to fund the carrying cost of the inventory with our own working capital.

        Risk management techniques, adapted to the unique aspects of gas storage, enable us to match the capacity at our facilities with the portfolio of long-term and short-term contracts and proprietary optimization transactions at those facilities in order to utilize the maximum amount of capacity available. We utilize New York Mercantile Exchange Inc., or NYMEX, and Intercontinental Exchange, Inc., or ICE, which are regulated exchanges for the purchase and sale of energy products, to hedge our commodity risk with respect to the pricing of natural gas. This helps us reduce potential credit, delivery and supply risks. Generally these are financial swaps and are settled without the requirement for physical delivery. In the case of NYMEX futures, we can enter an EFS (exchange for swaps) to avoid the requirement for delivery.

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    Customers and Counterparties

        Our gas storage customers include a broad mix of gas market participants, including financial institutions, producers, marketers, power generators, pipelines and municipalities. Approximately 99% of the counterparties under our gas storage contracts and proprietary storage optimization transactions either have an investment grade credit rating, provide us with another form of financial assurance, such as a letter of credit or other collateral, or are governmental entities.

        Although during certain reporting periods a large portion of our gross revenues can be attributed to one or two counterparties, these gross revenues reflect the full commodity value of natural gas sales under our optimization strategy and overstate the counterparties' contribution to our net margin (after cost of goods sold) that is more correlated with our net earnings and operating cash flow.

        Our exposure to the volume of business transacted with a natural gas clearing and settlement facility is mitigated by the facility's requirement to post margin deposits to reduce the risk of default.

Our Assets

        Our owned and operated gas storage facilities consist of AECO Hub™ (comprised of two facilities in Alberta, Canada), our Wild Goose storage facility in California and our Salt Plains storage facility in Oklahoma. Our gas storage assets are modern, well-maintained, automated facilities with low maintenance costs, long useful lives and comparatively high injection and withdrawal, or "cycling," capabilities. Our facilities require low amounts of cushion gas, meaning that a relatively small amount of gas is required to remain inside our facilities in order to maintain a minimum facility pressure supporting the working gas. The size and flexibility of our facilities, together with the application of advanced skills in reservoir engineering, drilling, geology and geophysics, enable us to support individual high-cycle contracts in excess of the average physical cycling capabilities of our facilities. In addition to the facilities we own and operate, we also contract for 8.5 Bcf of gas storage capacity on a long-term basis from Natural Gas Pipeline Company of America LLC, or NGPL, on its pipeline system in the mid-continent at cost-of-service based rates that we believe are currently below market rates. The following table highlights certain important design information about our assets:

 
  AECO Hub™    
   
   
   
 
 
  Suffield   Countess   Wild Goose   Salt Plains   NGPL    
 
Name
  Alberta   Alberta   California   Oklahoma   Midcon/Texok   Total  
Location
 

Gas Storage Capacity (Bcf)

    80     68     35     13     8.5     204.5  

Peak Withdrawal (MMcf per day)

    1,800     1,250     700     150     114     4,014  

Peak Injection (MMcf per day)

    1,600     1,150     450     115     57     3,372  

Reservoirs

    5     2     3     1     N/A     11  

Storage Wells

    60     29     15     30     N/A     134  

Compression (horsepower)

    36,000     34,500     20,800     10,000     N/A     101,300  

In Service Date

    1988     2003     1999     1995     N/A     1988 - 2003  

    AECO Hub™

    Overview

        AECO Hub™, our largest operation, is comprised of two facilities in Alberta, Suffield and Countess, which are 75 miles apart but operate as one hub. Due to its high injection and withdrawal capacity (2.8 Bcf per day and 3.1 Bcf per day, respectively), AECO Hub™ supports high cycling customer contracts. AECO Hub™ is the largest natural gas storage provider in western Canada and the largest independent storage hub in North America, based on our analysis of working gas capacity owned by other storage owners, adjusted according to each such owner's percentage ownership of its respective storage facilities. Its location on TransCanada Pipeline's Alberta System with direct access to

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abundant western Canadian natural gas supply and pipeline connections to most major U.S. and Canadian natural gas markets provides us and our customers with significant flexibility and liquidity.

        AECO Hub™ is located in the Western Canadian Sedimentary Basin, or the WCSB, which is the major hydrocarbon basin in Canada and one of the most important gas producing regions in North America. The WCSB accounts for more than 98% of annual Canadian natural gas production and approximately 18% of annual North American natural gas production according to the Canadian National Energy Board, or NEB. Although WCSB production has leveled off in recent years, we expect that Canadian natural gas production will be sustained in future years by new production from large new shale plays in northeast British Columbia, a large remaining conventional natural gas resource base, and eventually Arctic gas from the Mackenzie Delta and Alaska.

        AECO Hub™ is connected to the extensive Alberta System. Most of the gas produced in Alberta flows into the Alberta System, which transports that gas from the well or gas plant to industrial consumers and gas utilities in Alberta and to export pipelines at the Alberta border. Approximately 10.0 Bcf of gas is delivered into the Alberta System each day, and that volume is traded many times over by the gas marketing community. As a result, significant liquidity is available to customers of the AECO Hub™.

        AECO Hub™ has been a central part of the Alberta System since the early 1990s, when the Suffield facility began providing title transfers as a hub service before that service was available on the pipeline. Many transactions were being transacted by storage customers and others at the Suffield facility and a new price index, known as the "AECO Hub™ Price Index," was developed to facilitate price discovery. AECO Hub™ is the most commonly referenced pricing point for Canadian natural gas, and the price of gas in Alberta is often referred to as the "AECO Price."

    AECO Hub™ Facilities

        AECO Suffield and AECO Countess, the two facilities that make up the AECO Hub™, are geographically separated, but the toll design of the Alberta System means that they are both commercially located at the same point. This enables us to operate the two facilities as one integrated commercial operation without customers incurring incremental transportation costs. Customers nominate injections or withdrawals at Suffield's interconnect with the Alberta System, and AECO Hub™ allocates the nominations between its Suffield and Countess facilities based on its reservoir management strategy.

        Our rights to use the reservoirs at Suffield and Countess are held pursuant to a series of natural gas storage agreements, trust arrangements and similar instruments entered into with the holders of subsurface mineral interests of the land where the reservoirs are situated. Rights to access, occupy and use the lands for facilities including the well sites and pipelines are derived from access agreements, right-of-ways, easements, leases and other similar land use agreements with the surface owners of such land.

        Suffield Storage Facility.    AECO Suffield is located in southeastern Alberta. It is near the Alberta System's "eastern gate," the largest natural gas delivery point in Canada, where gas is delivered into TransCanada's mainline pipeline system (transporting gas to eastern Canada and the northeastern U.S.) and the Foothills/Northern Border pipeline system (transporting gas to Chicago and the Midwestern U.S.). AECO Suffield consists of 60 storage wells and five storage reservoirs with aggregate effective working capacity of approximately 80.0 Bcf. The storage reservoirs are connected to a central processing and compression facility by a system of five pipelines. Compression is provided by natural gas powered engines that have a total of more than 36,000 horsepower.

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        All of the processing and compression facilities and substantially all of the well sites for the storage reservoirs are located on the Canadian Forces Base, Suffield military training range, or CFB Suffield. CFB Suffield is open prairie land, which provides relatively low costs for seismic surveys, drilling and pipelining. While the military restricts access to the well sites on a limited basis from time-to-time (i.e., during military exercises), AECO Suffield has not experienced any operational issues due to the location since its inception in 1988.

        Countess Storage Facility.    AECO Countess is located in south central Alberta, approximately 60 miles east of Calgary. Countess is connected to a large diameter pipe of the Alberta System. This modern gas storage project consists of 29 storage wells and two high performance gas storage reservoirs that are connected to a central processing and compression facility. The two storage reservoirs each have their own gathering pipeline system. Compression is electrically powered and totals approximately 34,500 horsepower. The two reservoirs have total effective working capacity of approximately 68.0 Bcf.

    Customers

        AECO Hub™'s customers consist of a mix of gas market participants, including financial institutions, producers, marketers, power generators, pipelines and municipalities, resulting in a portfolio of customers with diverse usage patterns and varying contract expiration dates. This allows more opportunity for AECO Hub™ to optimize underutilized capacity. Many of our customers actively buy and sell natural gas at key hubs across North America. Our strong relationships at AECO Hub™ often result in new business at Wild Goose and Salt Plains.

        Most LTF transactions at AECO Hub™ are for a gas storage capacity of 1.0 Bcf or greater and average 3.3 Bcf. LTF contract terms have been chosen so that a manageable amount of contracts expire each year, avoiding exposure to a large contract turnover volume during a temporary market downturn. Existing commitments represent approximately 51% of AECO Hub™'s capacity for the fiscal year ending March 31, 2012. The weighted average contract life of our LTF storage contracts at AECO Hub™ is 2.9 years but most of our current customers have consistently entered into new contracts when their existing contracts expire. The largest contract we have at AECO Hub™ is in the seventh year of an initial term of 10 years, with the potential to be extended in five year increments to a maximum term of 25 years under certain circumstances. Upon the expiration of the initial term and each subsequent five year extension, this contract is automatically extended for five additional years unless either party exercises its right to terminate the contract. Under the contract terms, the party exercising its early termination rights is subject to the payment of an early termination fee.

    Historic and Future Expansion

        Since our inception, we have increased the AECO Hub™'s gas storage capacity by 39.0 Bcf. We are continuing our delta pressuring activities at AECO Countess. We expect that the delta pressuring will increase the gas storage capacity of AECO Hub™ by another 2 Bcf by March 31, 2012.

    Regulatory

        AECO Hub™ is subject to provincial regulatory jurisdiction. Operations are subject to the regulation of the Alberta Energy Resources Conservation Board, or the Alberta ERCB, which must also approve proposed expansions of storage capacity. AECO Hub™ is not subject to active market regulation. There is no cost-of-service or other utility-type regulation of storage rates or other commercial terms of storage contracts in Alberta. While the Alberta Utilities Commission, or the AUC, does have overriding jurisdiction to set gas storage prices when authorized to do so by the Alberta Government, it is not currently Alberta Government policy to apply such rate regulation. As such, AECO Hub™ can charge customers negotiated market-based rates as well as store purchased gas for its own account.

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    Environmental

        Both AECO Hub™ facilities are subject to federal and provincial environmental laws and regulations, including oversight by Alberta's Department of Environment and the Alberta ERCB. There are currently no material environmental issues.

    Wild Goose

    Overview

        Our Wild Goose storage facility is located 55 miles north of Sacramento, California. Wild Goose is a high deliverability, multi-cycle, or HDMC storage facility. This HDMC capability is made possible by the rock quality of the Wild Goose reservoirs and the extensive use of horizontal well technology.

        Wild Goose is strategically located in a highly-liquid hub market and is one of only three independent operating storage facilities in northern California. Wild Goose provides natural gas receipt and delivery services at Pacific Gas & Electric Company, or PG&E Citygate, a liquid trading point where gas supply from multiple upstream basins meets the volatile California end-use gas demands that create a dependence on natural gas storage. This location provides customers with the opportunity to take advantage of PG&E Citygate pricing, liquidity and arbitrage opportunities. Wild Goose is connected to two PG&E interconnect points—Line 167 (a local transmission line), which is situated adjacent to the facility, and PG&E's Line 400/401 (the large diameter backbone pipelines) via our own 25 mile, 30 inch connector pipeline. Wild Goose benefits from the energy supply and demand dynamics of California, including underlying natural gas consumption growth, fluctuating gas-fired power generation demand, a dual-peaking market for gas prices, uncertainty of pipeline supply and the potential for significant new power generation demand (partly due to the varying availability of hydro-power) to back up renewable energy sources such as wind and solar. These dynamics support high demand for natural gas storage.

    Facility

        Wild Goose operates 15 gas storage wells that are completed in three depleted natural gas reservoirs with an effective working capacity of 35.0 Bcf and a gas generated compression of 20,800 horsepower. The Wild Goose reservoirs are located in high quality rock formations. In addition, the reservoirs have a strong water drive mechanism, which helps maintain reservoir pressure and well deliverability. Rights to use the reservoirs at Wild Goose for natural gas storage are held pursuant to a series of natural gas storage leases with the surface owners of the lands where the reservoirs are situated as well as mineral owner agreements and similar instruments entered into with the holders of subsurface mineral interests in such lands. Rights for the lands used for the pipelines are derived from right-of-ways, easements, leases, and other similar land-use agreements.

    Customers

        Wild Goose's customers include a mix of gas market participants, including financial institutions, producers, marketers, power generators, pipelines and municipalities, resulting in a portfolio of customers with diverse usage patterns and different contract expiration dates. This allows us to optimize underutilized capacity.

        Wild Goose has contracts with over a dozen third-party customers for terms of one year or longer. Existing commitments represent approximately 74% of Wild Goose's capacity for the fiscal year ending March 31, 2012. The weighted average contract life of our LTF storage contracts at Wild Goose is 1.9 years, but many of our current customers have consistently entered into new contracts when their existing contracts expire.

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    Historic and Future Expansion

        Since our inception, we have increased the gas storage capacity of Wild Goose by 17.0 Bcf. In December 2010 we received approval from the California Public Utilities Commission, or CPUC to amend Wild Goose's certificate to further expand the facility to 50.0 Bcf of gas storage capacity and to increase its maximum injection rate from 450 to 650 MMcf per day and its maximum withdrawal rate from 700 to 1,200 MMcf per day. This approval allowed us to quickly increase Wild Goose's gas storage capacity to 35.0 Bcf. In addition, we commenced construction activities to increase the capacity further to 50.0 Bcf as soon as is practicable. We expect that the remaining 15.0 Bcf of certificated capacity will be available for service no later than March 31, 2012.

    Regulatory

        Wild Goose is regulated as a state utility by the CPUC and is certified to serve the California intra-state market. Wild Goose has regulatory authority to negotiate market based rates for third-party storage contracts and buys and sells gas for its own account to optimize its operations. In addition, as an independent storage provider Wild Goose is exempt from the provisions of California's affiliate conduct rules and has the right to coordinate its operation with our other facilities. It is however, restricted from contracting for natural gas storage services with its affiliates.

    Environmental

        There are currently no material environmental liabilities at Wild Goose. Wild Goose operates in environmentally sensitive agricultural and wetlands recreation environments. All facilities are modern and are operated based on strict environmental and maintenance standards.

        In constructing and expanding the Wild Goose facility, we have experienced no significant environmental-related delays or unexpected costs, by initially bringing forward development plans that mitigate any environmental impacts to the satisfaction of all responsible agencies and stakeholders. Wild Goose has received the State of California—Department of Conservation Award for Outstanding Oilfield Lease and Facility Maintenance for six consecutive years.

    Salt Plains

    Overview

        Our Salt Plains storage facility is located 110 miles north of Oklahoma City, Oklahoma, in a region of growing demand for natural gas as a fuel for heating and power generation. Salt Plains provides intrastate services in Oklahoma through its connection to pipelines operated by ONEOK Gas Transportation Pipelines, L.L.C., or ONEOK, and intrastate and interstate services through its interconnect with pipelines operated by Southern Star Central Gas Pipeline, Inc., or Southern Star. The heightened supply and demand imbalances in this market create increased margin opportunities for us and our customers.

        Salt Plains is in a strategic mid-continent location with interconnects to pipelines owned by Southern Star and ONEOK, which serve both regional and mid-continent gas markets. This provides customers the benefits of liquidity, supply, and arbitrage opportunities. In addition, gas produced in the Rocky Mountains that is delivered to the mid-continent region gets redistributed to various pipelines such as Southern Star that have access to Salt Plains. Growing shale gas development in neighboring regions, such as the Barnett, Fayetteville, Haynesville and Cana Woodford shales, is also adding significant supply to the mid-continent region, which has the potential to increase demand for gas storage services. Compression is gas-powered and totals approximately 10,000 horsepower. The reservoir has a total working gas storage capacity of approximately 13.0 Bcf.

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    Facility

        Salt Plains operates 30 wells that are completed in a depleted natural gas storage reservoir characterized by high-quality rock. The wells are connected to a central plant facility by seven miles of pipeline. Rights to use the reservoir at Salt Plains for natural gas storage are held pursuant to a series of gas storage agreements with the mineral rights owners of the lands where the reservoir is situated. Rights for the lands used for the pipelines are derived under these gas storage agreements as well as from right-of-way grants from other land owners.

    Customers

        Existing commitments represent approximately 36% of Salt Plains' capacity for the 2012 fiscal year. The weighted average contract life of our LTF storage contracts at Salt Plains is 1.4 years, but most of our current customers have consistently entered into new contracts when their existing contracts expire. The largest contract we have at Salt Plains is in the third year of a three year term.

    Historic and Future Expansion

        Since our inception, we have increased the facility's gas storage capacity by 4.3 Bcf. We believe there is the potential for opportunities to expand the gas storage capacity of the facility and we are currently assessing the feasibility of such expansion in the future.

    Regulatory

        Our Salt Plains intrastate operations are subject to regulation by the Oklahoma Corporation Commission, or the OCC. Salt Plains is also authorized to provide interstate storage service under the Natural Gas Policy Act of 1978 and the Federal Energy Regulatory Commission, or FERC, regulations and policies that allow intrastate pipeline and storage companies to engage in interstate commerce (commonly known as NGPA section 311 services). Salt Plains provides these NGPA section 311 services, which are not subject to FERC's broader jurisdiction under the Natural Gas Act, pursuant to a Statement of Operating Conditions which is on file with FERC. The OCC's regulatory policies are generally less stringent than those of FERC. Currently, Salt Plains is authorized to charge market based rates in both intrastate and interstate service and has no restrictions on affiliate interactions.

    Environmental

        We are not aware of any current material environmental liabilities relating to the Salt Plains facility.

    NGPL Contracted Capacity

    Overview

        Since 2001, our subsidiary has contracted for 8.5 Bcf of gas storage capacity on the MidCon leg and the TexOk leg of the NGPL pipeline system in the mid-continent. The NGPL system connects and balances Gulf Coast and mid-continent supply basins with Chicago and other Midwestern U.S. end-use markets. NGPL has a number of different storage facilities on its pipeline system and manages its storage capacity as pools on separate legs of the pipeline. Under NGPL's FERC-approved tariff, NGPL is limited to charging cost-of-service rates for its transportation and storage services. We currently have multiple LTF storage contracts with NGPL that expire on various dates through 2017. We have a tariff-based right of first refusal to renew these contracts at NGPL's favorable cost-of-service rate, effectively making this capacity a long-term asset without any invested capital, with an option to exit should the rate be above market value.

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        As a customer of the NGPL capacity, and not the operator, Niska uses its optimization strategy to generate revenue from its use of the capacity, and does not remarket services.

    Access Gas Services

        We have a small but growing gas marketing business in Eastern Canada, British Columbia and Alberta serving commercial, industrial and retail customers. This is also a margin business where supply is locked in to serve customers at committed prices. In Eastern Canada, EnerStream Agency Services also provides fee based agency services to natural gas end-users.

Regulation

        Our operations are subject to extensive laws and regulations that have the potential to have a significant impact on our business. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. We are subject to regulatory oversight by federal, state, provincial and local regulatory agencies, many of which implement rules and regulations that are binding on the natural gas storage and pipeline industry, related businesses and individual participants. The failure to comply with such laws and regulations can result in substantial penalties. The cost of regulatory compliance on our operations increases our costs of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors.

        Our historical and projected operating costs reflect the recurring costs resulting from compliance with these regulations, and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions or changes in regulation, or discovery of existing but unknown compliance issues. The following is a summary of the kinds of regulation that may impact our operations. However, such discussion should not be considered an exhaustive review of all regulatory considerations affecting our operations.

    Environmental Matters

        Our natural gas storage operations are subject to stringent and complex federal, state, provincial and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges, and solid waste management. Such laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits and other approvals. These laws and regulations impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct certain activities under statutes such as the Clean Water Act, or CWA, the Clean Air Act, or CAA, the Safe Drinking Water Act, or SDWA and comparable legislation in Canada limiting or preventing the release of materials from our facilities, managing wastes generated by our operations, the installation of pollution control equipment, responding to releases of process materials or wastes from our operations, and the risk of substantial liabilities for pollution resulting from our operations. The Occupational Safety and Health Act, or OSHA, comparable state statutes that regulate the protection of the health and safety of workers, as well as the Occupational Health and Safety Act in the Province of Alberta, and comparable federal legislation in Canada also apply to our operations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil, and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. We believe that we are in substantial compliance with existing environmental laws and regulations and that such laws and regulations will not have a material adverse effect on our business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance of the amount or timing of future

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expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.

    Occupational Safety and Health Act

        The workplaces in the U.S. associated with the storage facilities we operate are subject to the requirements of the Federal Occupational Safety and Health Act, or OSHA, as amended, as well as comparable state statutes that regulate the protection of the health and safety of workers. Workplaces in Canada associated with our operations are subject to the requirements of the Occupational Health and Safety Act in the Province of Alberta and comparable federal legislation. Failure to comply with OSHA requirements, or comparable requirements in Canada, including general industry standards, recordkeeping requirements and monitoring of occupational exposure to regulated substances, could subject us to fines or significant compliance costs.

    Climate Change

        There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases (GHGs). Future regulation of GHGs in the United States could occur pursuant to future U.S. treaty commitments, new domestic legislation that may impose a carbon emissions tax or establish a cap-and-trade program or regulation by the EPA. The Obama Administration has indicated its support for a mandatory cap and trade program to reduce GHG emissions. However, a change in the control of Congress makes it unlikely that federal climate change legislation will be passed in the next few years. Similarly, the outcomes of the ongoing international negotiations since Cancun make it unlikely that a new, legally-binding international instrument to control GHGs will be adopted in the near future.

        While a new federal or international program seems unlikely, we may have to comply with state or regional programs to limit GHG emissions. State and regional programs that may impact our operations include the Western Climate Initiative (WCI) and the Regional Greenhouse Gas Initiative (RGGI). Given New Jersey's recent withdrawal, the future status of RGGI, and agreement between the states in the Northeastern U.S. is uncertain. We do not believe that RGGI will impact our business because we do not currently have operations in RGGI member states. The WCI is an agreement between the states of California, Oregon, Washington, New Mexico, Arizona, Utah and Montana, and the Canadian provinces of British Columbia, Manitoba, Ontario, and Quebec. If enough WCI member states pass implementing legislation, the WCI will create a regional cap-and-trade scheme for GHG emissions. Depending on the scope of any regional programs that we must comply with, we could be required to obtain and surrender allowances for GHG emissions statutorily attributed to our operations (e.g., emissions from compressor stations or the injection and withdrawal of natural gas). Although we would not be impacted to any greater degree than other similarly situated natural gas storage companies, a stringent GHG control program could have an adverse effect on our cost of doing business and reduce demand for the natural gas storage services we provide.

        In 2006, the California State Legislature passed and Governor Schwarzenegger signed AB 32, the Global Warming Solutions Act of 2006, with a goal of reaching (i) 1990 GHG emissions levels by the year 2020, (ii) 80% of 1990 levels by 2050, and (iii) establishing mandatory emissions reporting program. AB 32 directed the California Air Resources Board, or CARB, to begin developing discrete early actions to reduce GHGs while also preparing a scoping plan to identify how best to reach the 2020 limit. Since the passage of AB 32, the CARB approved in December 2010 a GHG cap-and-trade program, which is scheduled to take effect in 2012. However, a recent court order and citizens' challenge threatens to delay California's cap-and-trade program. No final determination has been made with regard to the potential applicability of the AB 32 cap-and-trade program to our operations. We are therefore not in a position to quantify any potential costs associated with compliance under the program as proposed. However, any limitation a finalized program places on GHG emissions from our

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equipment and operations could require us to incur costs to reduce the GHG emissions associated with our operations.

        Even in the absence of new federal legislation the U.S. Environmental Protection Agency, or EPA, has begun to regulate GHG emissions pursuant to the federal Clean Air Act (CAA) based on the April 2007 United States Supreme Court ruling in Massachusetts, et al. v. EPA that the EPA has authority to regulate carbon dioxide emissions. The GHG regulations that EPA has issued following exercising the authority affirmed by Massachusetts v. EPA include: (1) the December 2009 "endangerment finding" determining that air pollution from six GHGs endangers public health and welfare, and that mobile sources cause or contribute to that air pollution; (2) the May 2010 "Tailpipe Rule," issued jointly with the National Highway Traffic Safety Administration setting GHG emission and fuel economy standards for new light-duty vehicles; (3) the April 2010 "Timing Rule," concluding that stationary source regulation under Titles I and V of the CAA (involving Prevention of Significant Deterioration regulations and operating permits, respectively) must regulate GHG emissions beginning when such emissions are subject to controls under the mobile source provisions of the Act; (4) the June 2010 "Tailoring Rule," temporarily exempting small stationary sources from PSD and Title V requirements through regulations modifying the Act's emissions thresholds; and (5) the December 2010 "SIP Call" rule, finding 13 State Implementation Plans ("SIPs") inadequate because they did not regulate GHGs from stationary sources, and directing those States to correct the inadequacies or face federalization of their permitting programs. The first four rules have been challenged in consolidated litigation in the D.C. Circuit. However, the Court refused to stay the rules while the challenge is pending.

        In addition to the above rules, the EPA has stated that it intends to propose standards for power plants in July 2011 and for refineries in December 2011 and will issue final standards in May 2012 and November 2012, respectively. Finally, in December 2010, the EPA issued its plan to update pollution standards for fossil fuel power plants and petroleum refineries. This new standard along with the current EPA's GHG regulations could affect the demand for gas.

        Pursuant to a Congressional mandate in the FY2008 Consolidated Appropriations Act, EPA has promulgated regulations requiring the measuring and reporting of GHG emissions from a variety of industrial sources. Finalized in October 2009, the Mandatory Reporting of Greenhouse Gas Emissions Rule (Mandatory Reporting Rule or MRR) sets out general provisions applicable to all entities with MRR compliance obligations, as well as a series of subparts covering particular industrial sectors. For most sectors, MRR obligations are triggered when the facility's emissions exceed 25,000 metric tons of carbon dioxide equivalent in a year, however, some facilities will be covered regardless of their emissions levels. Since the initial MRR was finalized, the EPA has gone on to finalize additional subparts, bringing new sectors within the scope of the rule. Finalized in June 2010, Subpart W of the MRR applies to owners and operators of petroleum and natural gas systems, which are defined to include onshore oil and natural gas production, offshore oil and natural gas production, onshore natural gas process, onshore natural gas transmission and compression, underground natural gas storage, LNG storage, and LNG import and export activities be subject to the MRR's requirements if they emit more than 25,000 metric tons of carbon dioxide equivalent per year. Because our primary business involves underground natural gas storage, we are potentially subject to Subpart W of the MRR.

        Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide, and other GHG. It is generally anticipated that the Canadian government will consider regulatory measures similar to those being proposed by the EPA, but new national legislation on climate change is not expected at this time. Rather, the majority of GHG initiatives in Canada are likely to be in the form of regional initiatives.

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        British Columbia has been in the process of implementing a cap-and-trade system consistent with the requirements of the WCI. The province has created a Climate Action Secretariat that is responsible for developing cap-and-trade rules. Ontario, another province participating in the WCI, has committed to a phase out of coal-fired power by 2014.

        Alberta regulates GHG emissions under the Climate Change and Emissions Management Act, the Specified Gas Reporting Regulation (the "SGRR"), which imposes GHG emissions reporting requirements, and the Specified Gas Emitters Regulation (the "SGER"), which imposes GHG emissions limits. A facility subject to the SGRR must report if it has GHG emissions of 50,000 metric tonnes or more from a facility in any year. Under the SGER, GHG emission limits apply once a facility has direct GHG emissions in a year of 100,000 metric ton or more. Under the SGER, subject facilities are required to reduce their emission intensities (e.g., metric ton of GHGs emitted per unit of production) by 12% in the case of facilities operating prior to 2000 and by 2% per year beginning in the fourth year of commercial operations for facilities commencing operations in 2000 and after up to a maximum of 12%. A facility subject to the SGER may meet the applicable emission limits by making emissions intensity improvements, offsetting GHG emissions by purchasing offset credits or emission performance credits in the open market, or acquiring "fund credits" by making payments of CDN$15 per metric tonne to the Alberta Climate Change and Management Fund. The direct and indirect costs of these regulations may adversely affect our operations and financial results.

Rates

        Commercial arrangements at our facilities in the U.S. are subject to the jurisdiction of regulators, including FERC, the OCC and the CPUC. With authorization of the Alberta Government, commercial arrangements at our facility in Alberta, Canada, could be regulated by the AUC, but it is not currently Alberta Government policy to apply any such rate regulation. Each of our facilities currently has the ability to negotiate and charge rates based upon market prices, and are not limited to charging cost-of-service rates which are capped at recovery of costs plus a reasonable rate of return. The exemptions we receive under the regulatory regimes applicable to us enable us to buy, sell and store natural gas for our own account at our existing storage assets. The ability to charge market-based rates enables us to charge greater prices than many other storage providers which are required to charge cost-of-service based rates and our ability to buy, sell and store natural gas for our own account enables us to optimize our working gas capacity. In addition, we are permitted to consolidate management, marketing, and administrative functions for efficiencies in matters that some competing operators are prohibited from due to affiliate rules to which they are subject.

Employees

        As of March 31, 2011, we had 129 employees. Our executive officers are currently employed by Niska Partners Management ULC and subsidiaries of Niska Gas Storage Partners LLC.

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Competition

        The natural gas storage business is competitive. The principal elements of competition among storage facilities are rates, terms of service, types of service, access to supply sources, access to demand markets and flexibility and reliability of service. Because our facilities are strategically located in key North American natural gas producing and consuming regions, we face competition from existing competitors who also operate in those markets. Our competitors include gas storage companies, major integrated energy companies, pipeline operators and natural gas marketers of varying sizes, financial resources and experience. Competitors of the AECO Hub™ currently include TransCanada (Edson, CrossAlta), Atco (Carbon) and Enstor (Alberta Hub). Competitors of our Wild Goose facility currently include Buckeye Partners (Lodi), PG&E, NW Natural and PG&E (Gill Ranch) and a number of proposed projects in northern California. Competitors of our Salt Plains facility currently include Southern Star. Given the key location of our facilities, additional competition in the markets we serve could arise from new developments or expanded operations from existing competitors. We anticipate that growing demand for natural gas storage in the markets we serve will be met with increasing storage capacity, either through the expansion of existing facilities or the construction of new storage facilities.

Seasonality

        Our cash expenditures related to our optimization activities are highest during summer months, and our cash receipts from our optimization activities are highest during winter months. Consequently, our results of operations for the summer are generally lower than for the winter. With lower cash flow during the second and third calendar quarters, we may be required to borrow money in order to pay distributions to our members.

Item 1A.    Risk Factors.

        In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described below, which could materially adversely affect our business, financial condition and results of operations. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be adversely affected.

Risks Inherent in Our Business

We may not have sufficient cash following the establishment of cash reserves and payment of fees and expenses to enable us to make cash distributions to holders of our common units at the minimum quarterly distribution rate under our cash distribution policy.

        We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.35 per unit, or $1.40 per unit per year, which will require cash of approximately $24.1 million per quarter, or $96.6 million per year, based on the number of common and subordinated units currently outstanding. Under our cash distribution policy, the amount of cash we can distribute on our units principally depends upon the amount of cash generated from our operations, which will fluctuate based on, among other things:

    the rates that we are able to charge new or renewing storage customers that are influenced by, among other things, weather and the seasonality and volatility of natural gas demand and supply;

    our ability to continue to buy, sell and store natural gas for profit at our facilities as well as the cost of natural gas that we purchase for our own account and the duration for which we store it;

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    the risk that changes in the regulatory status of one or more of our facilities could remove the right to negotiate market-based rates, instead imposing cost of service rates, could adversely impact the rates we charge;

    technical and operating performance at our facilities;

    the level of our operating and maintenance and general and administrative costs; and

    nonpayment or other nonperformance by our customers.

        In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

    the level of capital expenditures we make;

    the cost of acquisitions that we make, if any;

    our debt service requirements;

    fluctuations in interest rates and currency exchange rates;

    fluctuations in our working capital needs;

    our ability to borrow funds and access capital markets;

    restrictions on distributions contained in debt agreements;

    the amount of cash reserves established by our board;

    fluctuations or changes in tax rates, including Canadian income and withholding taxes; and

    prevailing economic conditions.

        For a description of additional restrictions and factors that may affect our ability to pay cash distributions, see "Management's Discussion of Financial Condition and Results of Operations—Liquidity and Capital Resources."

The amount of cash we have available for distribution to holders of our units depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net earnings.

        The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses for financial accounting purposes and may not pay cash distributions during periods when we record net earnings.

Our level of exposure to the market value of natural gas storage services could adversely affect our revenues and cash available to make distributions.

        As portions of our third-party gas storage contract portfolio come up for replacement or renewal, and capacity becomes available, adverse market conditions may prevent us from replacing or renewing the contracts on terms favorable to us. The market value of our storage capacity, realized through the value customers are willing to pay for LTF contracts or via the opportunities to be captured by our STF contracts or optimization activities, could be adversely affected by a number of factors beyond our control, including:

    prolonged reduced natural gas price volatility;

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    a reduction in the difference between winter and summer prices on the natural gas futures market, sometimes referred to as the seasonal spread, due to real or perceived changes in supply and demand fundamentals;

    a decrease in demand for natural gas storage in the markets we serve;

    increased competition for storage in the markets we serve; and

    interest rates which, when higher, increase the cost of carrying owned or customer inventory.

        From our inception in May 2006 to March 31, 2011, we utilized an average of approximately 67.6% of our operated capacity for our LTF strategy, representing an average of approximately 46.1% of annual realized revenue. The volume-weighted average life of our LTF contracts at March 31, 2011 was 2.6 years. From inception to March 31, 2011, we utilized an average of approximately 16.7% of our operated capacity for our STF strategy, representing an average of approximately 17.8% of annual realized revenue. Over the same period, we utilized an average of approximately 15.7% of our operated capacity for our proprietary optimization strategy, representing an average of approximately 36.1% of annual revenue. As of March 31, 2011, approximately 22% of our LTF contracts and all of our STF contracts were due to expire on or before March 31, 2012. A prolonged downturn in the natural gas storage market due to the occurrence of any of the above factors could result in our inability to renegotiate or replace a number of our LTF contracts upon their expiration, leaving more capacity exposed to the value that could be generated through STF contracts or optimization. STF and optimization values would be impacted by the same factors, and market conditions could deteriorate further before the opportunity to extract value with those strategies could be realized.

        Further, our lines of business and assets are concentrated solely in the natural gas storage industry. Thus, adverse developments, including any of the industry-specific factors listed above, would have a more severe impact on our business, financial condition, results of operations and ability to pay distributions than if we maintained a more diverse business.

We face significant competition that may cause us to lose market share, negatively affecting our business.

        Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors. The natural gas storage business is highly competitive. The principal elements of competition among storage facilities are rates, terms of service, types of service, deliverability, supply and market access, flexibility and reliability of service. Our operations compete primarily with other storage facilities in the same markets in the storage of natural gas. The CPUC has adopted policies that favor the development of new storage projects and there are numerous projects, including expansions of existing facilities and greenfield construction projects, at various stages of development in the market where our Wild Goose facility operates. These projects, if developed and placed into service, may compete with our storage operations.

        We also compete with certain pipelines, marketers and liquefied natural gas, or LNG, facilities that provide services that can substitute for certain of the storage services we offer. In addition, natural gas as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas storage services. Some of our competitors have greater financial resources and may now, or in the future, have greater access to expansion or development opportunities than we do.

        If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to compete effectively. Some of these competitors may expand or construct new storage facilities that would create additional competition for us. The storage facility expansion and

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construction activities of our competitors could result in storage capacity in excess of actual demand, which could reduce the demand for our services, and potentially reduce the rates that we receive for our services.

        We also face competition from alternatives to natural gas storage—ways to increase supply of or reduce demand for natural gas at peak times such that storage is less necessary. For example, excess production or supply capability with sufficient delivery capacity on standby until required for peak demand periods or ability for significant demand to quickly switch to alternative fuels at peak times would represent alternatives to gas storage.

        Competition could intensify the negative impact of factors that significantly decrease demand for natural gas at peak times in the markets served by our storage facilities, such as competing or alternative forms of energy, a recession or other adverse economic conditions, weather, higher fuel costs and taxes or governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas. Increased competition could reduce the volumes of natural gas stored in our facilities or could force us to lower our storage rates.

If third-party pipelines interconnected to our facilities become unavailable or more costly to transport natural gas, our business could be adversely affected.

        We depend upon third-party pipelines that provide delivery options to and from our storage facilities for our benefit and the benefit of our customers. Because we do not own these pipelines, their continuing operation is not within our control. These pipelines may become unavailable for a number of reasons, including testing, maintenance, line repair, reduced operating pressure, lack of operating capacity or curtailments of receipt or deliveries due to insufficient capacity. In addition, these third-party pipelines may become unavailable to us and our customers because of the failure of the interconnects that transport gas between our facilities and the third-party pipelines. Because of the limited number of interconnects at our facilities (Wild Goose is connected to third-party pipelines by two interconnects, AECO Hub™ by two interconnects (one at each facility) and Salt Plains by two interconnects), the failure of any interconnect could materially impact our ability or the ability of our customers to deliver gas into the third-party pipelines. If the costs to us or our storage service customers to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If third-party pipelines become partially or completely unavailable, our ability to operate could be restricted, thereby reducing our profitability. A prolonged or permanent interruption at any key pipeline interconnect could have a material adverse effect on our business, financial condition, results of operations and ability to pay distributions to our members.

Our operations are subject to operational hazards and unforeseen interruptions, which could have a material adverse effect on our business.

        Our operations are subject to the many hazards inherent in the storage of natural gas, including, but not limited to:

    negative unpredicted performance by our storage reservoirs that could cause us to fail to meet expected or forecasted operational levels or contractual commitments to our customers;

    unanticipated equipment failures at our facilities;

    damage to storage facilities and related equipment caused by tornadoes, hurricanes, floods, earthquakes, fires, extreme weather conditions and other natural disasters and acts of terrorism;

    damage from construction and farm equipment or other surface uses;

    leaks of or other losses of natural gas as a result of the malfunction of equipment or facilities;

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    migration of natural gas through faults in the rock or to some area of the reservoir where the existing wells cannot drain the gas effectively;

    blowouts (uncontrolled escapes of gas from a well), fires and explosions;

    operator error; and

    environmental pollution or release of toxic substances.

        These risks could result in substantial losses due to breaches of our contractual commitments, personal injury or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our operations. In addition, operational interruptions or disturbances, mechanical malfunctions, faulty measurements or other acts, omissions, or errors may result in significant costs or lost revenues. Gas that moves outside of the effective drainage area through migration could be permanently lost and will need to be replaced to maintain design storage performance.

We are not fully insured against all risks incident to our business, and if an accident or event occurs that is not fully insured it could adversely affect our business.

        We may not be able to obtain the levels or types of insurance we desire, and the insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not covered by insurance could have a material adverse effect on our business, financial condition, results of operations and ability to pay distributions to our members.

We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our financial results and cash available for distribution.

        We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use the capacity could have a material adverse effect on our business, financial condition, results of operations and ability to pay distributions to our members.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

        Our $800.0 million principal amount of outstanding indebtedness consists of the 8.875% senior notes due 2018 of Niska US and Niska Canada. Our level of debt could have important consequences to us, including the following:

    additional financing for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

    we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to members; and

    we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally than our competitors with less debt.

        Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business,

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regulatory and other factors, some of which are beyond our control. In addition, our ability to service our debt under our credit facilities will depend on market interest rates because the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or terminating distributions and reducing or delaying our business activities, acquisitions, investments or capital expenditures. In addition, we may take actions such as selling assets, restructuring or refinancing our debt or seeking additional equity capital although we may not be able to effect any of these actions on satisfactory terms, or at all. Our inability to obtain additional financing on terms favorable to us or our inability to service our debt could have a material adverse effect on our business, results of operations, financial condition and ability to pay distributions. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

Restrictions in the agreements governing our indebtedness could limit our ability to make distributions to our members.

        We will be dependent upon the cash flow generated by our operations in order to meet our debt service obligations and to allow us to make distributions to our members. The operating and financial restrictions and covenants in our credit agreement, the indenture governing our senior notes and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make distributions to our members. For example, our credit agreement and the indenture governing our senior notes restrict or limit our ability to:

    make distributions;

    incur additional indebtedness or guarantee other indebtedness;

    grant liens or make certain negative pledges;

    make certain loans or investments;

    engage in transactions with affiliates;

    make any material change to the nature of our business;

    make a disposition of assets; or

    enter into a merger or plan to consolidate, liquidate, wind up or dissolve.

        Furthermore, our credit agreement contains covenants requiring us to maintain certain financial ratios and tests, including that we maintain a fixed charge coverage ratio of 1.1 to 1.0 at the end of each fiscal quarter when excess availability under both revolving credit facilities is less than 15% of the aggregate amount of availability under both credit facilities. Our ability to comply with those covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement or the indenture governing our senior notes, the lenders or the noteholders, as the case may be, will be able to accelerate the maturity of all borrowings and demand repayment of amounts outstanding, our lenders' commitment to make further loans to us may terminate, and we may be prohibited from making distributions to our members. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.

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        The indenture governing our senior notes prohibits us from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, both the indenture and our $400 million credit agreement contain covenants limiting our ability to pay distributions to unitholders. The covenants apply differently depending on our fixed charge coverage ratio (defined substantively the same in the indenture and the credit agreement). If the fixed charge coverage ratio is greater than 1.75 to 1.0, we will be permitted to make restricted payments, including distributions to our unitholders, if the aggregate restricted payments since the date of our IPO, excluding certain types of permitted payments, are less than the sum of a number of items including, most importantly, operating surplus (defined similarly to the definition in our Operating Agreement) calculated as of the end of our preceding fiscal quarter and the aggregate net cash proceeds received by us as a capital contribution or from the issuance of equity interests, including the net proceeds received from our IPO. The indenture governing our senior notes contains an additional general basket of $75 million not contained in our credit agreement.

        See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our $400.0 Million Credit Agreement" and "Our 8.875% Senior Notes Due 2018." Any subsequent replacement of our credit agreement, our senior notes or any new indebtedness could have similar or greater restrictions.

We will be required to make capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to pay cash distributions may be diminished or our financial leverage could increase.

        In order to increase our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to raise the level of our cash distributions. To fund our expansion capital expenditures, we will be required to use cash from our operations or incur borrowings or sell additional common units or other membership interests. Such uses of cash from operations will reduce cash available for distribution to our members. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our members. In addition, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional membership interests may result in significant unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

If we do not successfully complete expansion projects or make and integrate acquisitions that are accretive, our future growth may be limited.

        A principal focus of our strategy is to grow the cash distributions on our units by expanding our business. Our ability to grow depends on our ability to complete expansion and development projects and make acquisitions that result in an increase in cash per unit generated from operations. We have near term projects in progress to expand our capacity by up to an additional 17.0 Bcf, including 15.0 Bcf of capacity expected to become available by March 31, 2012 at Wild Goose and an additional 2.0 Bcf of capacity expected to become available by March 31, 2012 at AECO. We may be unable to successfully complete accretive expansion or development projects or acquisitions for any of the following reasons:

    we are unable to identify attractive expansion or development projects or acquisition candidates or we are outbid by competitors;

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    we are unable to obtain necessary regulatory and/ or government approvals;

    we are unable to realize anticipated costs savings or successfully integrate the businesses we build or acquire;

    we are unable to raise financing on acceptable terms;

    we make or rely upon mistaken assumptions about volumes, revenues and costs, including synergies and potential growth;

    we are unable to secure adequate customer commitments to use the newly expanded or acquired facilities;

    we are unable to hire, train or retain qualified personnel to manage and operate our business and assets;

    we are unable to complete expansion projects on schedule and within budgeted costs;

    we assume unknown liabilities when making acquisitions for which we are not indemnified or for which our indemnity is inadequate;

    our management's and employees' attention is diverted because of other business concerns; or

    we experience unforeseen difficulties operating in new product areas or new geographic areas.

        If any expansion or development project or acquisition eventually proves not to be accretive to our cash flow per unit, our business, financial condition, results of operations and ability to pay distributions to our members may be materially adversely affected.

Exposure to currency exchange rate fluctuations will result in fluctuations in our cash flows and operating results.

        Currency exchange rate fluctuations could have an adverse effect on our results of operations. Historically, a portion of our revenue has been generated in Canadian dollars, but we incur operating and administrative expenses in both U.S. dollars and Canadian dollars and financing expenses in U.S. dollars. If the Canadian dollar weakens significantly, we would be required to convert more Canadian dollars to U.S. dollars to satisfy our obligations, which would cause us to have less cash available for distribution.

        A significant strengthening of the U.S. dollar could result in an increase in our financing expenses and could materially affect our financial results under U.S. GAAP. In addition, because we report our operating results in U.S. dollars, changes in the value of the U.S. dollar also result in fluctuations in our reported revenues and earnings. In addition, under U.S. GAAP, all foreign currency-denominated monetary assets and liabilities such as cash and cash equivalents, accounts receivable, restricted cash, accounts payable, long-term debt, capital lease obligations and asset retirement obligations are revalued and reported based on the prevailing exchange rate at the end of the reporting period. This revaluation may cause us to report significant non-monetary foreign currency exchange gains and losses in certain periods.

Our operations are subject to environmental and worker safety laws and regulations that may expose us to significant costs and liabilities.

        Our natural gas storage activities are subject to stringent and complex federal, state, provincial and local environmental and worker safety laws and regulations. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. Moreover, new, stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our compliance costs or the cost of any remediation of environmental contamination that may

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become necessary, and these costs could be material. In addition, laws and regulations to reduce emissions of greenhouse gases could affect the production or consumption of natural gas and, adversely affect the demand for our storage services and the rates we are able to charge for those services. See "Business—Regulation" for more information.

A change in the jurisdictional characterization of our assets by regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

        AECO Hub™ in Alberta is not currently subject to rate regulation. The Alberta Energy Resources Conservation Board, or the ERCB, has jurisdiction to regulate the technical aspects of construction, development, and operation of storage facilities. If approved to do so by the Alberta Government, the AUC, may also set prices for gas stored in Alberta. It is not currently Alberta Government policy to disturb market-based prices of independent gas storage facilities. If, however, the AUC was authorized to regulate the rates we charge, it could materially adversely affect our business. In addition, a connected pipeline tolling structure is available to our customers at AECO Hub™, allowing them to inject and withdraw natural gas without incremental transportation costs. There has been a decision to include the previously provincially-regulated Alberta System under the jurisdiction of the Federal National Energy Board, or NEB, and it is possible that the NEB could assume federal jurisdiction over, and set rates for, connected storage facilities, including AECO Hub™, or invoke transportation toll design changes that negatively impact AECO Hub™.

        Our Wild Goose operations are regulated by the CPUC. The CPUC has authorized us to charge our Wild Goose customers market-based rates because, as an independent storage provider, we, rather than ratepayers, bear the risk of any underutilized or discounted storage capacity. If the CPUC changes this determination, for instance as a result of a complaint, we could be limited to charging rates based on our cost of providing service plus a reasonable rate of return, which could have an adverse impact on our revenues associated with providing storage services.

        Our Salt Plains operations are subject to primary regulation by the OCC and are permitted to conduct a limited amount of storage service in interstate commerce under Federal Energy Regulatory Commission, or FERC, regulations and policies that allow pipeline and storage companies to engage in interstate commerce (commonly known as NGPA section 311 services under the Natural Gas Policy Act of 1978), which services are not subject to FERC's broader jurisdiction under the Natural Gas Act. These section 311 services are provided by Salt Plains pursuant to a Statement of Operating Conditions which is on file with FERC. FERC has permitted Salt Plains to charge market-based rates for its section 311 services. Market-based rate authority allows Salt Plains to negotiate rates with individual customers based on market demand. This right to charge market-based rates may be challenged by a party filing a complaint with FERC. Our market-based rate authorization may also be re-examined if we add substantial new storage capacity through expansion or acquisition and as a result obtain market power. Any successful complaint or protest against our rates, or re-examination of those rates by FERC, could limit us to charging rates based on our cost of providing service plus a reasonable rate of return, and could have an adverse impact on our revenues associated with providing storage services. Should FERC or the OCC change their relevant policies, or should we no longer qualify for primary regulation by the OCC, our results of operations could be materially adversely affected.

        Our current natural gas storage operations in the United States are generally exempt from the jurisdiction of FERC, under the Natural Gas Act of 1938, or the Natural Gas Act or, in the case of Salt Plains, are providing services under NGPA section 311. If our operations become subject to FERC regulation under the Natural Gas Act, such regulation may extend to such matters as:

    rates, operating terms and conditions of service;

    the types of services we may offer to our customers;

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    the expansion of our facilities;

    creditworthiness and credit support requirements;

    relationships among affiliated companies involved in certain aspects of the natural gas business; and

    various other matters.

        In the event that our operations become subject to FERC regulation, and should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, or EPAct 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for certain violations of up to $1,000,000 per day for each violation. FERC also has the authority to order disgorgement of profits from transactions deemed to violate the Natural Gas Act and the EPAct 2005.

We hold title to our storage reservoirs under various types of leases and easements, and our rights thereunder generally continue only for so long as we pay rent or, in some cases, minimum royalties.

        Our rights under storage easements and leases continue for so long as we conduct storage operations and pay our grantors for our use, or otherwise pay rent owing to the applicable lessor. If we were unable to operate our storage facilities for a prolonged period of time (generally one year) or did not pay the rent or minimum royalty, as applicable, to maintain such storage easements and leases in good standing, we might lose title to our gas storage rights underlying our storage facilities. In addition, title to some of our real property assets may have title defects which have not historically materially affected the ownership or operation of our assets. In either case, to recover our lost rights or to remove the title defects, we would be required to utilize significant time and resources. In addition, we might be required to exercise our power of condemnation to the extent available. Condemnation proceedings are adversarial proceedings, the outcomes of which are inherently difficult to predict, and the compensation we might be required to pay to the parties whose rights we condemn could be significant and could materially adversely affect our business, financial condition, results of operations and ability to pay distributions to our members.

Our financial results are seasonal and generally lower in the second and third quarters of the calendar year, which may require us to borrow money in order to make distributions to our members during these quarters.

        Our cash expenditures related to our optimization activities are highest during summer months, and our cash receipts from our optimization activities are highest during winter months. As a result, our results of operations for the summer are generally lower than for the winter. With lower cash flow during the second and third calendar quarters, we may be required to borrow money in order to pay distributions to our members. Any restrictions on our ability to borrow money could restrict our ability to pay the minimum quarterly distributions to our members.

Our risk management policies cannot eliminate all commodity price risk. In addition, any non-compliance with our risk management policies could result in significant financial losses.

        While our hedging policies are designed to minimize commodity price risk, some degree of exposure to unforeseen fluctuations in market conditions remains. We have in place risk management systems that are intended to quantify and manage risks, including risks related to our hedging activities such as commodity price risk and basis risk. We monitor processes and procedures to prevent unauthorized trading and to maintain substantial balance between purchases and future sales and delivery obligations. However, these steps may not detect and prevent all violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. There is no assurance that our risk management procedures will prevent losses that would

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negatively affect our business, financial condition, results of operations and ability to pay distributions to our members. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Policy and Practices."

New derivatives legislation could have an adverse impact on our ability to hedge risks associated with our business and on the cost of our hedging activities.

        We use over-the-counter (OTC) derivatives products to hedge commodity risks and, to a lesser extent, our interest rate and currency risks. Recent legislation has been adopted to increase the regulatory oversight of the OTC derivatives markets and impose restrictions on certain derivative transactions, which could affect the use of derivatives in hedging transactions. Final regulations pursuant to this legislation defining which companies will be subject to the legislation have not yet been adopted. If future regulations subject us to additional capital or margin requirements or other restrictions on our trading and commodity positions, they could have an adverse effect on our ability to hedge risks associated with our business and on the cost of our hedging activities.

We may enter into commercial obligations that exceed the physical capabilities of our facilities.

        We enter into LTF and STF contracts and proprietary optimization transactions based on our understanding of the injection, withdrawal and working gas storage capabilities of our facilities as well as the expected usage patterns of our customers. If our understanding of the capabilities of our facilities or our expectations of the usage by customers is inaccurate we may be obligated to customers to inject, withdraw or store natural gas in manners which our facilities are not physically able to satisfy. If we are unable to satisfy our obligations to our customers we may be liable for damages, the customers could have the right to terminate their contracts with us, and our reputation and customer relationships may be damaged.

Our operations could be affected by terrorist activities and catastrophic events that could result from terrorism.

        In the event that our storage facilities are subject to terrorist activities, such activities could significantly impair our operations and result in a decrease in revenues and additional costs to repair and insure our assets. The effects of, or threat of, terrorist activities could result in a significant decline in the North American economy and the decreased availability and increased cost of insurance coverage. Any of these factors could have a material adverse effect on our business, financial condition, results of operations and ability to pay distributions to our members.

We depend on a limited number of customers for a significant portion of our revenues. The loss of any of these customers could result in a decline in our revenues and cash available to make distributions.

        We rely on a limited number of customers for a significant portion of our revenues. The loss of all or a portion of the revenues attributable to our key customers as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations and ability to pay distributions to our members.

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Risks Related to Our Structure

Holdco currently controls our manager, which has sole responsibility for conducting our business and managing our operations. Our manager has delegated this responsibility to our board, all of the members of which are appointed by our manager. Our manager and its affiliates, including Holdco, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of our common unitholders.

        Holdco owns and controls our manager. Our manager appoints all of the members of our board, which manages and operates us. Some of our directors and executive officers are directors or officers of our manager or its affiliates, including Holdco. Although our board has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, our directors and officers have a fiduciary duty to manage our business in a manner beneficial to Holdco. Therefore, conflicts of interest may arise between Holdco and its affiliates, including our manager, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our board may favor our manager's own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations:

    neither our Operating Agreement nor any other agreement requires Holdco to pursue a business strategy that favors us or our unitholders;

    pursuant to our Operating Agreement, our manager has limited its liability and defined its and our board's fiduciary duties in ways that are protective of it and the board as compared to liabilities and duties that would be imposed upon a managing member under Delaware law in the absence of such definition. Our Operating Agreement also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under Delaware common law;

    our board determines the amount and timing of asset purchases and sales, borrowings, issuance of additional membership interests and reserves, each of which can affect the amount of cash that is distributed to unitholders;

    our board determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances, whether a capital expenditure is classified as a maintenance capital expenditure. This determination can affect the amount of cash that is distributed to our unitholders, including distributions on our subordinated units, and to the holders of the incentive distribution rights, as well as the ability of the subordinated units to convert to common units;

    our board determines which costs incurred by our manager and its affiliates are reimbursable by us;

    our Operating Agreement does not restrict our manager from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf;

    our manager may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units;

    Holdco and its affiliates are not limited in their ability to compete with us;

    our manager is allowed to take into account the interests of parties other than us, including Holdco and its affiliates, in resolving conflicts of interest with us;

    except in limited circumstances, our manager has the power and authority to conduct our business without unitholder approval;

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    our Operating Agreement permits us to borrow funds to permit the payment of cash distributions or fund operating expenditures. These borrowings will be treated as cash receipts for the purpose of calculating operating surplus, and thus may permit us to achieve the financial conditions necessary for the subordinated units to convert to common units;

    our manager may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units or to make incentive distributions;

    our Operating Agreement permits us to distribute up to $50.0 million from capital sources, including on the incentive distribution rights, without treating such distribution as a distribution from capital;

    our manager controls the enforcement of the obligations that it and its affiliates owe to us; and

    our manager decides whether to retain separate counsel, accountants or others to perform services for us.

Affiliates of our manager, including Holdco and the Carlyle/Riverstone Funds and their portfolio company subsidiaries, are not limited in their ability to compete with us and are not obligated to offer us the opportunity to pursue additional assets or businesses.

        Our Operating Agreement among us, Holdco and others does not prohibit affiliates of our manager, including Holdco and the Carlyle/Riverstone Funds, from owning assets or engaging in businesses that compete directly or indirectly with us. Holdco is pursuing a potential gas storage development project in western Canada and currently holds the rights to build a salt dome cavern gas storage facility in Louisiana and a depleted reservoir in southern Texas. Holdco may but is not required to offer us the opportunity to purchase these projects. Holdco may instead opt to develop these projects in competition with us. In addition, the Carlyle/Riverstone Funds and their portfolio companies may acquire, construct or dispose of additional natural gas storage or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. The Carlyle/Riverstone Funds and their affiliates are large, established participants in the energy industry and may have greater resources than we have, which may make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition opportunities. As a result, competition from these entities could adversely impact our business, financial condition, results of operations and ability to pay distributions to our members.

Holders of our common units have limited voting rights and are not entitled to elect our manager or our directors.

        Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right to elect our manager or our board on an annual or other continuing basis. Our board, including our independent directors, is chosen entirely by our manager. Unlike publicly-traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. Furthermore, if the unitholders were dissatisfied with the performance of our manager, they have little ability to remove our manager.

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We are a "controlled company" within the meaning of NYSE rules and, as a result, qualify for, and rely on, exemptions from some of the NYSE listing requirements with respect to independent directors.

        Because Holdco controls more than 50% of the voting power for the election of our directors, we are a controlled company within the meaning of NYSE rules, which exempt controlled companies from the following corporate governance requirements:

    the requirement that a majority of the board consist of independent directors;

    the requirement that we have a nominating or corporate governance committee, composed entirely of independent directors, that is responsible for identifying individuals qualified to become board members, consistent with criteria approved by the board, selection of board nominees for the next annual meeting of shareholders, development of corporate governance guidelines and oversight of the evaluation of the board and management;

    the requirement that we have a compensation committee of the board, composed entirely of independent directors, that is responsible for reviewing and approving corporate goals and objectives relevant to chief executive officer compensation, evaluation of the chief executive officer's performance in light of the goals and objectives, determination and approval of the chief executive officer's compensation, making recommendations to the board with respect to compensation of other executive officers and incentive compensation and equity-based plans that are subject to board approval and producing a report on executive compensation to be included in an annual proxy statement or Form 10-K filed with the SEC;

    the requirement that we conduct an annual performance evaluation of the nominating, corporate governance and compensation committees; and

    the requirement that we have written charters for the nominating, corporate governance and compensation committees addressing the committees' responsibilities and annual performance evaluations.

        For so long as we remain a controlled company, we are not required to have a majority of independent directors or nominating, corporate governance or compensation committees. Accordingly, our unitholders may not have the same protections afforded to shareholders of companies that are subject to all of the NYSE corporate governance requirements.

Our Operating Agreement limits our manager's and directors' fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our manager or board that might otherwise constitute breaches of fiduciary duty.

        Our Operating Agreement contains provisions that reduce the fiduciary standards to which our manager or directors would otherwise be held by state fiduciary duty laws. The limitation and definition of these duties is permitted by the Delaware law governing limited liability companies. For example, our Operating Agreement:

    permits our manager to make a number of decisions in its individual capacity, as opposed to in its capacity as our manager, or in its sole discretion. This entitles our manager to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any unitholder. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the company or amendment to our Operating Agreement;

    provides that our manager or directors will not have any liability to us or our unitholders for decisions made in their capacity as manager or board members so long as they acted in good faith, meaning they believed the decision was in our best interests;

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    generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of our board and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be "fair and reasonable" to us, as determined by our board and that, in determining whether a transaction or resolution is "fair and reasonable," our board may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

    provides that our manager and our officers and directors will not be liable for monetary damages to us or our other members for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the manager or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

    provides that in resolving conflicts of interest, it will be presumed that in making its decision the manager or our board acted in good faith, and in any proceeding brought by or on behalf of any unitholder or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Even if unitholders are dissatisfied, they cannot initially remove our manager without Holdco's consent.

        Unitholders have little ability to remove our manager. The vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our manager. Holdco owns 72.6% of our outstanding common and subordinated units. Accordingly, our public unitholders are currently unable to remove our manager without Holdco's consent because Holdco owns sufficient units to be able to prevent the manager's removal.

        If our manager is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all subordinated units held by our manager and its affiliates will automatically be converted into common units. If no units held by any holder of subordinated units or its affiliates are voted in favor of that removal, all subordinated units will convert automatically into common units and any existing arrearages on the common units will be extinguished. A removal of our manager under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met the tests specified in our Operating Agreement. Cause is narrowly defined in our Operating Agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our manager liable for actual fraud or willful misconduct in its capacity as our manager. Cause does not include most cases of poor management of the business.

Our manager, or its interest in us, may be transferred to a third party without unitholder consent.

        Our manager may transfer its managing member interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our Operating Agreement does not restrict the ability of the owners of our manager from transferring ownership of our manager to a third party. The new owners of our manager would then be in a position to revoke the delegation to our board of the authority to conduct our business and operations or to replace our directors and officers with their own choices. This effectively permits a "change of control" of the company without unitholder vote or consent.

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Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions or for other purposes.

        An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other relatively more attractive investment opportunities may cause the trading price of our common units to decline. Therefore, changes in interest rates may affect our ability to issue additional equity to make acquisitions or for other purposes.

It is our policy to distribute a significant portion of our available cash to our members, which could limit our ability to grow and make acquisitions.

        Pursuant to our cash distribution policy, we expect that we will distribute a significant portion of our available cash to our members and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy may impair our ability to grow.

        In addition, because we intend to distribute a significant portion of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our members.

We may issue additional membership interests without unitholder approval, which would dilute a unitholder's existing ownership interests.

        Our Operating Agreement does not limit the number of additional membership interests that we may issue at any time without the approval of our unitholders. Our issuance of additional common units or other membership interests of equal or senior rank may have the following effects:

    each unitholder's proportionate ownership interest in us will decrease;

    the amount of cash available for distribution on each unit may decrease;

    because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

    the ratio of taxable income to distributions may increase;

    the relative voting strength of each previously outstanding unit may be diminished; and

    the market price of the common units may decline.

Our manager has a call right that may require unitholders to sell their common units at an undesirable time or price.

        If at any time our manager and its affiliates own more than 80% of the common units, our manager will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price, as calculated pursuant to the terms of our Operating Agreement. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our manager is not obligated to obtain a fairness opinion regarding the value of the

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common units to be repurchased by it upon exercise of the call right. There is no restriction in our Operating Agreement that prevents our manager from issuing additional common units and exercising its call right. If our manager exercised its call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Our manager and its affiliates own approximately 48.2% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than for the conversion of the subordinated units into common units), our manager and its affiliates will own approximately 74.6% of our outstanding common units.

Our Operating Agreement restricts the voting rights of unitholders owning 20% or more of our common units.

        Our Operating Agreement restricts unitholders' voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our manager and its affiliates, their transferees and persons who acquired such units with the prior approval of our board, cannot vote on any matter. Our Operating Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

        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, we 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 our Operating Agreement.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by Holdco or other large holders.

        We have 33,804,745 common units and 33,804,745 subordinated units outstanding. 16,304,745 of the common units and all of the subordinated units are owned by Holdco. All of the subordinated units will convert into common units at the end of the subordination period, which could occur as early as the distribution in respect of the quarter ending March 31, 2013. Sales by Holdco or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we provided registration rights to Holdco. Under our Operating Agreement, our manager and its affiliates have additional registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.

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Tax Risks to Common Unitholders

Our tax treatment depends on our being treated as a partnership for U.S. federal income tax purposes and having no liability for U.S. federal income tax. If the U.S. Internal Revenue Service, or the IRS, were to treat us as a corporation for U.S. federal income tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

        The anticipated after tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for U.S. federal income tax purposes. However, it is possible in certain circumstances for a limited liability company such as us to be treated as a corporation for U.S. federal income tax purposes. Although we do not believe that we will be so treated based upon our current operations, a change in our business (or a change in current law) could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

        If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate. We may also be liable for state income taxes in addition to federal income taxes. Distributions to unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to them. Because corporate income taxes would be imposed upon us, our cash available for distribution to unitholders would be substantially reduced, likely causing a substantial reduction in the value of our common units.

        Our Operating Agreement provides that the adverse impact of any such additional entity-level taxation will be borne by all members.

Notwithstanding our treatment for U.S. federal income tax purposes, we are subject to certain non-U.S. taxes. If a taxing authority were to successfully assert that we have more tax liability than we anticipate or legislation were enacted that increased the taxes to which we are subject, the cash available for distribution to unitholders could be further reduced.

        Most of our business operations and subsidiaries are subject to income, withholding and other taxes in the non-U.S. jurisdictions in which they are organized or from which they receive income, reducing the amount of cash available for distribution. In computing our tax obligation in these non-U.S. jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing tax authorities, such as whether withholding taxes will be reduced by the application of certain tax treaties. Upon review of these positions the applicable authorities may not agree with our positions. A successful challenge by a tax authority could result in additional tax being imposed on us, reducing the cash available for distribution to unitholders. In addition, changes in our operations or ownership could result in higher than anticipated tax being imposed in jurisdictions in which we are organized or from which we receive income and further reduce the cash available for distribution. Although these taxes may be properly characterized as foreign income taxes, unitholders may not be able to credit them against their liability for U.S. federal income taxes on their share of our earnings.

        Our Operating Agreement provides that the adverse impact of any such additional entity-level taxation will be borne directly or indirectly by all members.

If we were subjected to a material amount of additional entity-level taxation by individual states and localities, it would reduce our cash available for distribution to unitholders.

        Changes in current state law may subject us to additional entity-level taxation by individual states and localities, reducing our cash available for distribution to unitholders. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise and other

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forms of taxation. Our Operating Agreement provides that the adverse impact of any such additional entity-level taxation will be borne by all members.

Recently proposed legislation in Canada relating to the taxation of partners in a Canadian partnership could result in a significant increase in Canadian taxes paid over the next five years.

        Under Canadian tax law, partners in a partnership report their shares of the partnership's income or loss each year. When the partnership uses a different tax year than the partner, the partner generally takes into account the income or loss accrued for the partnership year that ends within the partner's tax year. Under legislation recently proposed in the Canadian parliament, however, certain partners would be required to accrue their shares of the partnership's income through the end of the partners' tax years (even if the partnership's year has not yet ended). Changes to this system can result in the partner being required to report more than one year of the partnership's income for a single tax year.

        Certain of our subsidiaries are partners in partnerships and would be required to report additional income and pay additional Canadian income taxes under the proposed legislation. Although we would be allowed to spread the accelerated income over a prospective five year period, if such legislation were to be enacted in its current form, the amount of Canadian income taxes paid by us could increase by a material amount, reducing the cash available for distribution to unitholders. At this time, we cannot predict the form of legislation that might ultimately be enacted or the specific effects of that legislation on us

We may become a resident of Canada and have to pay tax in Canada on our worldwide income, which could reduce our earnings, and unitholders could then become taxable in Canada in respect of their ownership of our units. Moreover, as a non-resident of Canada we may have to pay tax in Canada on our Canadian source income, which could reduce our earnings.

        Under the Income Tax Act (Canada), or the Canadian Tax Act, a company that is resident in Canada is subject to tax in Canada on its worldwide income, and unitholders of a company resident in Canada may be subject to Canadian capital gains tax on a disposition of its units and to Canadian withholding tax on dividends paid in respect of such units.

        Our place of residence, under Canadian law, would generally be determined based on the place where our central management and control is, in fact, exercised. It is not our current intention that our central management and control be exercised in Canada. Based on our operations, we do not believe that we are, nor do we expect to be, resident in Canada for purposes of the Canadian Tax Act, and we intend that our affairs will be conducted and operated in a manner such that we do not become a resident of Canada under the Canadian Tax Act. However, if we were or become resident in Canada, we would be or become subject under the Canadian Tax Act to Canadian income tax on our worldwide income. Further, unitholders who are non-residents of Canada may be or become subject under the Canadian Tax Act to tax in Canada on any gains realized on the disposition of our units and would be or become subject to Canadian withholding tax on dividends paid or deemed to be paid by us, subject to any relief that may be available under a tax treaty or convention.

Our tax treatment as a publicly-traded partnership, as a company with multinational operations as well as the tax treatment of an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

        The present tax treatment of publicly-traded partnerships, companies with multinational operations, or an investment in such entities as Niska Gas Storage Partners LLC is complex and may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the

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tax laws, treaties and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.

If a tax authority contests the positions we take, the market for our common units may be adversely impacted and the cost of any such contest will reduce our cash available for distribution to unitholders.

        The tax authorities may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and a court may not agree with these positions. Any contest with a tax authority may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with a tax authority will be borne by our members because the costs will reduce our cash available for distribution.

Unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

        Because our unitholders are treated as partners for U.S. federal income tax purposes to whom we allocate taxable income, which could be different in amount than the cash we distribute, unitholders are required to pay any U.S. federal income taxes, Medicare taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

        If unitholders sell their common units, they will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because for U.S. federal income tax purposes distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them for U.S. federal income tax purposes if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our liabilities, unitholders may incur a tax liability on the sale of their units in excess of the amount of cash they receive.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

        Investment in common units by a tax-exempt entity, such as employee benefit plans and individual retirement accounts (known as IRAs), or a non-U.S. person raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, is unrelated business taxable income and will be taxable to them. In addition, we expect to withhold taxes from distributions to non-U.S. persons at the highest applicable effective tax rate, and non-U.S. persons are required to file U.S. federal tax returns and pay tax on their shares of our taxable income attributable to our U.S. operations. Tax exempt entities (or those who intend to hold our units through an IRA) and non-U.S. persons should consult a tax advisor before investing in our common units.

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We treat each unitholder as having the same tax benefits without regard to the actual common units held. The IRS may challenge this treatment, which could adversely affect the value of the common units.

        Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of taxable income recognized by unitholders as a result of their ownership of our units. It also could affect the amount of gain from a unitholder's sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to that unitholder's tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

        We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly- traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although existing publicly-traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Moreover, our method of proration differs from the proposed Treasury Regulations with respect to allocations of certain items of income and loss. Our counsel has not rendered an opinion regarding the validity of our proration method.

The amount of taxable income or loss allocable to each unitholder depends, in part, upon values that we periodically determine for our outstanding equity interests and our assets in order to comply with federal income tax law. The IRS may challenge our determinations of these values, which could adversely affect the value of our units.

        U.S. federal income tax law requires us to periodically determine the value of our assets and to calculate the amount of taxable income or loss allocable to each partner based in part upon these values. We determine these asset values and allocations in part by reference to values that we determine for our outstanding equity interests. The IRS may challenge our valuations and related allocations. A successful IRS challenge to these valuations or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from a unitholder's sale of units and could have a negative impact on the value of units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, such unitholder would no longer be treated as the owner of those units for tax purposes during the period of the loan and may recognize gain or loss from the disposition.

        Because a unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as an owner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder in respect of those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion

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regarding the treatment of a unitholder whose common units are loaned to a short seller. Unitholders desiring to assure their status as owners of units for tax purposes and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from loaning their units.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our tax partnership for U.S. federal income tax purposes.

        We will be considered to have terminated our tax partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year and may result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred.

Unitholders are likely subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

        In addition to U.S. federal income taxes, unitholders are likely subject to state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in California, Oklahoma and Texas. Each of California and Oklahoma currently imposes a personal income tax on individuals. Many states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is the unitholder's responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

Item 1B.    Unresolved Staff Comments

        None.

Item 2.    Properties.

        Our storage facilities are constructed and maintained on property owned by others. Rights to use our reservoirs for natural gas storage are held pursuant to natural gas storage leases with the surface owners of the lands where the reservoirs are situated as well as mineral owner agreements and similar instruments entered into with the holders of subsurface mineral interests in such lands. Rights for the lands used for our pipelines are derived from right-of-ways, easements, leases and other similar land-use agreements.

        For more information on our material properties, see "Business—Our Assets" in Item 1 of this Report.

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Item 3.    Legal Proceedings

        We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business.

Item 4.    (Removed and Reserved).

PART II

Item 5.    Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities.

    Our Limited Liability Company Interests

        As of June 10, 2011, we had outstanding 33,804,745 common units, 33,804,745 subordinated units, a 2% managing member interest and incentive distribution rights, or IDRs. The common units and subordinated units together represent all of our limited partner interests and 98% of our total ownership interests, in each case excluding our IDRs. As discussed below under "Our Cash Distribution Policy—Incentive Distribution Rights," the IDRs represent the right to receive increasing percentages, up to a maximum of 48%, of the cash we distribute from operating surplus (as defined below) in excess of $0.4025 per unit per quarter. Holdco currently owns approximately 48.2% of our outstanding common units, all of our subordinated units and all of our IDRs.

        Our common units, which represent limited liability company interests in us, are listed on the NYSE under the symbol "NKA." Our common units have been traded on the NYSE since May 12, 2010. Prior to that time, there was no public market for our stock. The following table sets forth for the indicated periods the high and low sales prices per unit for our common units on the NYSE:

Three Months Ended
  High   Low  

June 30, 2010 (from May 12, 2010)

  $ 19.98   $ 17.01  

September 30, 2010

  $ 19.60   $ 17.93  

December 31, 2010

  $ 20.60   $ 19.32  

March 31, 2011

  $ 22.11   $ 19.25  

        On June 10, 2011, the closing market price for our common units was $19.24 per unit.

        We have gathered tax information from our known unitholders and from brokers/nominees and, based on the information collected, we estimate our number of beneficial unitholders to be approximately 15,000 at March 31, 2011.

        Cash distributions paid to unitholders for the year ended March 31, 2011 were as follows:

Record Date
  Payment Date   Per Unit  

August 10, 2010

  August 13, 2010   $ 0.173  

November 11, 2010

  November 12, 2010   $ 0.35  

February 7, 2011

  February 11, 2011   $ 0.35  

May 6, 2011

  May 13, 2011   $ 0.35  

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        We generally make quarterly cash distributions of substantially all of our available cash, generally defined as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as our manager deems appropriate. Distributions of cash paid by us to a unitholder will not result in taxable gain or income except to the extent the aggregate amount distributed exceeds the tax basis of the Common Units owned by the unitholder.

        We are a publicly traded LLC and are not subject to federal income tax on our U.S.-sourced income. Instead, unitholders are required to report their allocable share of our income, gain, loss and deduction, regardless of whether we make distributions. We have made quarterly distribution payments since August 2010.

        We are subject to withholding taxes by the Canada Revenue Agency ("CRA") for the portion of our quarterly distributions that are derived from our Canadian operations. Unitholders receive foreign tax credits equal in amount to the amount that we pay to the CRA and can apply these credits against other Canadian sourced income, to the extent that they may have any.

        The following graph reflects the changes in closing prices from May 12, 2010, the first trading day of our common units on the NYSE, through March 31, 2011:


NKA Unit Price

GRAPHIC

    Holders

        As of June 10, 2010, there were 4 holders of record of our common units. The number of record holders does not include holders of units in "street names" or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

    Our Cash Distribution Policy

        Our Operating Agreement contains a policy pursuant to which we pay regular quarterly cash distributions in an aggregate amount equal to substantially all of our available cash. Under the policy, each quarter our board makes a determination of the amount of cash available for distribution to members. Our board determines cash available for distribution to be an amount equal to all cash on hand at the end of the quarter, less reserves for the prudent conduct of our business (including

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reserves for capital expenditures, operating expenditures and debt service) or for distributions to members in respect of future quarters. Our board's determination of available cash takes into account the need to maintain certain cash reserves to preserve our distribution levels across seasonal and cyclical fluctuations in our business. Our board may determine to reserve or reinvest excess cash in order to permit gradual or consistent increases in quarterly distributions and may borrow to fund distributions in quarters when we generate less available cash than necessary to sustain or grow our cash distributions per unit.

        Consistent with our Operating Agreement, our board has, to date, declared a minimum quarterly distribution of $0.35 per unit per complete quarter, or $1.40 per unit per year, for each complete fiscal quarter since our IPO. This equates to an aggregate cash distribution of approximately $24.1 million per quarter or $96.6 million per year, in each case based on the number of common units and subordinated units and the 2% managing member interest currently outstanding. These distributions reflect the Board's basic judgment that our unitholders will be better served by our distributing our available cash, after expenses and reserves, rather than retaining it. Because we believe we will generally finance any expansion capital investments from external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, we believe that our investors are best served by our distributing all of our available cash. Because we are not subject to entity-level U.S. federal income tax, we will have more cash to distribute to unitholders than would be the case if we were subject to such tax.

    Managing Member Interest

        Our manager is entitled to 2% of all distributions that we make prior to our liquidation. Our manager has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current managing member interest if we issue additional membership interests in the future. The manager's initial 2% interest in distributions will be reduced if we issue additional membership interests in the future and our manager does not contribute a proportionate amount of capital to us to maintain its 2% managing member interest.

    Incentive Distribution Rights

        Incentive distribution rights represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Holdco holds the incentive distribution rights but may transfer these rights, subject to restrictions in our Operating Agreement.

        If for any quarter:

    we have distributed cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

    we have distributed cash from operating surplus to the common unitholders in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

        then additional distributions from operating surplus for that quarter will be made in the following manner:

    first, 98% to all unitholders, pro rata, and 2% to the manager, until each unitholder receives a total of $0.4025 per unit for that quarter (the "first target distribution");

    second, 85% to all unitholders, pro rata, 2% to the manager and 13% to the holders of incentive distribution rights, pro rata, until each unitholder receives a total of $0.4375 per unit for that quarter (the "second target distribution");

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    third, 75% to all unitholders, pro rata, 2% to the manager and 23% to the holders of incentive distribution rights, pro rata, until each unitholder receives a total of $0.5250 per unit for that quarter (the "third target distribution"); and

    thereafter, 50% to all unitholders, pro rata, 2% to the manager and 48% to the holders of incentive distribution rights, pro rata.

        In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.

    Limitations on Cash Distributions; Ability to Change Our Cash Distribution Policy

        There is no guarantee that unitholders will receive quarterly cash distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including:

    Our cash distribution policy may be affected by restrictions on distributions under our $400.0 million credit agreement and by the indenture relating to our senior notes as well as by restrictions in future debt agreements that we enter into. Specifically, our credit agreement and indenture contain financial tests and covenants, commensurate with companies of our credit quality that we must satisfy. Should we be unable to satisfy these restrictions under our $400.0 million credit agreement or indenture or if we are otherwise in default under our $400.0 million credit agreement or indenture, we would be prohibited from making cash distributions to unitholders notwithstanding our stated cash distribution policy. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our 8.875% Senior Notes Due 2018" and "—Our $400.0 Million Credit Agreement."

    Our board's determination of cash available for distribution takes into account reserves for the prudent conduct of our business (including reserves for cash distributions to our members), and the establishment of (or any increase in) those reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate.

    Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our board.

    Because we have limited history operating with a policy of distributing substantial amounts of cash and have grown rapidly through expansion of our facilities, we have a limited historical basis upon which to rely in our determination as to whether we will have sufficient available cash to pay the minimum quarterly distribution.

    Under Section 18-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

    We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business, including capital needs to maintain our storage facilities, to finance our proprietary optimization program and to fund the margin requirements of our hedging instruments.

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Sales of Unregistered Securities

        In connection with our IPO, we issued 13,679,745 common units and 33,804,745 subordinated units to Holdco and its affiliates, which contributed to us our natural gas storage assets. On June 11, 2010, upon the expiration of the underwriters overallotment option, we issued an additional 2,625,000 common units to Holdco. These units were issued in private placements exempt from registration under the Securities Act.

Use of Proceeds from the Sales of Registered Securities

        On May 17, 2010, we completed our IPO of common units pursuant to a Registration Statement on Form S-1, as amended (Reg. No. 333-165007), that was declared effective on May 10, 2010. Under the registration statement, we sold an aggregate of 17,500,000 common units to the public at a price of $20.50 per common unit. Goldman, Sachs & Co., Morgan Stanley & Co. Incorporated, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, RBC Capital Markets Corporation, and UBS Securities LLC acted as joint book-running managers of the offering. The offering commenced on April 30, 2010 and closed on May 17, 2010. As a result of our IPO, we raised a total of $358.8 million in gross proceeds, and approximately $331.4 million in net proceeds after deducting underwriting discounts and commissions of $22.0 million, structuring fees of $1.3 million and offering expenses of approximately $4.0 million.

        We used approximately $271.4 million of the net proceeds of this offering to fully repay all borrowings under our revolving credit facilities. We have used the remainder for general company purposes, including funding a portion of the cost of our expansion projects.

Equity Compensation Plan

        As of March 31, 2011, there were no equity compensation plans providing for issuances of equity securities of the registrant. See "Item II. Executive Compensation—Compensation Discussion and Analysis—Long-Term Incentive Plan" for information about our Long-Term Incentive Plan, which became effective at the time of our IPO.

Item 6.    Selected Financial Data.

        The following table shows selected historical consolidated financial and operating data of Niska Gas Storage Partners LLC for the fiscal year ended March 31, 2011, and Niska Predecessor, consisting of the combined financial statements of Niska GS Holdings I, L.P. and Niska GS Holdings II, L.P. for the fiscal years ended March 31, 2010, 2009 and 2008 and for the period from May 12, 2006 to March 31, 2007. Niska Predecessor acquired our predecessor business from EnCana Corporation in a two step transaction. In the first step of the transaction, which closed on May 12, 2006, Niska Predecessor acquired all of our assets except Wild Goose. In the second phase of the transaction, which closed on November 16, 2006, Niska Predecessor acquired Wild Goose. This document does not include financial statements relating to the assets prior to their acquisition by Niska Predecessor because of the reasons explained below. As a result, the financial statements of Niska Predecessor for the period ended March 31, 2007 are not directly comparable to financial statements for subsequent periods.

        Financial information for periods prior to May 12, 2006 and for Wild Goose for periods prior to November 16, 2006 is not presented. Niska Predecessor was provided with historical financial data for the years ended December 31, 2003, 2004 and 2005 prepared by EnCana Corporation in accordance with Canadian GAAP. Niska Predecessor was not provided with any financial information, audited or otherwise, for the periods from January 1, 2006 through May 11, 2006, in the case of all assets other than Wild Goose, or through November 16, 2006, in the case of Wild Goose. We are not affiliated in any way with EnCana Corporation and we are unable to prepare financial statements for the assets of

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Niska Predecessor for periods prior to the dates that Niska Predecessor acquired such assets from EnCana Corporation. We also do not have access to the information necessary to convert the financial information prepared by EnCana Corporation from Canadian GAAP to U.S. GAAP. This financial information rests peculiarly within the knowledge of EnCana Corporation and cannot be obtained by Niska Predecessor without unreasonable effort or expense. Niska Predecessor did not rely on the financial and operating data prepared by EnCana Corporation when it acquired the assets from EnCana Corporation, and Niska Predecessor materially changed the operation of the assets after it acquired them and did not assume all of the liabilities and obligations associated with EnCana Corporation's operation of the assets. Accordingly, the financial and operating data prepared by EnCana Corporation is not readily comparable to Niska Predecessor's financial statements. We, and our auditors, are unable to verify the financial information prepared by EnCana Corporation. In particular, any intercompany profits arising from transactions between the Canadian and U.S. operations (and other EnCana Corporation subsidiaries) cannot be identified and as such, profits that would have been generated from such transactions are not eliminated from revenues and expenses. Additionally, the financial statements prepared by EnCana Corporation for its Canadian operations do not include a line item or narrative regarding taxes and we are unable to determine the appropriateness of the exclusion of taxes from the financial statements.

        The historical consolidated financial data presented for the year ended March 31, 2011 and the combined financial data presented for the years ended March 31, 2010, 2009 and 2008 and the period from May 12, 2006 to March 31, 2007 is derived from audited financial statements for those respective periods, and should be read together with and is qualified in its entirety by reference to, the historical audited consolidated and combined financial statements, respectively of Niska Gas Storage Partners LLC and Niska Predecessor and the accompanying notes included in Item 8.

        Moreover, the table should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in Item 7.

 
  Niska   Niska Predecessor  
 
  Years Ended March 31,   Period from
May 12, 2006
to March 31,
2007(1)
 
 
  2011   2010   2009   2008  
 
  (dollars in millions)
 

Consolidated Statement of Earnings Data:

                               

Revenues(2)

  $ 230.1   $ 270.5   $ 252.2   $ 232.9   $ 193.8  

Depreciation and amortization

    46.9     43.1     54.8     45.5     46.6  

Interest and debt expense

    77.0     38.1     53.5     73.9     60.2  

Earnings before income taxes(3)

    27.4     121.1     96.9     45.0     41.4  

Net earnings(3)

    57.5     53.2     108.8     48.3     53.5  

Balance Sheet and Other Financial Data (at period end):

                               

Total current assets

  $ 443.7   $ 430.0   $ 355.9   $ 225.9   $ 228.3  

Total assets

    2,061.3     2,099.4     2,002.9     1,905.2     1,931.1  

Total debt (including current portion)

    800.0     800.0     662.0     693.8     833.7  

Members' equity

    917.0     929.8     977.4     867.1     820.5  

Operational Data: (unaudited)

                               

Effective working gas capacity (Bcf)(4)

    204.5     185.5     163.7     155.3     144.2  

Capacity added during the period (Bcf)

    19.0     21.8     8.4     11.1      

Percent of operated capacity leased to third parties(5)

    71.4 %   79.5 %   89.7 %   89.9 %   97.0 %

(1)
Period data includes Wild Goose from November 16, 2006 to March 31, 2007.

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(2)
Revenues include optimization revenues, which are presented net of cost of goods sold.

(3)
Earnings before income taxes and net earnings include asset impairments of $0.7 million and other income of $0.1 million in 2010, impairment of goodwill of $22.0 million, asset impairments of $2.1 million and other income of $20.8 million in 2009 and impairment of assets of $2.5 million and loss on sale of assets of $2.3 million in 2008. The 2009 impairment of goodwill related primarily to the goodwill of a subsidiary that was written down to zero following a year of overall negative economic conditions. Other income in 2009 consisted primarily of a recovery of $17.8 million and an additional $2.7 million in interest as a result of the settlement of a dispute relating to the acquisition of our predecessor business from EnCana Corporation.

(4)
Represents operated and NGPL capacity.

(5)
Excludes NGPL leased capacity of 8.5 Bcf.

Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations.

        The historical financial statements included elsewhere in this document reflect the consolidated assets, liabilities and operations of Niska Gas Storage Partners LLC ("Niska Partners" or "Niska") as at and for the year ended March 31, 2011, and the combined assets, liabilities and earnings of Niska Predecessor as at and for the years ended March 31, 2010 and 2009. The following discussion of the historical consolidated and combined financial condition and results of operations should be read in conjunction with the historical financial statements and accompanying notes of Niska and Niska Predecessor included elsewhere in this document. In addition, this discussion includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from statements we make. See "Forward-Looking Statements." Factors that could cause actual results to differ include those risks and uncertainties that are discussed in "Risk Factors."

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        A summary of financial and operating data for the years ended March 31, 2011, 2010 and 2009 is as follows:

 
  Niska   Niska Predecessor  
 
  Year Ended March 31,  
 
  2011   2010   2009  
 
  (dollars in millions)
 

Consolidated Statement of Earnings and Comprehensive Income Data:

                   

Revenues

                   
 

Long-term contract revenue

  $ 119.6   $ 109.8   $ 110.7  
 

Short-term contract revenue

    41.0     58.4     52.0  
 

Optimization, net(1)

    69.5     102.3     89.4  
               

    230.1     270.5     252.2  

Expenses (Income):

                   
 

Operating

    44.8     38.2     45.4  
 

General and administrative

    34.6     36.6     24.2  
 

Depreciation and amortization

    47.0     43.1     54.8  
 

Interest

    77.0     38.1     53.5  
 

Impairment of assets(2)

        0.7     24.2  
 

Other income(3)

    (0.2 )   0.0     (20.8 )
 

Foreign exchange gains

    (0.5 )   (7.2 )   (25.8 )
               
 

Earnings before income taxes

    27.4     121.1     96.9  
 

Income tax expense/(benefit):

                   
 

Current

    1.2     1.3     0.3  
 

Deferred

    (31.3 )   66.6     (12.2 )
               

    (30.1 )   67.9     (11.9 )
               

Net earnings and comprehensive income

  $ 57.5   $ 53.2   $ 108.8  
               

Reconciliation of Adjusted EBITDA to net income:

                   

Net earnings

  $ 57.5   $ 53.2   $ 108.8  

Add/(deduct):

                   
 

Interest expense

    77.0     38.1     53.5  
 

Income tax expense/(benefit)

    (30.1 )   67.9     (11.9 )
 

Depreciation and amortization

    47.0     43.1     54.8  
 

Unrealized risk management losses/(gains)

    44.8     24.7     (82.8 )
 

Foreign exchange gains

    (0.5 )   (7.2 )   (25.8 )
 

Loss on sale of assets

             
 

Impairment of assets

        0.7     24.1  
 

Other income

    (0.2 )   0.0     (20.8 )
 

Unrealized inventory impairment writedown

        3.4     62.3  
               

Adjusted EBITDA

  $ 195.5   $ 223.9   $ 162.2  
               
 

Less:

                   
   

Cash interest expense, net

  $ (76.0 ) $ (40.2 ) $ (45.1 )
   

Income taxes paid

    (0.5 )   (0.3 ) $ (0.3 )
   

Maintenance capital expenditures

    (1.7 )   (0.9 ) $ (1.4 )
   

Other income

    0.2   $ (0.0 ) $ 20.8  
               

Cash Available for Distribution

  $ 117.5   $ 182.5   $ 136.2  
               

Balance Sheet Data (at period end):

                   

Total assets

  $ 2,061.3   $ 2,099.3   $ 2,002.9  

Property, plant and equipment, net of accumulated depreciation

    964.1     983.0     940.2  

Long-term debt(4)

    800.0     800.0     597.0  

Total partners' equity

    917.0     929.8     977.4  

Operating Data (unaudited):

                   

Effective working gas capacity (Bcf)(5)

    204.5     185.5     163.7  

Capacity added during period (Bcf)

    19.0     21.8     8.4  

Percent of operated capacity contracted to third parties(6)

    71.4 %   79.5 %   89.7 %

(1)
Optimization revenue is presented net of cost of goods sold. Net optimization revenues include unrealized risk management gains/losses and write-downs of inventory. We had an unrealized risk management loss of $44.8 million for the year ended March 31, 2011, an unrealized risk management loss of $24.7 million for the year ended March 31, 2010 and an unrealized

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    risk management gain of $82.8 million for the year ended March 31, 2009. We had a write-down of inventory of $62.3 million for the year ended March 31, 2009, compared to $3.4 million for the year ended March 31, 2010. Excluding these non-cash items, which do not affect Adjusted EBITDA, our realized optimization revenues were $114.3 million for the year ended March 31, 2011, $130.4 million for the year ended March 31, 2010 and $68.9 million for the year ended March 31, 2009.

(2)
Impairment charges in the fiscal year ended March 31, 2009 primarily relate to the goodwill in a subsidiary that was written down from its carrying amount of $22.0 million to zero. The impairment charges were recorded following a year of overall negative economic conditions.

(3)
Other income for the fiscal year ended March 31, 2009 includes a recovery of $17.8 million in addition to $2.7 million in interest as a result of the settlement of a dispute relating to the acquisition of our predecessor business from EnCana Corporation.

(4)
Excludes revolver drawings, which are recorded in current liabilities.

(5)
Represents operated and NGPL capacity.

(6)
Excludes NGPL leased capacity of 8.5 Bcf.

        The following table sets forth volume utilized by, and revenue and fees/margins derived from, LTF contracts, STF contracts and proprietary optimization transactions for the fiscal years ended March 31, 2011, 2010 and 2009:

 
  Niska   Niska Predecessor  
 
  Year Ended March 31,  
 
  2011   2010   2009  

Storage Capacity (Bcf) utilized by:

                   

LTF Contracts

    104.7     103.9     106.3  

STF Contracts

    35.2     36.8     32.9  

Proprietary optimization transactions

    64.6     44.8     24.5  
               

Total

    204.5     185.5     163.7  
               

Revenue (in millions)

                   

LTF Contracts

  $ 119.6   $ 109.8   $ 110.7  

STF Contracts

    41.0     58.4     52.0  

Realized proprietary optimization transactions

    114.3     130.4     69.0  

Unrealized risk management gains (losses)

    (44.8 )   (24.7 )   82.8  

Unrealized inventory writedown

        (3.4 )   (62.3 )
               

Total

  $ 230.1   $ 270.5   $ 252.2  
               

Fees/Margins ($/Mcf)

                   

LTF Contracts

  $ 1.14   $ 1.06   $ 1.04  

STF Contracts

    1.16     1.59     1.58  

Realized proprietary optimization transactions

    1.77     2.91     2.81  

    Non-GAAP Financial Measure

    Adjusted EBITDA

        We use the non-GAAP financial measure Adjusted EBITDA in this report. A reconciliation of Adjusted EBITDA to net earnings, its 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, foreign exchange gains and losses, unrealized inventory impairment writedowns, gains and losses on asset dispositions, asset impairments and other income. We believe the adjustments for other income, which is comprised primarily of income from an arbitration award granted to us in the fiscal year ended March 31, 2009, are similar in

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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. Adjusted EBITDA is used as a supplemental financial measure 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 GAAP measure most directly comparable to Adjusted EBITDA is net earnings. The non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to net earnings. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Adjusted EBITDA should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net earnings and is defined differently by different companies, our definition of Adjusted EBITDA 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.

How We Evaluate Our Operations

        We generate substantially all of our revenue through long and short-term contracts for the storage of natural gas for third-party customers and the proprietary optimization of storage capacity that is

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uncontracted, underutilized or available only on a short-term basis. We evaluate our business on the basis of the following key measures:

    volume and fees derived from LTF contracts;

    volume and fees derived from STF contracts;

    volume and margin derived from our proprietary optimization activities;

    operating, general and administrative expenses;

    Adjusted EBITDA;

    capitalization and leverage; and

    borrowing base revolver availability and liquidity.

    Volume and Fees Derived from LTF Contracts

        We provide multi-year, multi-cycle storage services to our customers under LTF contracts. From our inception on May 12, 2006 to March 31, 2011, we utilized an average of approximately 67.6% of our operated capacity for our LTF strategy. The volume weighted average life of our LTF contracts at March 31, 2011 was 2.6 years. Under our LTF contracts, our customers are obligated to pay us monthly reservation fees which are fixed charges owed to us regardless of the actual use by the customer. When a customer utilizes the capacity that is reserved under these contracts, we also collect a variable fee designed to allow us to recover our variable operating costs. Reservation fees comprise over 90% of the revenue generated under LTF contracts and provide a baseline of revenue in excess of our general and administrative and operating costs. From inception to March 31, 2011, our LTF contracts generated average revenues, including both reservation and variable fees, of $1.03 per Mcf. We evaluate both the volume and price of our LTF contracting, which can indicate the effectiveness of our marketing efforts as well as the relative attractiveness of LTF contracts in comparison to our other revenue strategies. During periods when prices are higher, we will utilize more of our capacity under LTF contracts.

    Volume and Fees Derived from STF Contracts

        In addition, we provide short term services for customers under STF contracts. From inception to March 31, 2011, we utilized an average of approximately 16.7% of our operated capacity for our STF strategy. STF contracts typically have terms of less than one year. Under an STF contract, a customer pays a fixed fee to inject a specified quantity of natural gas on a specified date or dates and to store that gas in our storage facilities until withdrawal on a specified future date or dates. Because STF contracts set forth specified future injection or withdrawal dates, we enter into offsetting transactions to capture incremental value as spot and future natural gas prices fluctuate prior to that activity date. We monitor the volume used for and evaluate the fees generated under our STF contracts. The fees we are able to generate from our STF contracts reflect market conditions (including interest rates) and the effectiveness of our marketing efforts. From inception to March 31, 2011, our STF contracts generated average revenues of $1.61 per Mcf. The capacity utilized for STF contracts depends on, among other things, the total capacity of our storage facilities that is not being utilized for LTF contracts and the contract rates available for STF contracts.

    Volume and Margin Derived from Our Proprietary Optimization Activities

        From inception to March 31, 2011, we utilized an average of approximately 15.7% of our operated capacity and all of our NGPL capacity for our proprietary optimization strategy. When market conditions warrant, we enter into economically hedged transactions with available capacity to achieve margins higher than can be obtained from third-party contracts. Because we simultaneously hedge our

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transactions, we are able to determine in advance the minimum margins that will be realized and add incremental margins by re-hedging as market conditions change.

        At times, if spreads move favorably, such as if winter gas prices fall below forward prices for the following summer, we can further increase margins that have been substantially locked in by choosing to hold inventory into a subsequent period and re-hedging the transaction. This has the result of increasing our cash flow margins and overall profitability, although for accounting purposes the income is deferred into a later period, causing the appearance of cyclicality in our reported revenues and profits.

        When evaluating the performance of our optimization business, we focus on our realized optimization margins, excluding the impact of unrealized hedging gains and losses and inventory write-downs. For accounting purposes, our net realized 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 substantially all inventory is economically hedged, any inventory write-downs are offset by hedging gains and any unrealized hedging losses are offset by gains when the inventory is sold. From inception to March 31, 2011, our proprietary optimization business generated average margins of $2.61 per Mcf on a realized basis before unrealized marked to market gains and losses and inventory write-downs.

    Operating Expenses

        Our most significant operating expenses are fuel and electricity costs. These operating expenses vary significantly based upon the amount of gas we inject or withdraw throughout the year and the price of the energy commodity at the time of purchase. Variable operating expenses are partially offset by the variable fees we collect from our LTF contracts. The smaller, fixed component of our operating expenses include salaries and labor, parts and supplies, surface and mineral lease rentals and other general operating costs. These fixed operating expenses are more stable from year to year but can fluctuate due to unforeseen repairs, equipment malfunctions and overhauls of compressors or engines.

    General and Administrative Expenses

        Our general and administrative expenses primarily consist of employee compensation, legal, accounting and tax fees and our office lease.

    Adjusted EBITDA

        We define Adjusted EBITDA as net earnings before interest, income taxes, depreciation and amortization, unrealized risk management gains and losses, foreign exchange gains and losses, unrealized inventory impairment writedown, gains and losses on asset dispositions, asset impairments and other income. Our Adjusted EBITDA is not a presentation made in accordance with GAAP. We utilize Adjusted EBITDA in order to be able to compare our results against our peers, regardless of differences in financing, and by excluding non-recurring items to be able to compare to our own results for other periods.

    Capitalization and Leverage

        We regularly monitor our leverage statistics to ensure a conservative capital structure. As of March 31, 2011, we had a debt to Adjusted EBITDA ratio of 4.1x, debt to capitalization of 47%, and a fixed charge coverage ratio of 2.5x. We expect to maintain or improve these ratios over time in order to maintain access to available capital markets, a competitive cost of capital and financial flexibility to grow our business and increase our cash distributions.

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    Borrowing Base Revolver Availability and Liquidity

        Funding the purchase of proprietary optimization inventory can consume a significant portion of our available working capital. In times of higher natural gas prices, holding large inventories of proprietary gas may cause us to consume a substantial portion of our availability under our credit facilities. We therefore closely monitor the utilization and remaining available capacity under our credit facilities and actively pursue additional STF contracts when we determine it is appropriate to maintain liquidity.

Factors that Impact Our Business

        Factors that impact the performance of specific components of our business from period to period include the following:

    Market Price for LTF Contracts

        The price available in the marketplace when negotiating new or replacement LTF contracts reflects demand and affects the amount of storage capacity utilized for LTF contracts that year, and thus the amount of capacity utilized for STF contracts or proprietary optimization for that year. We may increase the capacity that we use for LTF contracts at times of higher market prices and demand. Lower market prices for LTF contracts may result from lower seasonal spreads or a more competitive environment for storage services.

    Gas Storage Capacity Growth

        Capacity added in the prior year or added during a year is expected to generate incremental revenue.

    Carried Inventory

        When winter gas prices fall below forward prices for the following summer, we may defer the withdrawal of proprietary optimization inventory until the next fiscal year in order to add incremental margin and economic value. This results in the deferral of realized earnings and cash flow from one fiscal year to the next. In some cases, we can mitigate the impact of deferred earnings and cash flow by entering into STF contracts that straddle the two fiscal years.

    Variable Costs

        The variable operating costs of our facilities (mostly comprised of costs associated with fuel or electricity for compressor operations) are affected by the amount and price of energy used to inject and withdraw gas from our facilities and by the number and timing of gas injections and withdrawals. For example, if we experience large injections of gas in the early summer (instead of a steady rate of injections throughout the summer) we would have greater than expected costs in our first quarter and lower than expected costs in our second quarter. A mild winter could lead to less withdrawals in total, and therefore lower overall variable costs. These cost variances would be partially offset by similar variances in contract revenues.

    Carrying Costs

        Our cost of capital and the amount of our working capital availability impacts the amount of capacity utilized for proprietary optimization as compared to STF contracts. A higher cost of capital relative to that of our customers or less availability will generally lead to less volume used for proprietary optimization transactions. In general, higher carrying costs for us or our customers result in lower margins for us.

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    Customer Usage Patterns

        Incremental revenue opportunities in the form of STF or proprietary optimization transactions may arise for us if capacity usage by our LTF customers is underutilized or offset by other LTF customers.

    Weather

        Weather extremes and variability directly affect our margins. Very mild years tend to reduce revenue generated under our STF and proprietary optimization strategies, while years with very hot summers, very cold winters or a number of significant storms tend to increase the revenue generated under those strategies.

Segment Information

        Our 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 our inception, we have operated along functional lines in our commercial, engineering and operations teams for operations in Alberta, northern California and the U.S. midcontinent. All functional lines and facilities offer the same services: firm storage contracts, short-term firm services and optimization. All services are delivered using reservoir storage. We measure profitability consistently along all functional lines based on revenues and earnings before interest, taxes, depreciation and amortization, before unrealized risk management gains and losses. We have aggregated our functional lines and facilities into one reportable segment as at and for the fiscal years ended March 31, 2011, 2010 and 2009.

        Information pertaining to our LTF, STF and proprietary optimization revenues is presented in the consolidated and combined statements of earnings and comprehensive income. All facilities have the same types of customers: major companies in the energy industry, industrial, commercial, and local distribution companies and municipal energy consumers.

Results of Operations

Fiscal Year Ended March 31, 2011 Compared to Fiscal Year Ended March 31, 2010

        The fiscal year ended March 31, 2011 was characterized by an environment of stable natural gas prices and reduced volatility. These factors combined to reduce seasonal natural gas storage spreads and limited revenue opportunities within our optimization and STF strategies. Notwithstanding these market conditions, we generated $195.6 million of adjusted EBITDA and $117.6 million of cash available for distribution. In addition, we continued our organic strategy by expanding our facilities by 19.0 Bcf at a cost of approximately $1.86/ Mcf (including accrued expenditures and transfers of cushion gas).

        Revenue.    Revenues for the fiscal year ended March 31, 2011 decreased by 14.9% to $230.1 million from $270.5 million for the fiscal year ended March 31, 2010. This decrease was primarily attributable to the following:

    LTF Revenues.  LTF revenues for the fiscal year ended March 31, 2011 increased by 8.9% to $119.6 million from $109.8 million for the fiscal year ended March 31, 2010. This increase was primarily attributable to higher reservation fees earned on the renewal or initiation of certain LTF contracts which increased the fee to $1.14 per Mcf for the year ended March 31, 2011 from $1.06 per Mcf for the year ended March 31, 2010. In addition, approximately 66% of LTF revenue is transacted in Canadian dollars. The Canadian dollar strengthened approximately 7% in relation to the U.S. dollar during the current fiscal year.

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    STF Revenues.  STF revenues for the fiscal year ended March 31, 2011 decreased by 29.8% to $41.0 million from $58.4 million for the fiscal year ended March 31, 2010. This decrease was primarily attributable to 26.4% decline in margins in the fiscal year ended March 31, 2011 to $1.16 per Mcf from $1.59 per Mcf in the fiscal year ended March 31, 2010. The balance relates to a 4.3% decrease in capacity utilized for STF contracts, from 36.8 Bcf for the fiscal year ended March 31, 2010 to 35.2 Bcf for the fiscal year ended March 31, 2011 as a result of increasing capacity allocated to Optimization Revenues.

    Optimization Revenues.  Net optimization revenue for the fiscal year ended March 31, 2011 decreased by 32.1% to $69.5 million from $102.3 million for the fiscal year ended March 31, 2010. This decrease was primarily attributable to lower margins realized from capacity utilized for proprietary optimization, and was also affected by timing differences relating to the realization of income. 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 Revenues.  Realized optimization revenues for the fiscal year ended March 31, 2011 decreased by 12.3% to $114.3 million from $130.4 million for the fiscal year ended March 31, 2010. This is primarily attributable to lower margins realized from the optimization strategy. The average realized margin deteriorated by 39.2% to $1.77 per Mcf from $2.91 per Mcf. Partially offsetting this was an increase in capacity that was utilized for proprietary optimization activities due to the significant amount of working capital that was available to us following our re-financing and IPO, and further aided by low commodity prices that existed during the year ended March 31, 2011. Capacity utilized for optimization activities increased by 44.2% from 44.8 Bcf for the fiscal year ended March 31, 2010 to 64.6 Bcf for the fiscal year ended March 31, 2011.

    Unrealized Risk Management Losses.  Unrealized risk management losses for the fiscal year ended March 31, 2011 were $44.8 million compared to losses of $24.7 million in the fiscal year ended March 31, 2010. Unrealized losses are attributable to prices rising after financial hedges were transacted for the fiscal year ended March 31, 2011 and 2010. As all inventory is economically hedged financially, any risk management losses (or gains) are offset by future gains (or losses) associated with the sale of proprietary inventory.

        Earnings before Income Taxes.    Earnings before income taxes for the fiscal year ended March 31, 2011 decreased by 77.4% to $27.4 million from $121.1 million for the fiscal year ended March 31, 2010. This decrease was primarily attributable to the decreased revenue discussed above, plus the following:

    Operating Expenses.  Operating expenses for the fiscal year ended March 31, 2011 increased by 17.3% to $44.8 million from $38.2 million for the fiscal year ended March 31, 2010. This increase was primarily attributable to higher property and pipeline tax costs resulting from an

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      increase in capacity at our storage facilities in conjunction with higher fuel and electricity costs resulting from increased cycling of our facilities in the fiscal year ended March 31, 2011.

 
  Niska   Niska
Predecessor
 
 
  Year Ended March 31,  
 
  2011   2010   2009  
 
  (in millions)
 

General operating costs, including insurance, vehicle leases, safety and training costs

  $ 21.6   $ 19.2   $ 21.9  

Salaries and benefits

    7.1     6.8     6.3  

Fuel and electricity

    12.9     9.4     14.2  

Maintenance

    3.2     2.8     3.0  
               

Total operating expenses

  $ 44.8   $ 38.2   $ 45.4  
               
    General and Administrative Expenses.  General and administrative expenses for the fiscal year ended March 31, 2011 decreased by 5.5% to $34.6 million from $36.6 million for the fiscal year ended March 31, 2010. This decrease was primarily attributable to lower legal, audit, and tax costs that we incurred in the prior year in relation to our IPO and re-financing efforts, offset by higher compensation and other costs associated with hiring incremental staff to support the regulatory requirements of being a public company.

 
  Niska   Niska
Predecessor
 
 
  Year Ended March 31,  
 
  2011   2010   2009  
 
  (in millions)
 

Compensation costs

  $ 23.4   $ 21.8   $ 13.4  

General costs, including office and IT costs

    4.8     3.2     6.4  

Legal, audit and regulatory costs

    6.4     11.6     4.4  
               
 

Total general and administrative expenses

  $ 34.6   $ 36.6   $ 24.2  
               
    Depreciation and Amortization.  Depreciation and amortization for the fiscal year ended March 31, 2011 increased by 9.0% to $47.0 million from $43.1 million for the fiscal year ended March 31, 2010. This increase was primarily attributable to a provision of $5.5 million to record the impact of cushion gas effectiveness at AECO Hub™, compared to a provision of $1.8 million recorded in the fiscal year ended March 31, 2010. The provision for cushion gas is an estimate based on tests of cushion gas effectiveness. Through continued monitoring over a series of withdrawal and injection cycles, management is able to better estimate the extent of effectiveness deterioration.

    Interest Expense.  Interest expense for the fiscal year ended March 31, 2011 increased to $77.0 million from $38.1 million for the fiscal year ended March 31, 2010. Our average outstanding total debt balance increased to $806.6 million for the year ended March 31, 2011 from $736.2 million for the year ended March 31, 2010. Prior to their termination on March 4, 2010, the interest rates on our previous term debt and revolving credit facilities were floating and the average interest rates applied to our term debt and revolver balances were lower by approximately 45%, in the prior year than in the fiscal year ended March 31, 2011.

        Foreign Exchange Gains.    Foreign exchange gains for the fiscal year ended March 31, 2011 decreased to $0.5 million from $7.2 million for the year ended March 31, 2010. Foreign exchange gains

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were realized on the settlement of Canadian dollar denominated receivables and payables in an appreciating Canadian dollar environment.

        Net Earnings.    Net earnings for the fiscal year ended March 31, 2011 increased by 8.1% to $57.5 million from $53.2 million for the fiscal year ended March 31, 2010. This change was primarily attributable to the lower pre-tax earnings discussed above, offset by the following:

        Income Tax Expense/(Benefit).    We recorded an income tax benefit of $30.1 million for the fiscal year ended March 31, 2011 compared to an expense of $67.9 million for the fiscal year ended March 31, 2010. This change is in part due to a one-time expense in the prior period resulting from electing a U.S. tax reporting currency for select Canadian entities. The change is also due to less income being earned in Canadian entities during the current period, combined with tax pools obtained from assets purchased, and favorable assessments completed by taxation authorities. Taxes paid in the current year were $0.5 million, compared to $0.3 million in the fiscal year ended March 31, 2010.

Fiscal Year Ended March 31, 2010 Compared to Fiscal Year Ended March 31, 2009

        Revenue.    Revenues for the fiscal year ended March 31, 2010 increased by 7.3% to $270.5 million from $252.2 million for the fiscal year ended March 31, 2009. This increase was primarily attributable to the following:

    LTF Revenues.  LTF revenues for the fiscal year ended March 31, 2010 decreased by 0.8% to $109.8 million from $110.7 million for the fiscal year ended March 31, 2009. This decrease was primarily attributable to a 37.9% decrease in fuel and commodity revenue to $8.4 million for the fiscal year ended March 31, 2010 from $13.5 million for the fiscal year ended March 31, 2009 due to lower natural gas prices. There was also a small decrease (2.2%) in the amount of capacity utilized for LTF contracts. These factors were offset by higher reservation fees earned on LTF contracts which increased by 6.7% to $0.98 per Mcf for the year ended March 31, 2010 from $0.91 per Mcf for the year ended March 31, 2009. On an aggregate basis, revenue of $1.06 per Mcf was earned during the fiscal year ended March 31, 2010, compared to revenue of $1.04 per Mcf in the fiscal 2009.

    STF Revenues.  STF revenues for the fiscal year ended March 31, 2010 increased by 12.3% to $58.4 million from $52.0 million for the fiscal year ended March 31, 2009. This increase was primarily attributable to an 11.9% increase in capacity utilized for STF contracts, from 32.9 Bcf for the fiscal year ended March 31, 2009 to 36.8 Bcf for the fiscal year ended March 31, 2010. The balance relates to a 0.3% improvement in margins in the fiscal year ended March 31, 2010 (to $1.59 per Mcf from $1.58 per Mcf).

    Optimization Revenues.  Net optimization revenue for the fiscal year ended March 31, 2010 increased by 14.4% to $102.3 million from $89.4 million for the fiscal year ended March 31, 2009. This increase was primarily attributable to increased capacity utilized for optimization, and affected by timing differences relating to the realization of income. When evaluating the performance of our optimization business, we focus on our realized optimization margins, excluding the impact of unrealized hedging gains and losses and inventory write-downs. For accounting purposes, our net optimization revenues include the impact of unrealized 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 Revenues.  Realized optimization revenues for the fiscal year ended March 31, 2010 increased by 89.3% to $130.4 million from $68.9 million for the fiscal year ended March 31, 2009. This is primarily attributable to an increase in capacity that was

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        utilized for proprietary optimization activities due to low commodity prices in the year ended March 31, 2010. Capacity utilized for optimization activities increased by 82.9% from 24.5 Bcf for the fiscal year ended March 31, 2009 to 44.8 Bcf for the fiscal year ended March 31, 2010. Also contributing was a lower cost of goods sold related to sales of inventory that was subject to a write-down in fiscal 2009 creating wider margins to the hedges locked-in at higher price levels. The average realized margin capacity utilized for optimization improved 3.5% to $2.91 per Mcf from $2.81 per Mcf.

      Unrealized Risk Management Gains/(Losses).  Unrealized risk management losses for the fiscal year ended March 31, 2010 were $24.7 million compared to a gain of $82.8 million in the fiscal year ended March 31, 2009. An unrealized loss, as opposed to an unrealized gain for the year ended March 31, 2009, is attributable to prices rising after financial hedges were transacted for the fiscal year ended March 31, 2010 compared to a falling price environment during the same period in fiscal 2009. The lower volumes of inventory carried over at the end of the year ended March 31, 2010 and therefore lower volumes being hedged is what caused the magnitude of the unrealized gains/(losses) to be lower than in fiscal 2009. As all inventory is economically hedged financially, any risk management losses (or gains) are offset by future gains (or losses) associated with the sale of proprietary inventory.

      Unrealized Inventory Writedown.  Inventory purchased early during the summers of 2008 and 2009 was written down for both of the fiscal years ended March 31, 2009 and March 31, 2010 when commodity prices retreated below the weighted average cost of the inventory. These losses were offset by gains from financial hedges that were transacted when the inventory was purchased. For the fiscal year ended March 31, 2010 this unrealized inventory writedown amounted to $3.4 million, compared to $62.3 million for the fiscal year ended March 31, 2009.

        Earnings before Income Taxes.    Earnings before income taxes for the fiscal year ended March 31, 2010 increased by 25.0% to $121.1 million from $96.9 million for the fiscal year ended March 31, 2009. This increase was primarily attributable to the increased revenue discussed above, plus the following:

    Operating Expenses.  Operating expenses for the fiscal year ended March 31, 2010 decreased by 15.8% to $38.2 million from $45.4 million for the fiscal year ended March 31, 2009. This decrease was primarily attributable to lower fuel and electricity costs resulting from lower prices in the fiscal year ended March 31, 2010.

    General and Administrative Expenses.  General and administrative expenses for the fiscal year ended March 31, 2010 increased by 51.2% to $36.6 million from $24.2 million for the fiscal year ended March 31, 2009. This increase was primarily attributable to increased compensation costs, including incentive compensation, professional services obtained in connection with the process of preparing for our IPO, hiring of additional employees, refinancing our debt facilities and tax planning. The increase in legal fees also resulted from the absence of a credit of $2.4 million recorded in 2009 as the result of the settlement of arbitration proceedings. These increases were partially offset by reduced rent expenses from subletting a portion of the company's office space in the fiscal year ended March 31, 2010.

    Depreciation and Amortization.  Depreciation and amortization for the fiscal year ended March 31, 2010 decreased by 21.4% to $43.1 million from $54.8 million for the fiscal year ended March 31, 2009. This decrease was primarily attributable to a provision recorded in the fiscal year ended March 31, 2009 of $11.9 million to record the impact of cushion gas effectiveness at AECO Hub™, compared to a provision of $1.8 million recorded in the fiscal year ended March 31, 2010. The provision for cushion gas is an estimate based on tests of cushion gas

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      effectiveness. Through continued monitoring over a series of withdrawal and injection cycles, management is able to better estimate the extent of effectiveness deterioration.

    Interest Expense.  Interest expense for the fiscal year ended March 31, 2010 decreased by 28.8% to $38.1 million from $53.5 million for the fiscal year ended March 31, 2009. Our average outstanding total debt balance increased by 2.8% to $736.2 million for the year ended March 31, 2010 from $716.0 million for the year ended March 31, 2009. The balance of our previous term debt in fiscal 2010 averaged $594.9 million prior to its termination on March 4, 2010, compared to $648.7 million for the year ended March 31, 2009. The average utilization of our previous working capital revolvers in fiscal 2010 increased by 102.4% to $136.1 million prior to its termination on March 4, 2010, compared to $67.3 million for the year ended March 31, 2010. On March 5, 2010, we entered into a $400 million revolving credit facility and we issued $800.0 million of senior unsecured notes. Prior to their termination on March 4, 2010, the interest rates on our previous term debt and revolving credit facilities were floating and the average interest rates applied to our term debt and revolver balances were lower by approximately 44.7%, in the fiscal year ended March 31, 2010 than in the fiscal year ended March 31, 2009.

        Foreign Exchange Gains.    Foreign exchange gains for the fiscal year ended March 31, 2010 decreased to $7.2 million from $25.8 million for the year ended March 31, 2009. The election by two of our Canadian subsidiaries to adopt the U.S. dollar as their functional currency for their Canadian tax returns during the fiscal year ended March 31, 2010 eliminated material foreign currency translation gains and losses attributable to deferred income taxes. Foreign exchange gains were realized on the settlement of Canadian dollar denominated receivables in an appreciating Canadian dollar environment.

        Net Earnings.    Net earnings for the fiscal year ended March 31, 2010 decreased by 51.1% to $53.2 million from $108.8 million for the fiscal year ended March 31, 2009. This change was primarily attributable to the higher pre-tax earnings discussed above, offset by the following:

            Income Tax Expense/(Benefit).     Income tax expense for the fiscal year ended March 31, 2010 increased to $67.9 million from an income tax benefit of $11.9 million for the fiscal year ended March 31, 2009. This increase is primarily the result of a one-time election which two of our Canadian subsidiaries made to adopt the U.S. dollar as their functional currency for Canadian tax return filing purposes that had two impacts: First, this one-time election converted unrealized foreign exchange losses into deferred tax expense and while it does not have a cash tax impact, the election increased deferred tax expense by $22.5 million. Second, due to uncertainty surrounding the use of some capital losses created by this election, we recorded a valuation allowance which increased deferred taxes (again with no cash tax implications) by another $22.6 million. The other key factor in increased tax expense is that stronger earnings in the last quarter of the year increased expected deferred tax expense by $18.1 million. Taxes paid in both years were about $0.3 million.

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Seasonality and Quarterly Fluctuations

        Our business is highly seasonal. In general, revenue is highest during our third and fourth fiscal quarters (October through March), during the peak of the natural gas storage winter withdrawal season, when we typically sell most of our optimization inventory to serve the seasonal demand created by the North American residential market which uses natural gas to heat their homes. Revenue is substantially lower in the first and second quarters (April through September), when natural gas prices are generally lower and we shift to the storage injection season and replenish our natural gas inventory. In 2011, approximately 59.6% of our revenue was generated in the third and fourth quarters of our fiscal year.

        Because we typically purchase natural gas and build inventories in the summer months and hedge sales forward into the winter months, the peak borrowing on our revolving credit facilities are generally highest in the middle of our third fiscal quarter, while our peak accounts receivable collections typically occur in our fourth fiscal quarter.

        The following table illustrates the differences in the recognition of revenue associated with our revenue strategies.

 
  Year Ended March 31, 2011  
 
  Qtr 1   Qtr 2   Qtr 3   Qtr 4   Fiscal
2011
 
 
  (in millions)
 

LTF revenue

  $ 29.6   $ 28.4   $ 30.3   $ 31.3   $ 119.6  

STF revenue

    8.2     9.5     11.1     12.2     41.0  

Realized optimization, net

    16.1     19.2     38.3     40.7     114.3  
                       

Total realized revenue

    53.9     57.1     79.7     84.2     274.9  

Realized revenue as a percentage of total realized revenue

    19.6 %   20.8 %   29.0 %   30.6 %   100.0 %

 

 
  Year Ended March 31, 2010  
 
  Qtr 1   Qtr 2   Qtr 3   Qtr 4   Fiscal
2010
 
 
  (in millions)
 

LTF revenue

  $ 26.9   $ 26.7   $ 28.3   $ 27.9   $ 109.8  

STF revenue

    12.6     12.3     15.0     18.5     58.4  

Realized optimization, net

    1.0     7.5     64.7     57.2     130.4  
                       

Total realized revenue

    40.5     46.5     108.0     103.6     298.6  

Realized revenue as a percentage of total realized revenue

    13.6 %   15.6 %   36.2 %   34.7 %   100.0 %

Liquidity and Capital Resources

        Our primary short-term liquidity needs are to pay our quarterly distributions, to pay interest and principal payments under our $400.0 million credit agreement and our senior notes, to fund our operating expenses, and maintenance capital and to pay for the acquisition of proprietary optimization inventory along with associated margin requirements, which we expect to fund through a combination of cash on hand, cash from operations and borrowings under our $400.0 million credit agreement. Our medium-term and long-term liquidity needs primarily relate to potential organic expansion opportunities and asset acquisitions. We expect to finance the cost of any expansion projects and acquisitions from the proceeds of our IPO, 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. We anticipate that our primary sources of funds for our long-term liquidity needs will be from cash from operations and/or debt or equity financings. We believe that these sources of funds will be sufficient to meet our liquidity needs for the foreseeable future.

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        Because we intend to distribute substantially all of our available cash, our growth may not be as fast as the growth of businesses that reinvest their available cash to expand ongoing operations. Moreover, our future growth may be slower than our historical growth. We expect that we will, in large part, rely upon external financing sources, including bank borrowings and issuances of debt and equity interests, to fund our expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy could significantly impair our ability to grow. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may affect the available cash that we have to distribute on each unit. Our Operating Agreement does not limit our ability to issue additional units, including units ranking senior to the common units we offered in our IPO. The incurrence of additional debt by us or our operating subsidiaries would result in increased interest expense, which in turn may also affect the available cash that we have to distribute to our unitholders.

    Historical Cash Flows

        Our cash flows are significantly influenced by our level of natural gas inventory, margin deposits and related forward sale contracts or hedging positions at the end of each accounting period and may fluctuate significantly from period to period. In addition, our period-to-period cash flows are heavily influenced by the seasonality of our proprietary optimization activities. For example, we generally purchase significant quantities of natural gas during the summer months and sell natural gas during the winter months. The storage of natural gas for our own account can have a material impact on our cash flows from operating activities for the period we pay for and store the natural gas and the subsequent period in which we receive proceeds from the sale of natural gas. When we purchase and store natural gas for our own account, we use cash to pay for the gas and record the gas as inventory and thereby reduce our cash flows from operating activities. We typically borrow on our revolving credit facilities to fund these purchases, and these borrowings increase our cash flows from financing activities. Conversely, when we collect the proceeds from the sale of natural gas that we purchased and stored for our own account, the impact on our cash flows from operating activities is positive and the impact on our cash flows from financing activities is negative. Therefore, our cash flows from operating activities fluctuate significantly from period-to-period as we purchase gas, store it, and then sell it in a later period. In addition, we have margin requirements on our economically hedged positions. As the cash deposits we make to satisfy our margin requirements increase and decrease with our volume of derivative positions and changes in commodity prices, our cash flows from operating activities may

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fluctuate significantly from period to period. The following table summarizes our sources and uses of cash for the fiscal years ended March 31, 2011, 2010, and 2009:

 
  Niska   Niska Predecessor  
 
  Year Ended March 31,  
 
  2011   2010   2009  
 
  (in millions)
 

Operating Activities

                   

Net Earnings

  $ 57.5   $ 53.2   $ 108.8  

Adjustments to reconcile net earnings to net cash provided by operating activities:

                   

Unrealized foreign exchange loss (gain)

    0.8     (0.1 )   (37.2 )

Deferred income (benefit) taxes

    (31.3 )   66.6     (12.2 )

Unrealized risk management losses (gains)

    44.8     10.2     (77.3 )

Depreciation and amortization

    46.9     43.1     54.8  

Deferred charges amortization

    4.1     12.4     2.9  

Impairment of goodwill

            22.0  

Impairment of assets

        0.6     2.1  

Write-down of inventory

        3.4     62.3  

Changes in non-cash working capital

    (69.4 )   (33.5 )   (104.6 )
               

Net cash provided by operating activities

  $ 53.4   $ 155.9   $ 21.5  
               

Net cash used in investing activities

  $ (20.4 ) $ (67.8 ) $ (15.6 )
               

Net cash (used)/ provided by financing activities

   
(46.6

)
 
17.5
   
(30.4

)
               

Other information:

                   

Proprietary inventory at cost

  $ 133.6   $ 129.4   $ 133.1  

        Operating Activities.    The variability in net cash provided by operating activities is primarily due to (1) varying market conditions that exist during any given fiscal period, which impacts the margins and fees under each of our LTF, STF and optimization activities; and (2) market conditions at the end of any given fiscal period, which impacts our decision to sell significant volumes of inventory or hold them over a fiscal period end and sell them in the next fiscal period if there is the economic incentive to do so, such as to increase the margins from previous optimization transactions.

        For a discussion of changes in cash flow resulting from adjustments to reconcile net earnings to net cash provided by operating activities, please refer to the discussion "—Results of Operations."

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        Changes in non-cash working capital are broken down further as follows:

 
  Niska   Niska Predecessor  
 
  Year Ended March 31,  
 
  2011   2010   2009  
 
  (in millions)
 

Changes in non-cash working capital:

                   

Margin deposits

  $ (90.9 ) $ (36.2 ) $ 70.3  

Natural gas inventory

    (17.8 )   0.3     (163.3 )

Prepaid expenses

    (4.1 )   13.1     (13.8 )

Accrued receivables

    19.3     8.4     18.4  

Deferred revenue

    3.3     (16.4 )   17.9  

Accrued liabilities

    22.4     (1.0 )   (34.8 )

Other

    (1.5 )   (1.7 )   0.7  
               

Net changes in non-cash working capital

  $ (69.3 ) $ (33.5 ) $ (104.6 )
               

        For the fiscal year ended March 31, 2010, the price of natural gas for the following summer was higher than the economically hedged price of our inventory. We thus chose to carry some of our inventory over the year end and re-hedged its sale to the following fiscal year. This had the effect of increasing our aggregate margins and profitability, but deferred some income and operating cash flow from the fiscal year ended March 31, 2009 to the fiscal year ended March 31, 2010. Unlike 2009, because we already had a significant opening inventory balance at the beginning of the year, we did not show a significant use of cash for the purposes of purchasing inventory for the period ended March 31, 2010. $36.2 million of additional margin deposits were provided during the period to provide collateral support for our financial hedges.

        For the fiscal year ended March 31, 2011, our facility expansions resulted in an increase in the amount of capacity that we optimized, and, because natural gas prices were higher in the following summer than they were at the end of the prior year, we chose to carry a significant amount of our inventory into the following year. While we held slightly more inventory at year end compared to March 31, 2010, lower prices offset some of the change in inventory value. In addition, forward natural gas prices rose after we economically hedged our inventory requiring us to provide incremental margin deposits to cover our unrealized mark to market losses on the financial hedge positions.

        Working Capital.    Working capital is defined as the amount by which current assets exceed current liabilities. Our working capital ratio is defined as current assets divided by current liabilities. Our working capital requirements are primarily affected by our level of capital spending for maintenance and expansion activity, but are also impacted by changes in accounts receivable and accounts payable. These changes are influenced by factors such as credit extended to, and the timing of collections from, our customers. Our working capital is also affected by the relationship between unrealized financial risk management hedges which are marked-to-market on a monthly basis, the margin deposits required by our brokers for such gains and losses, proprietary inventory which is stored in our facilities and cash used to fund inventory purchases.

        As of March 31, 2011, we had net working capital of $272.1 million (working capital ratio of 2.6 to 1.0), representing only a marginal change compared to net working capital of $249.8 million (working capital ratio of 2.4 to 1.0) at March 31, 2010.

        Investing Activities.    Most of the investing activities in each of the fiscal years ended March 31, 2011, 2010 and 2009 were attributed to expansion capital expenditures at our storage facilities. These expenditures, as outlined in "—Capital Expenditures," have enabled us to increase our effective working gas capacity by 49.2 Bcf during this period. However, maintenance capital expenditures have

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been consistently modest, ranging between $0.9 million and $1.7 million each year during this same period.

        Financing Activities.    Net cash provided/(used) by financing activities consists of debt incurred for the acquisition of assets, periodic optional and mandatory retirements of such debt, advances and repayments made on our previous credit facilities to fund proprietary inventory purchases, contributions of capital from our equity holders to fund expansion capital expenditures and debt retirements and distributions made to our equity holders.

        During the fiscal year ending March 31, 2009, we repaid $96.9 million of our term debt through a combination of cash provided from operations and a $50.0 million equity infusion from our equity holders. During the same period, we drew $65.0 million under our previous credit facilities to fund some of our proprietary inventory purchases. We also made a $48.5 million distribution to our equity holders to cover income tax obligations.

        During the fiscal year ending March 31, 2010 we drew $185.1 million from our previous credit facilities to fund proprietary inventory purchases and subsequently repaid $175.0 million when the inventory was sold later in the year. During the fiscal year ended March 31, 2010, we issued our senior notes, which provided net proceeds of approximately $775.4 million after deducting approximately $24.6 million of fees and expenses. (See "—Our 8.875% Senior Notes Due 2018.") Approximately $102.2 million of the net proceeds were used to make a distribution to our equity holders, approximately $75.0 million of the proceeds were used to repay our previous revolving credit facility and approximately $592.5 million of the proceeds were used to repay our previous term loan. In connection with our issuance of senior notes and the repayment of our previous credit facility and term loan, we entered into new senior secured asset-based revolving credit facilities, consisting of a U.S. revolving credit facility and a Canadian revolving credit facility (see "—Our $400 Million Credit Agreement.")

        During the fiscal year ending March 31, 2011 we received proceeds of $333.5 million from our IPO in May of 2010, after deducting fees of $23.4 million. This was offset by distributions totaling $313.3 million made to the owners of Niska Predecessor in connection with our debt and equity offerings, and $64.7 million related to quarterly distributions made to our unitholders during the period.

        In October of 2009 and January of 2010, the holders of our predecessor's Class A units made contributions to the capital of our predecessor totaling approximately $15.0 million and $18.0 million, respectively in order to fund capital expenditures. During the fiscal year ending March 31, 2010, our predecessor made distributions totaling approximately $129.0 million to its equity holders (inclusive of the $102.2 million distribution made from the proceeds of the senior notes).

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    Capital Expenditures

        Our capital expenditures for the years ended March 31, 2011, 2010 and 2009 were as follows:

 
  Niska   Niska
Predecessor
 
 
  Year Ended March 31,  
Capital expenditures
  2011   2010   2009  
 
  (in millions)
 

Maintenance capital

  $ 1.7   $ 0.9   $ 1.4  

Expansion capital

    18.7     66.9     17.6  
               

Total cash expenditures

    20.4     67.8     19.0  

Non-cash working capital related to property, plant and equipment expenditures

    2.9     2.3     9.6  

Non-cash transfer of natural gas inventory to property, plant and equipment

    13.6          
               
 

Total

  $ 36.9   $ 70.1   $ 28.6  
               

        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.

        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. In the fiscal year ended March 31, 2011, we spent a total of $32.3 million, excluding $2.9 million of capital expenditures which were accrued at March 31, 2011 to expand the capacity and services of our facilities.

    Our 8.875% Senior Notes Due 2018

        On March 5, 2010, Niska US and Niska Canada, closed 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 units were sold in an offering exempt from registration under the Securities Act to qualified institutional investors in reliance on Rule 144A under the Securities Act and to non-U.S. persons in offshore transactions in reliance on Regulation S under the Securities Act.

        On February 3, 2011, the Securities and Exchange Commission ("SEC") accepted and made effective our exchange offer whereby holders of the current Senior Notes were permitted to exchange such Senior Notes for new freely transferable Senior Notes. The terms of the new units are identical to the units which are described below, except that the new units are registered under the Securities Act and generally do not contain restrictions on transfer.

        In this report we refer to the 8.875% senior notes due 2018 of Niska US and Niska Canada as "the notes" or "our senior notes." In this section Niska US and Niska Canada are each referred to individually as an "issuer" and collectively as "the issuers."

        The notes are senior unsecured obligations of each issuer, which are: (1) effectively junior to that issuer's secured obligations; (2) equal in right of payment with all existing and future senior unsecured indebtedness of each issuer; and (3) senior in right of payment to any future subordinated indebtedness of each issuer. The notes are fully and unconditionally guaranteed by us and our direct and indirect subsidiaries on a senior unsecured basis, and are: (1) effectively junior to each guarantor's secured

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obligations; (2) equal in right of payment with all existing and future senior unsecured indebtedness of each guarantor and (3) senior in right of payment to any future subordinated indebtedness of each guarantor.

        Interest on our senior notes is payable on March 15 and September 15 of each year they are outstanding. The notes will mature on March 15, 2018. Under the indenture governing our senior notes, we are required to make principal payments prior to the maturity date except upon certain events of default. In addition, in the event of a change in control or certain asset sales, as those terms are defined in the indenture, we may be required to offer to redeem the notes from our holders.

        The indenture governing our senior notes limits our ability to pay distributions in respect of, repurchase or pay dividends on our membership interests (or other capital stock) or make other restricted payments. The limitation changes depending on our fixed charge coverage ratio, which is defined as the ratio of our consolidated cash flow to our fixed charges, each as defined in the indenture governing our senior notes, and measured for the preceding four quarters.

        If the fixed charge coverage ratio is not less than 1.75 to 1.0, we will be permitted to make restricted payments if the aggregate restricted payments since the date of closing of our IPO, excluding certain types of permitted payments, are less than the sum of a number of items including, most importantly:

    operating surplus (defined similarly to the definition in our Operating Agreement) calculated as of the end of our preceding fiscal quarter; and

    the aggregate net cash proceeds received by us 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, we will be permitted to make restricted payments if the aggregate restricted payments since the date of closing of our IPO, excluding certain types of permitted payments, are less than the sum of a number of items including, most importantly:

    $75.0 million; and

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

        As of March 31, 2011, the indenture governing our senior notes would have permitted us to distribute approximately $150 million.

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

        The indenture governing our senior notes contains certain other covenants that, among other things, limit our and certain of our subsidiaries' ability to:

    incur additional indebtedness;

    pay dividends on, repurchase or make distributions in respect of our capital stock or make other restricted payments;

    make certain investments;

    sell, transfer, or otherwise convey certain assets;

    create liens;

    consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; and

    enter into certain transactions with our affiliates.

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

        Prior to March 15, 2013, the issuers may redeem up to 35% of the aggregate principal amount of the notes at a premium, plus accrued and unpaid interest with net cash proceeds of certain equity offerings. Prior to March 15, 2014, the issuers may redeem some or all of the notes at a make-whole premium, as set forth in the offering memorandum. After March 15, 2014, the issuers may redeem some or all of the notes at a premium that will decrease over time until maturity.

    Our $400 Million Credit Agreement

        Concurrently with the issuance of our senior notes, Niska US and the AECO Partnership entered into new senior secured asset-based revolving credit facilities, consisting of a U.S. revolving credit facility and a Canadian revolving credit facility. References in this report to "our new credit facilities" or "our $400.0 million credit agreement" refer to the credit agreement and credit facilities, respectively, of the AECO Partnership and Niska US. These new revolving credit facilities provide for revolving loans and letters of credit in an aggregate principal amount of up to $200.0 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 $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 our option, in either U.S. or Canadian dollars. Royal Bank of Canada is acting as administrative agent and collateral agent for the revolving credit facilities. Each revolving credit facility has a four-year maturity.

        Borrowings under our revolving credit facilities are limited to a borrowing base calculated as the sum of specified percentages of eligible 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 a floating rate, which (1) in the case of U.S. dollar loans can be either LIBOR plus an applicable margin or, at our 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 our option, a prime rate plus an applicable margin. The credit agreement provides that we may borrow only up to the lesser of the level of our then current borrowing base and our committed maximum borrowing capacity, which is currently $400.0 million. Our borrowing base was $469.9 million as of June 1, 2011.

        Our obligations under our $400.0 million credit agreement will be guaranteed by us and all of our direct and indirect wholly owned subsidiaries (subject to certain exceptions) and secured by a lien on substantially all of our and our direct and indirect subsidiaries' current and fixed assets (subject to certain exceptions). Certain fixed assets will only be required to be part of the collateral to the extent such fixed assets are included in the borrowing base under the respective revolving credit facility. The aggregate borrowing base under both revolving credit facilities includes $150.0 million (the "PP&E Amount") due to a first-priority lien on fixed assets granted to the lenders. The PP&E Amount will be reduced on a dollar-for-dollar basis upon the release of fixed assets having a value in excess of $50.0 million from such liens.

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        The following fees are applicable under each revolving credit facility: (1) an unused line fee of 0.75% per annum, based on the unused portion of the respective revolving credit facility; (2) a letter of credit participation fee on the aggregate stated amount of each letter of credit equal to the applicable margin for LIBOR loans or bankers' acceptance loans, as applicable; and (3) certain other customary fees and expenses of the lenders and agents. We will be required to make prepayments under our revolving credit facilities at any time when, and to the extent that, the aggregate amount of the outstanding loans and letters of credit under such revolving credit facility exceeds the lesser of the aggregate amount of commitments in respect of such revolving credit facility and the applicable borrowing base.

        Our $400.0 million credit agreement contains customary covenants, including, but not limited to, restrictions on our and our subsidiaries' ability to merge and consolidate with other companies, incur indebtedness, grant liens or security interests on assets subject to security interests under the credit agreement, make acquisitions, loans, advances or investments, pay distributions, sell or otherwise transfer assets, optionally prepay or modify terms of any subordinated indebtedness or enter into transactions with affiliates. Our new revolving credit facilities require the maintenance of a fixed charge coverage ratio of 1.1 to 1.0 at the end of each fiscal quarter when excess availability under both revolving credit facilities is less than 15% of the aggregate amount of availability under both revolving credit facilities. Such fixed charge coverage ratio will be tested at the end of each quarter until such time as average excess availability exceeds 15% for thirty consecutive days.

        Our $400.0 million credit agreement contains limitations on our ability to pay distributions in respect of, repurchase or pay dividends on our membership interests (or other capital stock) or make other restricted payments. These limitations are substantially similar to those contained in the indenture governing our senior notes described above, except that the credit agreement does not contain a general basket of $75.0 million of restricted payments. As of March 31, 2011, our $400.0 million credit agreement would have permitted us to distribute approximately $75 million.

        Our $400.0 million credit agreement provides that, upon the occurrence of certain events of default, our obligations thereunder may be accelerated and the lending commitments terminated. Such events of default include payment defaults to the lenders, material inaccuracies of representations and warranties, covenant defaults, cross-defaults to other material indebtedness, including our senior notes, voluntary and involuntary bankruptcy proceedings, material money judgments, material events relating to pension plans, certain change of control events and other customary events of default.

        As of June 1, 2011, we had no borrowings outstanding under our revolving credit facilities and had $54.0 million in letters of credit issued. We and our subsidiaries were in compliance with all covenant requirements under our credit facilities at June 1, 2011.

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    Contractual Obligations

        The following table summarizes by period the payments due for our estimated contractual obligations as of March 31, 2011:

 
  Payment due by period  
 
  Total   Less than
1 year
  1 - 3 years   3 - 5 years   More than
5 years
 
 
  (in millions)
 

Long-term debt obligations

  $ 800.0   $   $   $   $ 800.0  

Interest on long-term debt obligations

    497.0     71.0     142.0     142.0     142.0  

Operating lease obligations

    181.2     8.2     16.1     13.0     143.9  

Leased storage contracts

    13.8     6.4     4.6     1.9     0.9  

Mineral and surface leases

    31.9     0.5     0.7     0.4     30.3  

Purchase obligations(1)

    3,703.0     3,171.8     485.3     45.9      
                       
 

Total

  $ 5,226.9   $ 3,257.9   $ 648.7   $ 203.2   $ 1,117.1  
                       

(1)
Purchase obligations consist of forward physical and financial commitments related to purchases of natural gas. As we economically hedge substantially all of our natural gas purchases, there are forward sales that offset these commitments that are not included in the above table. As at March 31, 2011, forward physical and financial sales for all future periods totaled $3,691 million.

    Off-Balance Sheet Arrangements

        In accordance with GAAP, there is no carrying value recorded for a credit facility until we borrow from the facility. In the future we may use off-balance sheet arrangements such as undrawn credit facility commitments, including letters of credit, to finance portions of our capital and operating needs. See "—Contractual Obligations" for more information.

        On January 1, 2010, Wild Goose entered into an operating lease for compression and other equipment related to the development of an expansion project. The primary term of the operating lease is five years, although there is an early purchase option which Wild Goose can exercise after three years. At the end of either term, Wild Goose can purchase the leased equipment from the operating lease counterparty at fair market value. The table above indicates all payments required under the primary term of the operating lease.

Critical Accounting Estimates and Policies

        The historical financial statements included elsewhere in this document have been prepared in accordance with GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management's judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the application of GAAP, including revenue recognition, the valuation of risk management assets and liabilities, inventory and goodwill. These estimates affect, among other items, valuing identified intangible assets, evaluating impairments of long-lived assets, depreciation of cushion gas, establishing estimated useful lives for long-lived assets, estimating revenues and expense accruals, assessing income tax expense and the requirement for a valuation allowance against the deferred income tax asset and valuing asset retirement obligations.

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    Revenue Recognition

        Our assessment of each of the four revenue recognition criteria as they relate to our revenue producing activities is as follows:

        Persuasive evidence of an arrangement exists.    Our customary practices are to enter into a written contract, executed by both the customer and us.

        Delivery.    Delivery is deemed to have occurred at the time the natural gas is delivered and title is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent that we retain our inventory, delivery occurs when the inventory is subsequently sold and title is transferred to the third party purchaser.

        The fee is fixed or determinable.    We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. The fees are generally due on the 25th of the month following the delivery or services rendered. For other arrangements, the amount of revenue is determinable when the sale of the applicable product has been completed upon delivery and transfer of title.

        Collectability is reasonably assured.    Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers' financial position (e.g. cash position and credit rating) and ability to pay. If collectability is not considered reasonably assured at the outset of an arrangement in accordance with our credit review process, revenue is recognized when the fee is collected.

        Revenue from our LTF contracts consists of monthly storage fees and fuel and commodity charges for injections and withdrawals. LTF contract revenue is accrued on a monthly basis in accordance with the terms of the customer contracts. Customer charges for injections and withdrawals are recorded in the month of injection or withdrawal.

        STF contract revenue consists of fees for injections and withdrawals, which include fuel and commodity charges. One half of the fees are earned at the time of injection by the customer and one-half of the fees are charged at the time of withdrawal by the customer.

        Energy trading contracts resulting in the delivery of a commodity where we are the principal in the transaction are recorded as proprietary optimization revenues or purchases at the time of physical delivery. Realized and unrealized gains and losses on financial energy trading contracts are included in proprietary optimization revenue. See Note 13 to our consolidated financial statements included elsewhere in this document.

    Fair Value of Risk Management Assets and Liabilities

        Niska Partners uses natural gas derivatives and other financial instruments to manage its exposure to changes in natural gas prices, foreign exchange, and interest rates. These financial assets and liabilities, which are recorded at fair value on a recurring basis, are included into one of three categories based on a fair value hierarchy.

        The fair value of our derivative and risk management contracts are recorded as a component of risk management assets and liabilities, which are classified as current or non-current assets or liabilities based upon the anticipated settlement date of the contracts. The determination of the fair value of these derivative and physical contracts reflects the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In the determination of fair value, we consider various factors, including closing foreign exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Although the fair value of our risk management assets and liabilities may fluctuate, such fluctuations will always be offset

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by equivalent changes in the value of our physical inventory and purchases. Our policy is for our inventory and purchases always to be economically hedged, within small tolerances permitted under our risk management policies, so we are not exposed economically to the risk of fluctuating commodity prices. We do not speculate on changes in the price of the commodity, rather we only lock in margins when they are available in the market. See "Business—Our Operations—Proprietary Optimization." For further analysis regarding our sensitivities to fluctuations in the price of natural gas, see "Management's Discussion and Analysis of Financial Condition and Results of Operation—Quantitative and Qualitative Disclosures about Market Risks—Commodity Price Risks."

    Inventory

        Our inventory is natural gas injected into storage and held for resale. Long-term inventory represents non-cycling working gas. We inject non-cycling working gas on a temporary basis to increase pressure within the reservoirs to allow us to market higher cycling contracts or previously un-saleable gas from an underutilized reservoir that can be sold into the market when we add mechanical compression to the reservoir. This mechanical compression will allow access to natural gas that was previously required to maintain pressure within the reservoir. Inventory is valued at the lower of average cost and market.

    Cushion Gas Effectiveness

        Certain volumes of gas defined as Cushion Gas are required for maintaining a minimum field pressure. Cushion Gas is considered a component of the facility and as such is not amortized because it is expected to ultimately be recovered and sold. Cushion Gas is monitored to ensure that it provides effective pressure support. In the event that gas moves to another area of the reservoir where it does not provide effective pressure support, charges against Cushion Gas are included in depreciation in an amount equal to the estimated volumes that have migrated.

    Impairment of Long-Lived Assets

        We evaluate whether events or circumstances have occurred that indicate that long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected undiscounted future cash flows. In the event that the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset's carrying value over its fair value is recorded.

    Goodwill and Other Intangible Assets

        We account for business acquisitions using the purchase method of accounting and accordingly the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of the net assets acquired is attributed to goodwill.

        Goodwill is not amortized and is re-evaluated on an annual basis or more frequently if events or changes in circumstances indicate that the asset might be impaired.

        Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the business climate, legal factors, operating performance indicators, competition, sale or disposition of a significant portion of the business or other factors. The performance of the test involves a two-step process. The first step of the impairment test involves comparing the fair values of the applicable reporting units with their aggregate

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carrying values, including goodwill. If the carrying amount exceeds the fair value of the reporting unit, we perform the second step of the goodwill impairment test to determine the amount of impairment loss. The second step of the goodwill impairment test involves comparing the implied fair value of the affected reporting unit's goodwill with the carrying value of that goodwill.

        Determining the fair value of a reporting unit is judgmental in nature and requires the use of significant estimates and assumptions. These assumptions are dependent on several subjective factors including the timing of future cash flows and future growth rates. The fair value of our reporting units is determined based on a weighting of multiples of potential earnings approaches which is classified under Level 3 fair value measurement under FASB ASC 820. The multiples of earnings approach estimates fair value by applying multiples of potential earnings, working gas capacity, and cyclability of similar entities. Results using the multiples of potential earnings and the multiples of gas capacity and cyclability are given equal weighting when determining the valuation using this approach. The future operating projections are based on consideration of past performance and the projections and assumptions used in our current operating plans and adjusted for market participant assumptions as appropriate. We then assign a weighting to the multiple or earnings to derive the fair value of the reporting unit.

        These types of analyses contain uncertainties because they require management to make assumptions and apply judgment to estimate economic factors and the profitability of future business strategies and industry conditions. A reduction in volatility and the narrowing of seasonal natural gas storage spreads in the last six months of the fiscal year ended March 31, 2011 compressed short-term firm and realized optimization margins compared to those experienced in the prior fiscal year. If narrow seasonal spreads and low volatility persist for an extended period of time, these conditions could impact the Company's intermediate and long-term forecast of revenues and profitability and, therefore, valuations of goodwill.

        Intangible assets representing customer contracts are amortized over their useful lives. These assets are reviewed for impairment as impairment indicators arise. When such events or circumstances are present, the recoverability of long-lived assets is assessed by determining whether the carrying value will be recovered through the expected undiscounted future cash flows. In the event that the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset's carrying value over its fair value is recorded. Pipeline rights of way are formal agreements granting rights of way into perpetuity and are not subject to amortization but are subject to an annual impairment test.

    Income taxes

        We are not taxable entities. Income taxes on their income are the responsibility of the individual partners and have accordingly not been recorded in the consolidated financial statements. Niska Partners has corporate subsidiaries, which are taxable corporations subject to Canadian federal and provincial income taxes, which are included in the consolidated financial statements.

        Income taxes on the Canadian corporate subsidiaries are provided based on the asset and liability method, which results in deferred income tax assets and liabilities arising from temporary differences. Temporary differences are differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. This method requires the effect of tax rate changes on current and accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The asset and liability method also requires that deferred income tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized.

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Recent Accounting Pronouncements

Fair Value Measurement (ASC 810-10)

        Effective April 1, 2010, we are required to disclose the fair value information of financial instruments at each interim reporting period. The disclosures include the relevant carrying value as well as the methods and significant assumptions used to estimate the fair value, in addition to transfers into and out of the three levels of the fair value hierarchy (described as Level 1, Level 2 and Level 3), as well as additional details about movements within Level 3. The new standard clarifies the level of disaggregation required and the inputs and valuation techniques used to measure fair value. The adoption of this standard did not impact how we account for balances recorded at fair value.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risks.

        The term "market risks" refers to the risk of loss arising from changes in commodity prices, currency exchange rates, interest rates, counterparty credit and liquidity. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

    Commodity Price Risk

        To mitigate exposure to changes in commodity prices, we enter into purchases and sales of natural gas inventory and concurrently match the volumes in these transactions with offsetting forward contracts or other hedging transactions.

        Derivative contracts used to manage market risk generally consist of the following:

    Forwards and futures are contractual agreements to purchase or sell a specific financial instrument or natural gas at a specified price and date in the future. We enter into forwards and futures to mitigate the impact of price volatility. In addition to cash settlement, exchange traded futures may also be settled by 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. We enter 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. We may enter into option agreements to mitigate the impact of changes in natural gas prices.

        In order to manage our exposure to commodity price fluctuations, our policy is to promptly enter into a forward sale contract or other hedging transaction for every proprietary purchase contract we enter into. Therefore, inventory purchases are matched with forward sales or are otherwise economically hedged so that there are no speculative positions beyond the minimal operational tolerances specified in our risk policy.

        At March 31, 2011, 32.8 Bcf of natural gas inventory was economically hedged, representing 99.4% of our total current inventory. However, 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 $32.8 million, but the fair value or mark-to-market value of our hedges would decrease by only $32.6 million, due to 0.6% (0.2 Bcf) of that inventory that was not economically hedged. Conversely, if the price of natural gas declined by $1.00 per Mcf, the value of that inventory would

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decrease by $32.4 million while the fair value of our hedges would increase by only $32.2 million, due to the non-economically hedged position. Long-term inventory and fuel gas used for operating our facilities are not offset. Total volumes of long-term inventory and fuel gas at March 31, 2011 are 3.4 Bcf and 0.0 Bcf, respectively.

        Although the intent of our risk-management strategy is to protect our margins and manage our liquidity risk on related margin deposit requirements, we do not qualify any of our derivatives for hedge accounting. Changes in the fair values of these derivatives receive mark-to-market treatment in current earnings and result in greater potential for earnings volatility. This accounting treatment is discussed further under Note 2 of the Notes to our Consolidated Financial Statements and "—Critical Accounting Estimates and Policies."

    Currency Exchange Risk

        Our cash flow relating to our Canadian operations is reported in the U.S. dollar equivalent of such amounts measured in Canadian dollars. Monetary assets and liabilities of our Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period.

        Because a portion of our Canadian business is conducted in Canadian dollars, we use certain financial instruments to minimize the risks of changes in the exchange rate. These instruments include forward swaps or spot swaps buying or selling U.S. dollars. Options may also be used in the future. All of the financial instruments utilized are placed with large brokers and financial institutions.

        At March 31, 2011, we had forward currency exchange contracts for a notional value of $142.8 million. The value of the forward currency contracts at March 31, 2011 and 2010 was a liability of $6.3 million, and a liability of $4.1 million, respectively, and is recorded in derivative assets and derivative liabilities on the consolidated balance sheets. These contracts expire on various dates between April 1, 2011 and August 1, 2014 and are for the exchange of $145.9 million Canadian dollars into $142.8 million U.S. dollars at a weighted average rate of 1.022 Canadian dollars to 1.00 dollar.

    Interest Rate Risk

        We are exposed to interest rate risk due to variable interest rates under our $400.0 million credit agreement. All such borrowings under our credit facilities bear interest at variable rates. As of March 31, 2011, we had no borrowings outstanding under our revolving credit facilities. The credit facilities would currently provide an interest rate on borrowings of 5.0% (assumes LIBOR plus 350 basis points, where LIBOR is approximately 1.50%). In the future, we may borrow under fixed rate and variable rate debt instruments that also give rise to interest rate risk. Changes in economic conditions could result in higher interest rates, thereby increasing our interest expense and reducing our funds available for capital investment, operations or distributions to our unitholders.

    Counterparty Credit Risk

        Counterparty credit risk is the risk of financial loss if a customer fails to perform its contractual obligations. We engage 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 our ability to take ownership of customer-owned natural gas stored in its facilities in the event of non-payment.

        Margin deposits, or letters of credit in lieu of deposits, are required on derivative instruments utilized to manage our counterparty credit risk. As commodity prices increase or decrease, the fair

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value of our derivative instruments changes thereby increasing or decreasing our margin deposit requirements. Rising commodity prices or an expectation of rising prices could increase the cash needed to manage our commodity price exposure and thereby increase our liquidity requirements, limit amounts available to us through borrowing and reduce the volume of natural gas we may purchase. Exchange traded futures and options have minimal credit exposure as the exchanges guarantee every contract will be margined on a daily basis. In the event of any default, our 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.

    Liquidity Risk

        Liquidity risk is the risk that we will not be able to meet our financial obligations as they become due. Our approach to managing liquidity risk is to contract a substantial part of our facilities to generate constant cash flow and to ensure that they always have sufficient cash and credit facilities to meet their obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to reputation.

    Fair Value Measurement

        The fair values of the derivative instruments are based on quoted market prices obtained from NYMEX or ICE and from various sources such as independent reporting services, industry publications and brokers. These quotes are compared to the contract price of the instrument, which approximates the gain or loss that would have been realized if the contracts had been closed out at a specified time. We utilize observable market data when available, or models that utilize observable market data when determining fair value.

Risk Management Policy and Practices

        We have in place risk management practices that are intended to quantify and manage risks facing our business. These risks include, but are not limited to, market, credit, foreign exchange, operational, and liquidity risks. Our hedging practices mitigate our exposure to commodity price and foreign exchange risks. Strict open position limits are enforced, and physical inventory is offset with forward hedges. Our counterparty strategy ensures we have a strong mix of quality customers. We have models in place to monitor and manage operational and liquidity risks.

        The Risk Management Committee, or RMC, is comprised of members of our management team. The RMC provides oversight of our commercial activities. The committee reviews the adequacy of controls to ensure compliance with the risk policy. Our RMC meets weekly to review and respond to risks facing our business. The RMC analyzes positions and exposures and provides daily and weekly reporting to facilitate understanding of these exposures. The RMC assesses and manages the potential for loss in our positions through these reports. If limits are exceeded, the RMC is informed and appropriate action is taken to review and remedy. The RMC is independent of the Commercial and Marketing groups and reports through our chief financial officer.

        Optimization activities can only be executed by employees authorized to transact under the risk policy. All commercial personnel are annually required to read and certify that they will adhere to the principles purported within the policy. Each person authorized to make transactions is subject to internal volume limits. Counterparties are subject to credit limits as approved by our credit department.

        Our commercial and risk functions operate independently to ensure proper segregation of duties. Critical deal information for every transaction is entered into our deal capture systems and confirmed with counterparties.

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        Despite the policies, procedures and controls described above, there can be no assurance that our risk management systems will prevent losses that would negatively affect our business, results of operations, cash flows and financial condition. See "Risk Factors—Risks Inherent in Our Business—Our risk management policies cannot eliminate all commodity price risk." In addition, any non-compliance with our risk management policies could result in significant financial losses.

Item 8.    Financial Statements and Supplementary Data.

        The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth on pages F-4 through F-10 of this Annual Report on Form 10-K and are incorporated herein by reference.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

        On February 4, 2011 we changed our principal independent accountant from KPMG LLP, the Canadian member firm affiliated with KPMG International ("KPMG Canada"), to KPMG LLP, the United States member firm affiliated with KPMG International ("KPMG USA"). This change constituted the dismissal of KPMG Canada and the engagement of KPMG USA. The decision to change accountants was approved by the Audit Committee of our Board of Directors.

        During our two most recent fiscal years, KPMG Canada's reports on our financial statements and its predecessors did not contain an adverse opinion or disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope or accounting principles.

        During our and our predecessors' two most recent fiscal years or the subsequent period through February 4, 2011, we and KPMG Canada have not had any disagreements on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure which, if not resolved to the satisfaction of KPMG Canada, would have caused KPMG Canada to make reference to the matter in its reports on our financial statements; and (ii) there were no reportable events as the term is described in Item 304(a)(1)(iv) of Regulation S-K.

        During the most recent years ended March 31, 2010 and 2009 and any subsequent interim period through February 4, 2011 we did not consult with KPMG USA, the newly engaged accountant, regarding any matter described in Item 304(a)(2) of Regulation SK, including any issue related to our financial statements, subject of a disagreement, any reportable event or the type of audit opinion that might be rendered for us.

Item 9A.    Controls and Procedures.

    (a)    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 CFO have concluded that our controls and procedures were effective as of March 31, 2011. 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.

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    (b)    Management's Report on Internal Control over Financial Reporting.

        Management's report on internal control over financial reporting is set forth on page F-2 of this Annual Report on Form 10-K and is incorporated herein by reference.

    (c)    Attestation Report of the Registered Public Accounting Firm.

        The attestation report of our registered public accounting firm with respect to internal controls over financial reporting on page F-3 of this Annual Report on Form 10-K and is incorporated herein by reference.

    (d)    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.

Item 9B.    Other Information.

        None.


PART III

Item 10.    Directors, Executive Officers and Corporate Governance.

    Management of Niska Gas Storage Partners LLC

        Our manager has sole responsibility for conducting our business and for managing our operations. Pursuant to our Operating Agreement, our manager has delegated the power to conduct our business and manage our operations to our board. Our manager may revoke this delegation and resume control of our business at any time. Our manager and our board are not elected by our unitholders and will not be subject to re-election on a regular basis in the future. As long as the delegation of authority is in effect, our manager will appoint all members to our board. Unitholders will not be entitled to elect our directors or directly or indirectly participate in our management or operation. Our Operating Agreement provides that our manager must act in "good faith" when making decisions on our behalf.

        Whenever our manager makes a determination or takes or declines to take an action in its individual, rather than representative, capacity or in its sole discretion, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us or any member, and our manager is not required to act in good faith or pursuant to any other standard imposed by our Operating Agreement or under the Delaware Act or any other law. Examples include the exercise of its limited call rights, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation. Actions of our manager which are made in its individual capacity or in its sole discretion will be made by a majority of the owners of our manager.

        In selecting and appointing directors to our board, our manager does not apply a formal diversity policy or set of guidelines. However, when appointing new directors, our manager considers each individual director's qualifications, skills, business experience and capacity to serve as a director, as described below for each director, and the diversity of these attributes for the board as a whole.

Directors and Executive Officers

        Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal by the member of our manager. Our executive officers serve at the discretion of our board.

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There are no family relationships among any of the directors or executive officers. The following table shows information as of March 31, 2011 regarding our current directors and executive officers.

Name
  Age   Position
David F. Pope   54   President, Chief Executive Officer and Director
Simon Dupéré   48   Chief Operating Officer
Vance E. Powers   54   Chief Financial Officer
Rick J. Staples   48   Vice President, Commercial Operations
Jason A. Dubchak   38   Vice President, General Counsel & Corporate Secretary
Jason S. Kulsky   44   Vice President, Business Development
Darin T. Olson   36   Vice President, Finance
Deborah M. Fretz   63   Director
James G. Jackson(1)   47   Director
E. Bartow Jones   35   Director
Stephen C. Muther   62   Director
George A. O'Brien   62   Director
William H. Shea, Jr.    56   Director
Andrew W. Ward   44   Director

(1)
Mr. Jackson was appointed as a member of the board of directors on May 12, 2011.

        David F. Pope—Mr. Pope is our President and Chief Executive Officer and a member of our board, the board of directors of our manager and the board of supervisors of Niska Holdings, which is our parent. Mr. Pope has been our President and Chief Executive Officer since June 2006. Prior to his current role at Niska Holdings, Mr. Pope served as the President of Seminole Canada Gas Company since 2002, and prior to that has held various positions in the natural gas industry since 1980. In 1992, Mr. Pope began his employment with Enron Corporation after it acquired Canadian Gas Marketing, a company Mr. Pope founded in 1989. He worked for Enron Corporation as Vice President of its gas marketing and trading group from 1992 until March 2001, nine months' prior to Enron Corporation's filing of a voluntary petition for a Chapter 11 reorganization with the U.S. Bankruptcy Court in December of 2001. Mr. Pope has served as a director of GEP Midstream Finance Corp., or GEP Midstream, since 2008 and as a director of Gibson Energy ULC, or Gibson Energy, since 2010. Mr. Pope has a Bachelor of Engineering in Chemical Engineering from McGill University and has worked in the natural gas industry for his entire career.

        As a result of his professional background, we believe Mr. Pope brings to us executive-level strategic and financial skills and significant operational experience. Combined with his over 30 years of experience in the natural gas industry and deep knowledge of our business, these attributes make Mr. Pope well-suited to serve on our board.

        Simon Dupéré—Mr. Dupéré is our Chief Operating Officer. Mr. Dupéré has served as our Chief Operating Officer since September 2006. He is in charge of our field and facility operations, engineering and geoscience, including our existing operations at our four gas storage facilities and our expansion and development efforts. He has 25 years of active experience in the natural gas industry. Prior to joining us, Mr. Dupéré was the President & Chief Executive Officer at Intragaz Inc., a natural gas storage company engaged in the development and operation of two gas storage projects in Quebec. Mr. Dupéré has a Bachelor of Science in Physics Engineering from Laval University in Quebec City, Quebec.

        Vance E. Powers—Mr. Powers is our Chief Financial Officer. Mr. Powers has served as our Chief Financial Officer since January 1, 2011. Mr. Powers has over 25 years of experience in senior financial, accounting, and reporting positions. From April 2010 until commencing service as Niska's Chief

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Financial Officer, Mr. Powers served as a finance management consultant to Niska, assisting in the completion of Niska's initial public offering, its transition to a publicly-traded company and its establishment of an investor relations function. From May 2009 to March/April 2010, Mr. Powers was an individual investor. From December 2003 to May 2009, Mr. Powers served as Vice President, Finance and Controller of Buckeye GP LLC, the general partner of Buckeye Partners, L.P. (NYSE: BPL), one of the largest refined petroleum products pipeline and terminal companies in the United States, where he was a key member of the senior executive team and was principally responsible for Buckeye's accounting, financial reporting, planning and analysis and treasury functions. He also served Buckeye GP LLC as Acting Chief Financial Officer from July 2007 until November 2008, where he was additionally responsible for capital markets activities and investor relations.. He held similar positions with MainLine Management LLC, the general partner of Buckeye GP Holdings L.P. (NYSE: BGH), and participated in BGH's initial public offering in August 2006. Mr. Powers holds a MBA degree from Lehigh University and a BA from Gettysburg College. He is also a Certified Public Accountant in Pennsylvania.

        Rick J. Staples—Mr. Staples is our Senior Vice President, Commercial Operations, responsible for the marketing, trading and commercial operation of our natural gas storage assets. Mr. Staples has served us in this capacity since May 2006. Prior to joining us in 2006, Mr. Staples served as Director of Gas Storage with TransCanada Pipelines Ltd. from 2001 to 2006. Mr. Staples graduated from the University of Alberta with a degree in Mechanical Engineering. Mr. Staples also graduated from the Queens Executive program (Queens School of Business) in 1997.

        Jason A. Dubchak—Mr. Dubchak is our Vice President, General Counsel & Corporate Secretary. Mr. Dubchak has served as our Vice-President, General Counsel & Corporate Secretary since September 2007. Prior to assuming this role, Mr. Dubchak was Associate General Counsel and was continuously with the natural gas storage division of EnCana Corporation and its predecessor, Alberta Energy Company Ltd., respectively, since 2001. He has a Bachelor of Arts (Honors) from the University of Calgary and a Bachelor of Laws from the University of Alberta.

        Jason S. Kulsky—Mr. Kulsky is our Vice President, Business Development, and has held that title since May 2006. Mr. Kulsky previously served with the natural gas storage division of EnCana Corporation and its predecessor, Alberta Energy Company Ltd., most recently serving as Manager, Business Development, prior to joining us. Mr. Kulsky is a Chartered Financial Analyst and has a Bachelor of Commerce (Finance) degree from the University of Calgary and an engineering diploma from SAIT Polytechnic.

        Darin T. Olson—Mr. Olson is our Vice President, Finance and has served in that role since January 1, 2011. Mr. Olson also served as our Chief Financial Officer from May 2006 to January 1, 2011. Prior to joining us, he was the Controller of Seminole Canada Gas Company from 2002 to 2006. For the ten prior years, Mr. Olson worked in a variety of positions in the natural gas and public accounting industries. Mr. Olson is a Chartered Accountant and has a Bachelor of Commerce degree from the University of Calgary.

        Deborah M. Fretz—Ms. Fretz retired as President, Chief Executive Officer and director of Sunoco Logistics Partners L.P. ("Sunoco Logistics") on July 1, 2010. She served in this role from October 2001 to her retirement. Sunoco Logistics is a publicly-traded master limited partnership formed in 2001 to acquire, own and operate a geographically diverse group of crude oil and refined products pipelines, terminals and storage facilities in eleven states. Revenues are $10 billion, with 1,400 employees and interests in 10,000 miles of pipelines and 31 million barrels of storage capacity. Prior to the IPO of Sunoco Logistics Partners, Ms. Fretz held several executive management roles for Sunoco, Inc., the last as Vice President Mid-Continent Refining, Marketing and Logistics which included Sunoco's Lubricant business as well as the MidAmerica refining and marketing business. Ms. Fretz serves as a board

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member of GATX Corp., a Chicago-based transportation services firm, where she is Chair of the Compensation Committee and was formerly Lead Director.

        As a result of her service to Sunoco Logistics, Ms. Fretz gained extensive experience in overseeing the strategy, operations, and governance of major public companies. Ms. Fretz was also selected to serve as a director of our board due to her valuable knowledge of the energy industry. Ms. Fretz's experience has also given her knowledge of the unique issues related to operating publicly-traded limited partnerships, which are similar to us. We believe this background and skill set makes Ms. Fretz well-suited to serve as a member of our board.

        James G. Jackson—Mr. Jackson has been the Chief Financial Officer of BreitBurn GP, LLC, the general partner of BreitBurn Energy Partners L.P.(NASDAQ: BBEP) since July 2006 and an Executive Vice President since October 2007. Before joining BreitBurn, Mr. Jackson served as Managing Director of Merrill Lynch & Co.'s Global Markets and Investment Banking Group. Mr. Jackson joined Merrill Lynch in 1992 and was elected Managing Director in 2001. Previously, Mr. Jackson was a Financial Analyst with Morgan Stanley & Co. from 1986 to 1989 and was an Associate in the Mergers and Acquisitions Group of the Long-Term Credit Bank of Japan from 1989 to 1990. Mr. Jackson obtained a B.S. in Business Administration from Georgetown University and an M.B.A. from the Stanford Graduate School of Business.

        Mr. Jackson's knowledge and experience with BreitBurn Energy Partners L.P. and BreitBurn GP, LLC, has provided him with valuable experience and familiarity with master limited partnerships and, more specifically, the natural gas business. These skills coupled with his broad investment banking acumen and acquisition and financing experience brings additional depth to our Board's collective expertise, and therefore makes Mr. Jackson a key addition to our Board of Directors.

        E. Bartow Jones—Mr. Jones is a member of our board, the board of directors of our manager and the board of supervisors of Niska Holdings, which is our parent. Mr. Jones is currently a Managing Director of Riverstone Holdings LLC where he served as a Principal from 2007 to 2010. Mr. Jones has been with Riverstone since 2001. Mr. Jones currently serves on the boards of directors of Foresight Reserves, L.P., or Foresight, and Targe Energy, LLC, or Targe, and he previously served on the boards of directors of Buckeye and Mainline Management.

        Mr. Jones has worked closely with us since our inception. Mr. Jones's experience in evaluating the financial performance and operations of companies in our industry, as well as his leadership skills and business acumen, provide him with the necessary skills to serve as a member of our board. In addition, Mr. Jones's work with Foresight, Buckeye, Targe and MainLine Management has given him both an understanding of the broader energy business and of the unique issues related to operating publicly-traded limited partnerships, which are similar to us.

        Stephen C. Muther—Mr. Muther served as President of the general partner of Buckeye Partners, L.P. ("BPL") and the general partner of Buckeye GP Holdings L.P. ("BGH") from October 25, 2007 until his retirement in February 2009. BPL is a publicly-traded master limited partnership that is principally engaged in the transportation, terminalling, marketing and storage of refined petroleum products for major integrated oil companies, large refined products marketing companies and major end users of petroleum products. BGH is a publicly-traded master limited partnership that owns 100% of the general partner of BPL. From February 2007 to November 2007, Mr. Muther served as Executive Vice President, Administration and Legal Affairs of the general partners of BPL and BGH, and from May 1990 to February 2007, Mr. Muther held the position of Senior Vice President, Administration, General Counsel and Secretary of the general partner of BPL. Prior to joining Buckeye, Mr. Muther was Associate Litigation and Antitrust Counsel for General Electric Company from July 1984 to May 1990. Mr. Muther was an associate attorney with

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Debevoise & Plimpton in New York City from February 1975 to June 1984. Mr. Muther graduated from Princeton University in 1971 and from the University of Virginia School of Law in 1974.

        As a result of his service to BPL and BGH, Mr. Muther gained extensive experience in overseeing the strategy, operations, and governance of major public companies. Mr. Muther was also selected to serve as a director of our board due to his valuable legal expertise and his knowledge of the energy industry. Mr. Muther's experience has also given him knowledge of the unique issues related to operating publicly-traded limited partnerships, which are similar to us. We believe this background and skill set makes Mr. Muther well-suited to serve as a member of our board.

        George A. O'Brien—Mr. O'Brien is a member of our board and the board of directors of our manager. Mr. O'Brien has served as an independent director of Magellan GP, LLC, and general partner of Magellan Midstream Partners, L.P., or Magellan, a publicly-traded company that is engaged in the transportation, storage and distribution of refined petroleum products, from December 2003 until November 2009. Mr. O'Brien was President and CEO of Pacific Lumber Company from August 2006 until July 2008. From 1988 until 2005, he worked for International Paper where he served as Senior Vice President of Forest Products responsible for its forestry, wood products, minerals and specialty chemicals businesses. Other responsibilities during his tenure at International Paper included corporate development, CFO of its New Zealand subsidiary, CEO of the New Zealand pulp, paper and tissue businesses and Vice President of Corporate Development. In January 2007, Pacific Lumber Company filed for voluntary reorganization under Chapter 11 of the United States Bankruptcy Code. Pacific Lumber successfully emerged from Chapter 11 in July, 2008. Mr. O'Brien has an agreement with Riverstone, pursuant to which he has agreed to serve on the boards of Carlyle/Riverstone Funds' portfolio companies.

        As a result of his service to Magellan and International Paper, Mr. O'Brien gained extensive experience in overseeing the strategy, operations, and governance of major public companies. Mr. O'Brien was also selected to serve as a director of our board due to his valuable financial expertise, including extensive experience with capital markets transactions and knowledge of the energy industry. Mr. O'Brien's experience has also given him knowledge of the unique issues related to operating publicly-traded limited partnerships, which are similar to us. We believe this background and skill set makes Mr. O'Brien well-suited to serve as a member of our board.

        William H. Shea, Jr.—Mr. Shea is a member of our board and the board of directors of our manager. Mr. Shea has served as a director and Chief Executive Officer of Penn Virginia Resource Partners, L.P. since March 2010. Previously, Mr. Shea served as the Chairman of Buckeye GP LLC, the general partner of Buckeye Partners, L.P., a refined petroleum products pipeline partnership from May 2004 to July 2007, as President and Chief Executive Officer of Buckeye GP LLC from September 2000 to July 2007 and as President and Chief Operating Officer of Buckeye GP LLC from July 1998 to September 2000. From August 2006 to July 2007, Mr. Shea served as Chairman of MainLine Management LLC, the general partner of Buckeye GP Holdings, L.P., and as President and Chief Executive Officer of MainLine Management LLC from May 2004 to July 2007. Mr. Shea also serves as a director of Kayne Anderson Energy Total Return Fund, Inc. and Kayne Anderson MLP Investment Company. Mr. Shea has an agreement with Riverstone, pursuant to which he has agreed to serve on the boards of Carlyle/Riverstone Funds' portfolio companies.

        Mr. Shea's experiences as an executive with both Penn Virginia and Buckeye, energy companies that operate across a broad spectrum of sectors, including coal, natural gas gathering and processing and refined petroleum products transportation, have given him valuable knowledge about our industry. In addition, Mr. Shea has valuable experience overseeing the strategy and operations of publicly-traded partnerships, which are similar to us. As a result of this experience and resulting skills set, we believe Mr. Shea is an asset to our board.

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        Andrew W. Ward—Mr. Ward is a member of our board, the board of directors of our manager and the board of supervisors of Niska Holdings, which is our parent. Mr. Ward has served as a member of the board of supervisors of Niska Holdings since May 2006. He is currently a Managing Director of Riverstone Holdings LLC where he served as a Principal from March 2002 to December 2004. Mr. Ward currently serves on the board of directors of Gibson Energy and GEP Midstream and has previously served on the boards of directors of Buckeye GP LLC, or Buckeye, the general partner of Buckeye Partners, L.P., a refined petroleum products pipeline partnership, and MainLine Management LLC, or MainLine Management, the general partner of Buckeye GP Holdings L.P.

        Mr. Ward has served as a director since our inception. Mr. Ward's experience in evaluating the financial performance and operations of companies in our industry, combined with his leadership skills and business acumen, makes him a valuable member of our board. In addition, Mr. Ward's work with Gibson Energy, GEP Midstream, Buckeye and MainLine Management has given him both an understanding of the midstream sector of the energy business and of the unique issues related to operating publicly-traded limited partnerships, which are similar to us.

    Our Independent Directors

        Our Board has determined that Deborah M. Fretz, Stephen C. Muther and James G. Jackson are independent directors under the listing standards of the NYSE. Our Board considered all relevant facts and circumstances and applied the independence guidelines of the NYSE in determining that neither of these directors has any material relationship with us, our management, our general partner or its affiliates or our subsidiaries.

        We hold regularly scheduled meetings of our independent directors. In accordance with our Corporate Governance Guidelines, Mr. Muther will preside over meetings of our independent directors.

        The procedure by which any interested party may communicate directly with an independent director is set forth in our Corporate Governance Guidelines, which is available on our website.

    Audit Committee

        Our board has established an audit committee to assist it in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our Audit Committee is comprised of Ms. Fretz, Mr. Muther and Mr. Jackson. Our audit committee is fully independent as defined in the listing standards of the NYSE. Our audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the audit committee.

        We have designated Ms. Fretz, Mr. Muther and Mr. Jackson as audit committee financial experts. Mr. Muther has been appointed the Chairman of the audit committee.

    Compensation Committee; Compensation Committee Interlocks and Insider Participation

        As a controlled company that is listed on the NYSE, we are not required to have a compensation committee. In order to conform to best governance practices, however, our board has established a compensation committee to, among other things, oversee the compensation plans described below. The compensation committee establishes and reviews general policies related to our compensation and benefits. The compensation committee has the responsibility to determine and approve, or make

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recommendations to the board with respect to, the compensation and benefits of our board and executive officers.

        The Compensation Committee is composed of Mr. O'Brien, Mr. Shea and Ms. Fretz. Ms. Fretz is an independent director (as that term is defined in the applicable NYSE rules and Rule 10A-3 of the Exchange Act). All members of the compensation committee are non-employee directors (as that term is defined in Rule 16b-3 of the Exchange Act). None of our executive officers served as a director or member of a compensation committee of another entity that has or has had an executive officer who served as a member of our board during 2010, 2009 or 2008.

    Conflicts Committee

        Whenever a conflict arises between our manager or its affiliates, on the one hand, and us or any unaffiliated member, on the other, our board will resolve that conflict. Our board may establish a conflicts committee to review specific matters that our board refers to it. Our board may, but is not required to, seek the approval of such resolution from the conflicts committee. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. Such a committee would consist of a minimum of two members, none of whom can be officers or employees of our manager or directors, officers or employees of its affiliates (other than us and our subsidiaries) and each of whom must meet the independence standards for service on an audit committee established by the NYSE and the SEC. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our manager of any duties it may owe us or our unitholders.

        If our board does not seek approval from the conflicts committee, and the board determines that the resolution or course of action taken with respect to the conflict of interest is either (1) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (2) fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us, then it will be presumed that, in making its decision, our board acted in good faith, and in any proceeding brought by or on behalf of us or any member, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Reimbursement of Expenses of Our Manager

        Our manager does not receive any management fee or other compensation for providing management services to us. Our manager will be reimbursed for any expenses incurred on our behalf. There is no limit on the amount of expenses for which our manager may be reimbursed.

        In connection with the earlier acquisition of our assets from EnCana Corporation on May 12, 2006, our predecessor agreed to pay Carlyle/Riverstone an annual management fee of $1.0 million, plus the reimbursement of certain costs and expenses for its services. We are no longer subject to this obligation to Carlyle/Riverstone, as it remained with Holdco upon the formation of Niska Gas Storage Partners LLC.

Code of Ethics

        We have adopted a Code of Business Conduct and Ethics that applies to all of our officers, directors and employees.

        Available on our website at http://www.niskapartners.com are copies of our Audit Committee Charter, our Compensation Committee Charter, our Code of Business Conduct and Ethics and our Corporate Governance Guidelines, all of which also will be provided to unitholders without charge

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upon their written request to Niska Gas Storage Partners LLC, 1001 Fannin Street, Suite 2500, Houston, TX 77002, Attention: General Counsel.

Section 16(a) Beneficial Ownership Reporting Compliance

        Section 16(a) of the Securities Exchange Act requires our officers and directors, and persons who own more than ten percent of a registered class of our equity securities, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the Securities and Exchange Commission. Officers, directors and greater-than-ten-percent shareowners are required by regulations promulgated by the Securities and Exchange Commission to furnish us with copies of all Forms 3, 4 and 5 they file.

        Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to us during fiscal 2011 and upon a review of Forms 5 and amendments thereto furnished to us with respect to fiscal 2011, or upon written representations received by us from certain reporting persons that no Forms 5 were required for those persons, we believe that no director, executive officer or greater-than-ten-percent shareholder failed to file on a timely basis the reports required by Section 16(a) of the Exchange Act during, or with respect to, fiscal 2011, except that through inadvertence, the Forms 4 reporting one grant of units to each of Ms. Fretz and Mr. Muther were not timely filed. We have since rectified this process.

Significant Differences in Corporate Governance Standards

        Because Holdco controls more than 50% of the voting power for the election of our directors, we are a controlled company within the meaning of NYSE rules, which exempt controlled companies from the following corporate governance requirements:

    the requirement that a majority of the board consist of independent directors;

    the requirement that we have a nominating or corporate governance committee, composed entirely of independent directors, that is responsible for identifying individuals qualified to become board members, consistent with criteria approved by the board, selection of board nominees for the next annual meeting of shareholders, development of corporate governance guidelines and oversight of the evaluation of the board and management;

    the requirement that we have a compensation committee of the board, composed entirely of independent directors, that is responsible for reviewing and approving corporate goals and objectives relevant to chief executive officer compensation, evaluation of the chief executive officer's performance in light of the goals and objectives, determination and approval of the chief executive officer's compensation, making recommendations to the board with respect to compensation of other executive officers and incentive compensation and equity-based plans that are subject to board approval and producing a report on executive compensation to be included in an annual proxy statement or Form 10-K filed with the SEC;

    the requirement that we conduct an annual performance evaluation of the nominating, corporate governance and compensation committees; and

    the requirement that we have written charters for the nominating, corporate governance and compensation committees addressing the committees' responsibilities and annual performance evaluations.

        For so long as we remain a controlled company, we are not required to have a majority of independent directors or nominating, corporate governance or compensation committees. Accordingly, our unitholders may not have the same protections afforded to shareholders of companies that are subject to all of the NYSE corporate governance requirements.

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        In reliance on these exemptions, our Board is not comprised of a majority of independent directors, nor do we maintain a nominating/corporate governance committee.

Directors, Executive Officers and Corporate Governance—Directors and Executive Officers: Actions Taken Following the Fiscal Year Ended March 31, 2011

        On June 8, 2011, Mr. Pope informed our board that he will be resigning as our President and Chief Executive Officer as well as all other positions with the subsidiaries and related entities of Niska Gas Storage Partners LLC,, effective July 1, 2011. However, we expect Mr. Pope to remain a member of our board following his resignation as our President and Chief Executive Officer. As a member of our board, Mr. Pope will be entitled to the same compensation as our directors who are not officers, employees or paid consultants and advisors of our manager or its affiliates.

        Our board has appointed Mr. Dupéré as interim Chief Executive Officer, effective July 1, 2011. Mr. Dupéré will hold such office until a permanent Chief Executive Officer is appointed or until his earlier removal or resignation. In addition to this interim role, Mr. Dupéré will continue to act as our Chief Operating Officer. In addition, in connection with Mr. Pope's resignation, our board has elected Ms. Deborah Fretz as our interim non-executive Chairman of the Board, effective July 1, 2011.

Item 11.    Executive Compensation.

Compensation Discussion and Analysis

        From our inception in 2006 until our IPO, we operated as a private company. During this pre-IPO period, the compensation committee of the board of supervisors of Niska Predecessor, or the predecessor compensation committee, established the compensation of our named executive officers. Now the manager and our board, as its delegate, manages our operations and activities and makes decisions on our behalf. Our board has established a compensation committee that, while our board has delegation powers from our manager to oversee our operations, will determine and set compensation practices, or make recommendations to the full board regarding compensation matters that the board has reserved final authority over, as applicable. The compensation of each of our executive officers, including David Pope, Simon Dupéré, Vance Powers, Rick Staples, Jason Dubchak, Darin Olson and Paul Amirault (collectively, the "named executive officers"), for the fiscal year ending March 31, 2011 was determined and implemented solely by our compensation committee.

        Historically, the objectives of our executive compensation program were to:

    attract and retain the highest quality executive officers in our industry;

    reward the executive officers as a group for our improved performance (measured in terms of Adjusted EBITDA); and

    reward executive officers for their individual performance and contributions to our success.

        The predecessor compensation committee felt that these objectives were best met by providing a mix of cash and equity-based compensation to our executives, and we continue to believe that this mix of compensation elements provided us with a successful compensation program because it has allowed us to retain key employees and attract a quality team of executives, while motivating them to provide a high level of performance to us. We expect our compensation committee to seek to satisfy the same objectives; although the committee will make certain adjustments to the types of compensation provided and performance metrics used in order to more accurately reflect a compensation program appropriate for a publicly-traded entity.

        This section describes the objectives and elements of our compensation program for the fiscal year ended March 31, 2011 for our named executive officers. This section should be read together with the Compensation Tables that follow, which disclose the compensation awarded to, earned by or paid to

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the named executive officers with respect to the prior fiscal year, as well as for certain elements of compensation paid to the named executive officers for the fiscal years ending on March 31, 2009 and March 31, 2010.

    Setting Executive Compensation

        We have not historically utilized an outside compensation consultant or firm to assist in setting our executive compensation programs. The predecessor board utilized internal human resources staff to compile information regarding the executives' current and past compensation, and to obtain any publicly available compensation information regarding executive positions at companies that the board determined to be a "peer" company, but did not engage in any benchmarking practices nor did the predecessor board adhere to any type of formula when setting compensation. Our board, and the compensation committee of our board, holds the authority to engage outside assistance or a compensation consultant firm in setting executive compensation if it appears at any time that such assistance would be appropriate.

        On September 15, 2010, Cogent Compensation Partners was formally engaged by our Compensation Committee, on behalf of the Board of Directors to review our overall compensation structure, including short term and long term compensation. The ultimate findings and recommendation of Cogent Compensation Partners was not implemented by the Compensation Committee until April 1, 2011.

        Elements of Compensation.    The primary elements of our named executive officers' compensation other than the officer's base salary are a combination of cash bonus awards and long-term equity-based compensation awards. For the fiscal year ended March 31, 2011, the compensation for our named executive officers consisted of the following elements:

    base salary;

    discretionary cash bonus awards; and

    retirement, health and welfare and related benefits.

        Base Salary.    The predecessor compensation committee established base salaries for the named executive officers based on various factors, including the amounts it considered necessary to attract and retain high quality executives in our industry and the responsibilities of the named executive officers, and were responsible for approving any significant changes to executive salaries. Salaries for the named executive officers are generally adjusted on an annual basis to remain competitive as compared to the market.

        For the fiscal year ended March 31, 2011, Mr. Pope had an employment agreement with AECO Partnership, our wholly owned subsidiary that employs and is responsible for providing compensation and benefits for all of our employees and executive officers. The employment agreement provided for a minimum annual base salary of $450,000 (Canadian dollars, which, using the exchange rate noted within the Summary Compensation Table below, would be approximately $442,620 US dollars). This base salary amount was determined based upon the scope of Mr. Pope's responsibilities and commensurate with Mr. Pope's position as chief executive officer. The employment agreement stated that Mr. Pope's salary was eligible to be increased above the minimum at the predecessor compensation committee's discretion. In reviewing Mr. Pope's base salary for the year following March 31, 2009, however, the predecessor compensation committee determined that the salary set within Mr. Pope's employment agreement continued to be consistent with the duties and the everyday tasks for which he is responsible. On March 29, 2011, however, Mr. Pope entered into a new employment agreement that became effective on April 1, 2011, and the changes to his base salary and other elements of his compensation that became effective with that new employment agreement are discussed in greater detail below.

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        Discretionary Bonus Awards.    A significant portion of the compensation of our named executive officers consists of an annual cash bonus. While base salaries offer an important retention element by providing a guaranteed income stream to our employees, we hope to incentivize and motivate our employees to strive for both individual and overall company success by providing a substantial portion of compensation only when performance for the year calls for an additional compensatory award. We feel that our industry has historically relied heavily on performance-based cash bonuses to compensate executive officers, and we want to compensate our executives in line with our industry trends and practices. For the prior fiscal year, we accomplished this goal by awarding discretionary bonus awards to our employees, but with respect to bonuses following the end of the prior fiscal year, please see our discussion of the Short Term Incentive Plan described below.

        Historically the predecessor compensation committee determined the size, timing and allocation of the bonus based on initial recommendations from our chief executive officer. While the ultimate amount of any cash bonus paid to our named executive officers is now determined at the discretion of our board, the bonuses are originally structured around target amounts for each employee, as well as individual and company goals. We communicate a target annual bonus amount to our employees as a certain percentage of their base salary at the beginning of their employment, clearly noting that individual or company performance may significantly impact the relationship of that target annual amount to what is actually paid out in bonuses. Individual performance goals will depend on an employee's unit or particular function within a unit, while company performance has historically been tied to Adjusted EBITDA. We believe that paying a bonus tied to our Adjusted EBITDA aligns the interests of our executives and employees with those of our unitholders and motivates them to provide a high level of performance for us. A portion of the bonuses are accrued, but not paid, pending the results of the fiscal year end audit and subsequent audit adjustments. Thus, while those portions are accrued for the year in which they are earned, they are not paid until the following fiscal year.

        Historically, we have established a bonus pool for each fiscal year to be allocated among all employees, including the named executive officers. There have been two layers of potential bonus pools, a bonus pool of 3% of our first $80.0 million of Adjusted EBITDA, and an additional pool of 8% of Adjusted EBITDA over $80.0 million. Following a determination of the amount of the available bonus pool, a series of meetings occurs prior to the board's final determination of individual amounts owed to employees. The managers or supervisors of various business units first met with Mr. Pope to discuss the individual performance of employees that have worked directly under such managers. Mr. Pope then compiled this information and met with our predecessor compensation committee, where he made recommendations regarding the allotment of the bonus pool based on either ranges of amounts or a specific amount he believed are appropriate for the year. The predecessor compensation committee then met with our board to pass on its recommendations, which may or may not have been in line with the recommendations of Mr. Pope, as the predecessor compensation committee felt appropriate. The board then made the final determination of specific amounts due to each employee, including our named executive officers. We anticipate that the same process will continue on a going forward basis, although we will substitute our compensation committee for our predecessor compensation committee. Mr. Pope also receives his bonus from the same bonus pool as all other employees, thus by recommending the allotment of the bonus pool for other employees, Mr. Pope indirectly will have inferred the amount of the bonus pool that could potentially be reserved for himself; however, our compensation committee, and then our board, will ultimately make all determinations of Mr. Pope's annual cash bonus, if any. The board's determination regarding any individual award may be based solely on the targets and performance measures that have been used as guidelines for that year, or it may take into consideration extraordinary circumstances or past awards of compensation to the individual.

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    Long Term Equity-Based Incentives

        Niska Predecessor Class B and Class C Units.    In 2006, Niska Predecessor issued Class B units to some of our employees, including the named executive officers then employed by us, and Class C units to Mr. Pope pursuant to the terms of his employment agreement and Niska Predecessor's partnership agreements. The Class B and Class C units represented profits interest in Niska Holdings, and entitle the holders to share in distributions by Niska Holdings once the Class A units in Niska Predecessor have received distributions equal to their contributed capital plus an 8% rate of return. As of March 31, 2011, the risk of forfeiture had lapsed on all of the Class B and Class C units upon the completion of the time limitations or the achievement of the performance conditions associated with the units as applicable and certain of our named executive officers continue to hold these vested units and may receive certain profits interests with respect to these awards. No further grant of the Class B or Class C units, however, occurred during the prior fiscal year or will occur in the future.

        Following the end of the fiscal year ending March 31, 2011, we also adopted a cash-based long term phantom unit plan for our employees and certain directors that is described below, the Phantom Unit Performance Plan ("PUPP").

        Health and Welfare Benefits.    All of our regular full-time employees, including our named executive officers, receive certain health and welfare benefits. The benefits include a health and dental plan, a short- and long-term disability plan, basic and optional life insurance, and basic and optional accidental death and dismemberment insurance coverage (with the exception of Mr. Powers). Pursuant to his employment agreement that was effective during the fiscal year ended March 31, 2011, as well his new employment agreement, Mr. Pope is entitled to receive an annual allowance of $6,000 in order to cover additional health care expenses not directly provided or paid for by us. We also own a life insurance policy on the life of Mr. Pope, where we are both the owner and beneficiary. We make payments on Mr. Pope's behalf for a Critical Illness policy that was previously established by Mr. Pope's prior employer and continued by us. Mr. Powers receives health and dental benefits only, which are funded by us.

        Retirement and Pension Benefits.    Our registered retirement savings plan, or RRSP Plan/Non-Registered Employee Savings Plan, provides Canadian resident employees with an opportunity to participate in a retirement savings plan. This type of retirement plan is a Canadian retirement plan with features similar to a 401(k) plan or an individual retirement account administered in the United States. Our employees, including our named executive officers (other than Mr. Powers), are allowed to contribute their own funds, and we will provide certain matching contributions as well as discretionary contributions from us on their behalf from time to time. Mr. Pope's employment agreement states that he will receive an annual contribution from us of 8% of his annual base salary, and in the event that Mr. Pope contributes 5% to 25% of his own compensation, a corporate match of up to 5% annually. Mr. Powers, a U.S. citizen, participates in a US 401(k) Plan which allows Mr. Powers to contribute his own funds and the Company provides an 11% contribution to his 401(k) Plan.

        Mr. Pope's prior employer maintained a Supplemental Executive Retirement Plan, or a SERP, which Mr. Pope participated in prior to his employment with us. The SERP was intended to provide him with a $250,000 annual retirement benefit for a period of ten years, or in the event of Mr. Pope's death prior to retirement, a death benefit to his beneficiaries of $1,500,000. Within Mr. Pope's previous employment agreement, as well as his new employment agreement with us, we agreed to provide Mr. Pope with the same retirement benefits to which he would have been entitled under the SERP. Mr. Pope's prior employer had begun to fund Mr. Pope's SERP benefit by way of a life insurance policy on the life of Mr. Pope, which we took over as both owner and beneficiary in 2006 in connection with Mr. Pope's execution of his previous employment agreement with us. We intend to continue funding this life insurance policy as a means of financing Mr. Pope's eventual retirement or death benefit.

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        Perquisites.    We provide our named executive officers with certain perquisites that we feel are in line with industry standards as well as peer companies within our geographic region, and which are necessary to stay competitive with regard to executive compensation. Certain of these perquisites relate to items that are "carry-overs," or perquisites that were provided to the executives when they were previously employed by EnCana Corporation or its affiliates, and we felt that it would be unjust to take such benefits away from the executives following their employment with us. Our named executives (other than Mr. Powers) received additional payments to be applied to expenses for home computers, club membership (including industry organizations) and other personal expenses, as well as a monthly automobile allowance and paid parking at our office facilities.

    Actions Taken Following the Fiscal Year Ended March 31, 2011

        As previously discussed, the compensation committee believed that it was important to examine and potentially alter our overall compensation structure and of our executives to more accurately reflect a market-based compensation structure that was appropriate for a publicly traded limited partnership. Therefore, after performing such examination over the course of fiscal 2011, with the assistance of Cogent Compensation Partners, the compensation committee put in place a new comprehensive plan, which included changes to base salary, short term incentives and long term incentives. This new compensation plan was implemented on April 1, 2011 and is briefly described below.

        Base Salary    On March 24, 2011, our board approved, on the recommendation of the compensation committee, changes to many employees and executives base salary. These changes became effective on April 1, 2011 and were a result of the examination and surveys of the market conducted by the compensation committee and Cogent Compensation Partners over the course of fiscal year 2011. The changes were made to bring the base salary compensation in-line with other similarly-situated market comparables for publicly traded entities, and in particular, limited partnerships.

        Short Term Incentive Plan.    On March 24, 2011, our board approved the framework of a short term incentive bonus plan applicable to our employees, including our named executive officers, for the 2012 fiscal year (which will begin on April 1, 2011) (the "STI"). This is the functional equivalent to the former annual cash bonus compensation previously awarded under the fiscal 2011 compensation structure. The STI will provide annual bonuses based upon the achievement, if any, of our company performance targets, as well as individual performance targets for certain employees, which we expect our Compensation Committee to set each year.

        Long Term Incentive Plan.    On March 24, 2011, our board established a cash-based long-term compensation plan for our employees that we intend to use utilize during the fiscal year 2012 (the "PUPP"), as previously described. A principal purpose of the PUPP is to further align the interests of participants in the PUPP, including our named executive officers, with the interest of our unit holders by providing certain employees and directors with a phantom unit award. 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 our common units (a "Unit"), following the satisfaction of certain time periods and/or certain performance criteria.

        The PUPP will be primarily administered by our compensation committee under the overall direction of our board. The compensation committee will determine all of the terms and conditions of each Phantom Unit award, subject to the terms and conditions required by the PUPP, and will grant Phantom Units to eligible participants at such times as the compensation committee may determine to be appropriate. Such terms and conditions will be set forth in an individual Phantom Unit award agreement at the time of each grant of Phantom Units.

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        Phantom Unit awards under the PUPP will become vested upon the date or dates on which the compensation committee sets forth in the award agreement and subject to such performance conditions as the compensation committee may assign to the particular Phantom Unit award. Unless the compensation committee specifies otherwise within the award agreement, Phantom Units will be granted unvested and subject to both time and performance conditions. The default time period over which the Phantom Unit will vest will be three years from the date of grant, and the performance measure will be based upon DCF and TUR metrics compared to such metrics at a select group of peer companies to us, except that the we expect that initial grants of Phantom Units will be grossed up to 167% of the target amount for each recipient and will vest 2/3 after one year and 1/3 after two years (in order that 100% of the target number will vest in one year and 2/3 of the target number initially granted (together with an additional 1/3 of a subsequent grant assuming the PUPP is administered as expected). "DCF" is defined within the PUPP as distributed cash flow from a trust, partnership or corporation calculated based on the appreciation in the distributed cash flow per Unit or any other applicable publicly traded security during the performance period. "TUR" is defined within the PUPP as the total unitholder return of a trust, partnership or corporation, calculated based on the appreciation in the price of a Unit or other applicable traded security during the performance period. The DCF and TUR metrics will be calculated based on our percentile ranking during the applicable performance period compared to a peer group that will be determined by the compensation committee from time to time. Provided that we have satisfied our minimum quarterly distribution targets for the underlying Units, the Phantom Units will typically vest in accordance with the following performance criteria:


TUR Percentile

% of Phantom Units Earned at Payout

 
  Below
35thpercentile
  35th percentile   50th percentile   75th percentile  

Max.—75th percentile

    0 %   100 %   150 %   200 %

Target—50th percentile

    0 %   75 %   100 %   150 %

Threshold—35th percentile

    0 %   50 %   75 %   100 %

Below 35th percentile

    0 %   0 %   0 %   0 %


DCF Percentile

        The PUPP participants must also generally be providing services to us or one of our affiliates in order for their Phantom Unit to become vested. The compensation committee will have authority to provide for accelerated vesting provisions in the event of a termination of employment or a change in control. Generally, in the event of a PUPP participant's death, disability, retirement, or termination of employment without cause, unvested Phantom Units will vest on a pro rata basis by taking into account the number of days of actual service provided to us or one of our affiliates versus the number of days in the entire vesting period for the award. Where the Phantom Units are subject to performance criteria, a "target" level of performance will be applied upon any acceleration of vesting, such that a maximum of 100% of the Phantom Units originally granted will become vested. Where vesting of the Phantom Units are based solely on time, the Phantom Units will also vest on a pro rata basis calculated by the number of days of service provided to us or one of our affiliates from the grant date to the vesting date. Unless otherwise provided in an individual award agreement, if we incur a change in control, and the holder is also terminated, the Phantom Units will also receive accelerated vesting, with any performance-based vesting provisions being accelerated at the "target" performance level.

        The Phantom Units will also be granted with distribution equivalent rights. During the period the Phantom Unit is outstanding, any distribution that we pay to Unit holders generally will also be credited to the Phantom Unit holder in the form of additional Phantom Units. The number of additional Phantom Units to be credited to a PUPP participant's account will be determined by

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dividing the full amount of the distribution we would have made to the Phantom Unit holder if the Phantom Units were non-restricted Units, by the fair market value of a Unit on the payment date of any distribution.

        In the event that a PUPP participant is subject solely to the United States securities and tax laws rather than Canadian tax or securities laws, the PUPP also contains a schedule of certain provisions that will apply to those participants in lieu of certain provisions within the main body of the PUPP document.

        Mr. Pope's Employment Agreement.    Mr. Pope's previous employment agreement was entered into with Niska Gas Storage, and subsequently amended by an agreement that placed his employment with AECO Gas Storage Partnership (by its managing partner Niska Gas Storage Canada ULC) in 2009. Following our IPO and certain corporate restructuring events, we entered into a new employment agreement with Mr. Pope to clarify his position as the President and Chief Executive Officer of Niska Partners Management ULC and all of its subsidiaries, including Niska Gas Storage Partners LLC. The term of the new employment agreement began on April 1, 2011 and will continue for an indefinite period of time, but may be terminated at the discretion of Mr. Pope or us, with or without cause. Mr. Pope's compensation pursuant to the new employment agreement will include an annual base salary of not less than $550,000 Canadian dollars (approximately $540,980 in US dollars using the exchange rate in effect on March 31, 2011), payable in semi-monthly installments. Mr. Pope will be entitled to participate in the PUPP and receive phantom unit awards. The new employment agreement provides Mr. Pope with an annual allowance of $24,000 per year for expenses related to home computers, annual social club memberships and other personal expenses, a $6,000 annual supplemental health care allowance, a $2,000 (Canadian dollars) per month automobile allowance and four weeks of vacation per year. Mr. Pope will remain eligible to participate in our RRSP Plan/Non-Registered Employee Savings Plan, where he will receive an employer contribution on his behalf equal to eight percent (8%) of his annual base salary, as well as an employer matching contribution that will be capped at five percent (5%) of his annual base salary.

        The terms and conditions relating to potential severance payments, as well as our rationale for providing these benefits to Mr. Pope, are further described in the section below titled "Potential Payments Upon Termination or Change in Control."

        Mr. Pope's Retirement.    On June 8, 2011, Mr. Pope informed our board that he will be resigning as our President and Chief Executive Officer, effective July 1, 2011. We expect Mr. Pope to remain a member of our board following his resignation as our President and Chief Executive Officer. As a member of our board, Mr. Pope will be entitled to the same compensation as our directors who are not officers, employees or paid consultants and advisors of our manager or its affiliates.

Report of the Compensation Committee

        In light of the foregoing, as required by Item 407(e)(5) of Regulation S-K, our compensation committee has reviewed and discussed the Compensation Discussion and Analysis with our management and, based on such review and discussions, has recommended to the board of directors that the Compensation Discussion and Analysis be included in this annual report.

    By the Compensation Committee:
    George A. O'Brien, Chairman
    Deborah M. Fretz
    William H. Shea

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Executive Compensation

        The following tables, footnotes and the above narratives provide information regarding the compensation, benefits and equity holdings in Niska Holdings for the named executive officers.

    Summary Compensation for Years Ended March 31, 2011, 2010 and 2009

        The following table and footnotes provide information regarding the compensation of the named executive officers during the fiscal years ended March 31, 2009, March 31, 2010 and March 31, 2011. The year "2009" refers to the fiscal year of April 1, 2008 through March 31, 2009, the year "2010" refers to the fiscal year of April 1, 2009 through March 31, 2010, and the year "2011" refers to the fiscal year of April 1, 2010 through March 31, 2011. Compensation to our named executive officers was paid primarily in Canadian dollars, but is reported in U.S. dollars in the tables that follow. An exchange rate of 0.952 U.S. dollars was used for the 2009 and 2010 amounts for each Canadian dollar (the exchange rate reported by the Bank of Canada on December 31, 2009) and 0.9836 U.S dollars for each Canadian dollar was used for the 2011 amounts of each Canadian dollar (the exchange rate reported by the Bank of Canada on March 31, 2011). The only exception to this rule is for our new Chief Financial Officer, Vance E. Powers, who is a US resident and paid in US dollars.

Name and Principal Position
  Year
Covered
  Salary
($)
  Bonus
($)
  All Other
Compensation
($)(4)
  Total
($)
 

David F. Pope(1)

    2011     464,751     2,181,133     125,750     2,771,634  
 

Chief Executive Officer Principal Executive

    2010     449,820     5,571,384     72,631     6,093,835  
 

Officer)

    2009     444,465     2,374,296     108,094     2,926,855  

Simon Dupéré(2)

   
2011
   
270,490
   
849,585
   
63,566
   
1,183,641
 
 

Chief Operating Officer

    2010     245,378     1,767,960     44,219     2,057,557  

    2009     237,048     849,802     50,001     1,136,852  

Vance E. Powers

   
2011
   
55,000
   
102,667
   
9,534
   
167,201
 
 

Chief Financial Officer (Principal Financial

                               
 

Officer)

                               

Rick J. Staples(2)

   
2011
   
206,556
   
503,603
   
50,641
   
760,800
 
 

Senior Vice President, Commercial

    2010     191,411     1,258,544     49,563     1,499,518  
 

Operations

    2009     182,724     396,984     50,219     629,928  

Jason Dubchak

   
2011
   
196,720
   
354,096
   
26,605
   
577,421
 
 

Vice President, General Counsel &

                               
 

Corporate Secretary

                               

Darin Olson(2)

   
2011
   
196,720
   
295,080
   
39,757
   
531,557
 
 

Chief Financial Officer / Vice President,

    2010     177,310     553,112     31,393     761,815  
 

Finance

    2009     160,301     292,740     33,508     486,549  

Paul Amirault(3)

   
2011
   
137,463
   
0
   
316,798
   
454,261
 
 

Senior Vice President

    2010     213,992     658,784     36,626     909,402  

    2009     211,796     325,108     41,924     578,828  

(1)
$1,000,000 of Mr. Pope's bonus, which was accrued in fiscal year 2010, was not paid until September, 2010. However, the payment was made in relation to services provided by Mr. Pope during fiscal year 2010.

(2)
In the fiscal year ended March 31, 2010, Darin Olson was granted 900 Class B units, Simon Dupéré was granted 5,406 Class B units, and Rick Staples was granted 3,604 Class B units. Each of

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    the Class B units granted in the 2010 year was granted fully vested. In accordance with FASB ASC Topic 718, however, we recognized a $0 grant date fair value, and recognize no dollar amount with respect to financial reporting purposes upon the vesting of any previously granted Class B and Class C units. In the fiscal year ended March 31, 2011, no additional Class B or Class C units were granted, and no equity-based compensation awards from the Plan were granted during the prior fiscal year.

(3)
In the fiscal year ended March 31, 2011, Paul Amirault retired and received a retiring allowance of $295,080 USD which is part of the "All Other Compensation" total.

(4)
Amounts disclosed in the "All Other Compensation" column for the fiscal year ending in 2011 consist of the following items and amounts in USD:

Executive Officer
  RRSP
Plan
($)
  Parking
($)
  Vehicle
Allowance
($)
  Misc
Allowance &
Vacation
Buy back
($)
  Canadian
Pension
Plan
($)
  Employment
Insurance
($)
  Workers
Comp
Contributions
($)
  Total
($)
 

David Pope

    37,180     5,016     23,606     56,321     2,181     859     586     125,750  

Simon Dupéré

    21,639     5,016     17,705     15,605     2,181     859     560     63,566  

Rick Staples

    16,524     5,016     13,770     11,803     2,181     859     486     50,641  

Jason Dubchak

    15,738     5,016     0     2,361     2,181     859     451     26,605  

Darin Olson

    15,738     5,016     0     15,495     2,181     859     467     39,757  

Paul Amirault

    10,997     3,344     0     302,457     0     0     55     316,798  

 

US Executive Officer
  401K
Contributions
($)
  Parking
($)
  Vehicle
Allowance
($)
  Misc.
Allowance &
Vacation
Buy back
($)
  Social
Security
($)
  Medicare
($)
  Workers
Comp
Contributions
($)
  Total
($)
 

Vance E. Powers

    6,050     0     0     0     2,299     794     391     9,534  

    Grants of Plan-Based Awards

        We did not grant plan-based awards to our named executive officers during the fiscal year ended March 31, 2011.

    Narrative Description to Summary Compensation Table and Grants of Plan-Based Awards

        The term of Mr. Pope's employment agreement that was effective as of March 31, 2011 began on August 20, 2006 and was set to continue for an indefinite period of time unless earlier terminated by either party. The agreement provided Mr. Pope with an annual base salary of $450,000 (Canadian dollars, which, using the exchange rate noted within the Summary Compensation Table below, would be approximately $442,620 US dollars). Mr. Pope was entitled to receive a cash bonus from the discretionary cash pool described further in the "Compensation Discussion and Analysis" above, along with certain perquisites that have been disclosed within the "All Other Compensation" section of the Summary Compensation Table above. Provisions relating to Mr. Pope's termination of employment, non-competition and non-solicitation are described in detail below.

    Outstanding Equity Awards as of Fiscal Year-End March 31, 2010

        As of March 31, 2011, the risk of forfeiture had lapsed with respect to all equity awards held by our named executive officers.

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    Option Exercises and Stock Vested

        The named executive officers did not hold any options that were exercised or any unit awards that vested during the year ended March 31, 2011.

    Pension Benefits

        We do not maintain or sponsor a pension plan for our named executive officers.

    Nonqualified Deferred Compensation

        We do not maintain or sponsor a nonqualified deferred compensation plan for our named executive officers.

    Potential Payments Upon Change of Control or Termination

        As of March 31, 2010, Mr. Pope was the only named executive officer subject to a formal employment agreement that will provide the officer with certain payments and benefits in connection with his termination of employment. And as all outstanding equity awards held by our remaining executive officers have become fully vested, there would be no amounts payable or accelerated with respect to a termination of employment or a change in control. Mr. Pope's employment agreement that was effective as of March 31, 2011 with the AECO Partnership was executed in August of 2006 and contained the terms and conditions below.

        In the event we terminated Mr. Pope for Just Cause (as defined below), all compensation payments to Mr. Pope would have ceased. If we terminated Mr. Pope other than for Just Cause, or Mr. Pope terminated his employment for Good Reason (as defined below), Mr. Pope would have received a cash payment of $900,000 (Canadian dollars, or approximately $885,240 in US dollars using the exchange rate as of March 31, 2011) less applicable withholding taxes, which amount represented two years of salary for Mr. Pope. Where Mr. Pope voluntarily resigned without Good Reason (including a normal retirement), or his employment relationship was terminated due to death or a mental or physical incapacity, all compensation payments would have ceased at such time. Canada has traditionally had a very robust jurisprudence regarding the notice provided to employees or payments made in lieu of notice (severance), payable to employees upon certain terminations, and we felt that providing the $900,000 Canadian dollar payment in the event of Mr. Pope's termination other than for Just Cause or for Good Reason was an equitable result to both Mr. Pope and us in light of the uncertain, but typically generous, severance payments authorized in the Canadian courts to executives that have litigated a severance issue due to an uncertain or nonexistent employment agreement provision on this subject.

        Any payments that Mr. Pope would have been entitled to receive upon a termination of employment would have been conditioned upon his execution of a general release in our favor. Mr. Pope would also have remained subject to the confidentiality provisions of his employment agreement, as well as the non-competition provisions for a restricted period of one year and the non-solicitation provisions for a restricted period of six months following a termination of employment.

        "Good Reason" was defined as (1) our requirement that Mr. Pope devote the majority of his time to duties inconsistent with his position; (2) a reduction of 20% or more of Mr. Pope's annual base salary; (3) the required relocation of Mr. Pope's primary work location by more than 50 miles from his primary work location at the time of his entrance into the employment agreement; (4) our refusal to allow Mr. Pope to participate in our incentive compensation plans to which are comparable to the same plans in which he participated as an employee of his previous employer; or (5) our refusal to allow Mr. Pope to participate in employment benefit programs that are comparable to the same plans in which he participated as an employee of his previous employer.

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        "Just Cause" included (1) any improper conduct by Mr. Pope which was materially detrimental to us, our business, our employees or our standing in the community; (2) a willful failure to properly carry out his duties; (3) Mr. Pope's conviction of a criminal offense; or (4) any theft, conversion or misappropriation, attempted theft, conversion or misappropriation of any of our property, clients, business or business opportunities.

        Mr. Pope's employment agreement also provided for the continuation of Mr. Pope's SERP benefit. See "—Compensation Discussion and Analysis—Other Benefits."

        Following the fiscal year ending March 31, 2011, we entered into a new employment agreement with Mr. Pope that became effective on April 1, 2011. This new employment agreement also provides Mr. Pope with potential severance benefits in connection with certain terminations of his employment that are similar to the terms of the severance provided above. As with his previous employment agreement, Mr. Pope will receive a $900,000 cash payment (Canadian dollars, or approximately $885,240 in US dollars using the exchange rate as of March 31, 2011) in the event that he is terminated by us other than for Just Cause or he resigns with Good Reason. One slight difference between the previous employment agreement and the new employment agreement is that subclause (4) of the Good Reason definition described above has been modified to address our refusal to allow Mr. Pope to participate in our incentive compensation plans that are provided for within the new employment agreement, rather than a refusal to permit him to participate in incentive plans comparable to the incentive plans that Mr. Pope participated in at his previous employer. The new employment agreement states that both Mr. Pope and we will agree that in the event this severance payment is provided to Mr. Pope, it will constitute our one and final obligation to him in connection with a termination of his employment, and it will satisfy any and all statutory obligations we may have with respect to any benefits Mr. Pope was entitled to receive at the time of his termination of employment. As with his previous employment agreement, Mr. Pope will not be entitled to any severance in the event of a termination due to his death, a mental or physical incapacity, or a resignation. Mr. Pope's new employment agreement also contains non-competition provisions for a restricted period of one year and non-solicitation provisions for a restricted period of six months following a termination of employment.

Risk Assessment

        Our compensation committee has reviewed our compensation policies as generally applicable to our employees and believes that our policies do not encourage excessive and unnecessary risk-taking, and that the level of risk that they do encourage is not reasonably likely to have a material adverse effect on us.

        Our compensation philosophy and culture support the use of base salary, certain performance-based compensation that are generally uniform in design and in operation throughout our organization and with all levels of employees. These compensation policies and practices are centrally designed and administered, and are substantially identical between our business divisions. In addition, the following specific factors, in particular, reduce the likelihood of excessive risk-taking:

    Our overall compensation levels are competitive with the market.

    Our compensation mix is balanced among (i) fixed components like salary and benefits, and (ii) annual incentives that reward our overall financial performance, operational measures and individual performance.

    The compensation committee has discretion to reduce performance-based awards when it determines that such adjustments would be appropriate based on our interests and the interests of our unit holders.

    Executive officers are subject to certain blackout periods and our insider trading policy.

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Director Compensation

        Officers, employees or paid consultants and advisors of our manager or its affiliates who also serve as our directors will not receive additional compensation for their service as our directors. Directors who are not officers, employees or paid consultants and advisors of our manager or its affiliates ("Eligible Directors") will receive a an annual cash retainer of $50,000 and restricted common units with a market value equal to $50,000 at the time of the award. In addition, Eligible Directors will receive $1,500 for each board and committee meeting that they attend. The chairperson of the audit committee will receive an additional annual fee of $15,000. Directors serving as the chairperson of our other committees will receive an additional annual fee of $10,000. Directors will also receive reimbursement for out-of-pocket expenses associated with attending meetings of the board or committees and director and officer liability insurance coverage. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.


DIRECTOR COMPENSATION TABLE

Name
  Fees
Earned
or
Paid in
Cash
($)
  Unit
Awards
($)(1)
  Option
Awards
($)
  Non-
Equity
Incentive
Plan
Compensation
($)
  Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings
($)
  All
Other
Compensation
($)
  Total
($)
 

Deborah M. Fretz

  $ 72,500   $ 49,963     0     0     0     0   $ 122,463  

James G. Jackson(2)

    0     0     0     0     0     0     0  

E. Bartow Jones

    0     0     0     0     0     0     0  

Stephen C. Muther

  $ 78,500   $ 49,963     0     0     0     0   $ 128,463  

George A. O'Brien

    0     0     0     0     0     0     0  

William H. Shea

    0     0     0     0     0     0     0  

Andrew W. Ward

    0     0     0     0     0     0     0  

(1)
Represents the aggregate number of unit awards granted to the named director during the prior fiscal year

(2)
Mr. Jackson was appointed as a member of the board of directors on May 12, 2011.

        On June 8, 2011, Mr. Pope informed our board that he will be resigning as our President and Chief Executive Officer, effective July 1, 2011. We expect Mr. Pope to remain a member of our board following his resignation as our President and Chief Executive Officer. As a member of our board, Mr. Pope will be entitled to the same compensation as our Eligible Directors.

        In connection with Mr. Pope's resignation, our board has elected Ms. Deborah Fretz as our interim non-executive Chairman of the Board, effective July 1, 2011. In addition to the director compensation described above, as our non-executive Chairman of the Board, Ms. Fretz will receive additional director compensation of $125,000 per year that will be pro-rated based upon the number of days Ms. Fretz serves as our Chairman of the Board and is payable half in restricted common units and half in cash.

Item 12.    Security Ownership of Certain Beneficial Owners and Management.

        The following table sets forth the beneficial ownership of our units by:

    each person known by us to be a beneficial owner of more than 5% of our outstanding units;

    each of our directors;

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    each of our named executive officers; and

    all of our directors and executive officers as a group.

        The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

Name of Beneficial Owner
  Common Units
Beneficially
Owned
  Percentage of
Common Units
Beneficially
Owned
  Subordinated
Units
Beneficially
Owned
  Percentage of
Subordinated
Units
Beneficially
Owned
  Percentage of
Total Common
and
Subordinated
Units
Beneficially
Owned
 

Niska Sponsor Holdings Cooperatief U.A.(1)

    16,304,745     48.2 %   33,804,745     100 %   74.1 %

David Pope

                     

Simon Dupéré

                     

Vance E. Powers

    1,000     *             *  

Rick Staples

                     

Jason Dubchak

                     

Jason Kulsky

                     

Darin Olson

                     

Paul Amirault

                     

Deborah M. Fretz

    3,980     *             *  

James G. Jackson

                     

E. Bartow Jones

                     

Stephen C. Muther

    3,480     *             *  

George A. O'Brien

                     

William Shea, Jr. 

                     

Andrew Ward

                     

All directors and executive officers as a group (fifteen persons)

    8,460     *             *  

*
Less than 1%

(1)
The equity interests in Holdco are indirectly owned by our executive officers, certain of our employees and investment limited partnerships affiliated with the Carlyle/Riverstone Global Energy and Power Fund II, L.P. and Carlyle/Riverstone Global Energy and Power Fund III, L.P. C/R Energy GP III, LLC exercises investment discretion and control over the units held by Holdco through Carlyle/Riverstone Energy Partners III, L.P., of which C/R Energy GP III, LLC is the sole general partner. C/R Energy GP III, LLC is managed by an eight person management committee. The address of Holdco and C/R Energy GP III, LLC is 712 Fifth Avenue, 51st Floor, New York, NY 10019.

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Item 13.    Certain Relationships and Related Transactions, and Director Independence.

Certain Relationships and Related Party Transactions

        Holdco owns 16,304,745 common units and 33,804,745 subordinated units, representing approximately 74.1% of our units and the incentive distribution rights. In addition, our manager owns a 2% managing member interest in us.

    Agreements with Affiliates

        During the year ended March 31, 2011, we entered into various agreements that effected our formation transactions, including the transfer of assets to, and the assumption of liabilities by, us and our subsidiaries. These agreements were not the result of arm's-length negotiations and the terms of these agreements were not necessarily at least as favorable to the parties to these agreements as the terms which could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with our formation transactions, including the expenses associated with transferring assets to our subsidiaries were paid from the proceeds of our IPO.

    Services Agreement

        On March 5, 2010, our subsidiary, AECO Partnership, entered into a services agreement with certain affiliates of Holdco pursuant to which it would provide employees to manage certain development projects for Holdco or its affiliates in return for a service fee that is to be agreed upon between the parties from time to time. AECO Partnership subsequently assigned its rights and obligations under the services agreement to Niska Gas Storage Management ULC. The initial term of the services agreement expired on March 31, 2011, at which point it was automatically renewed for an additional one-year term. The current term will expire on March 31, 2012, at which point it will automatically renew for an additional one-year term unless it is terminated.

    Registration Rights Agreement

        Under our Operating Agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other company securities proposed to be sold by our manager or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our manager. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.

        In addition, we have entered into a registration rights agreement with Holdco. A copy of the form of registration rights agreement is filed as an exhibit to this report and is incorporated herein by reference. Pursuant to the registration rights agreement, we will be required to file a registration statement to register the common units and subordinated units issued to Holdco and the common units issuable upon the conversion of the subordinated units upon request of Holdco. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates of Holdco and, in certain circumstances, to third parties.

Policies Relating to Conflicts of Interest

        Conflicts of interest exist and may arise in the future as a result of the relationships between our manager and its affiliates (including Holdco), on the one hand, and us and our unaffiliated members, on the other hand. Our directors and officers have fiduciary duties to manage our manager in a manner beneficial to its owners. At the same time, our manager has a fiduciary duty to manage us in a manner beneficial to our unitholders. Our Operating Agreement contains provisions that specifically

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define our manager's fiduciary duties to the unitholders. Our Operating Agreement also specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Limited Liability Company Act, which we refer to as the Delaware Act, provides that Delaware limited liability companies may, in their Operating Agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a manager to members and us.

        Under our Operating Agreement, whenever a conflict arises between our manager or its affiliates, on the one hand, and us or any unaffiliated member or our board as our manager's delegate, on the other, our manager will resolve that conflict. Our manager has delegated this responsibility, along with the power to conduct our business, to our board. Our board may, but is not required to, seek the approval of such resolution from the conflicts committee of our board. An independent third party is not required to evaluate the fairness of the resolution.

        Whenever a potential conflict of interest exists or arises between the manager or any of its affiliates, on the one hand, and us or any of our members, on the other, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all our members, and shall not constitute a breach of our Operating Agreement, of any agreement contemplated, or of any duty if the resolution or course of action in respect of such conflict of interest is:

    approved by the conflicts committee of our board, although our board is not obligated to seek such approval;

    approved by the vote of a majority of the outstanding common units, excluding any common units owned by our manager or any of its affiliates;

    on terms no less favorable to us than those generally being provided to or available from unaffiliated third parties; or

    fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

        If our board does not seek approval from the conflicts committee and determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, our board acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our Operating Agreement, our board or the conflicts committee of our board may consider any factors it determines in good faith to consider when resolving a conflict. When our Operating Agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of us, unless the context otherwise requires. See "Management" for information about the conflicts committee of our board.

        The transactions described above under "—Agreements With Affiliates" were described in our registration statement relating to our IPO and deemed approved by all our members under the terms of our Operating Agreement.

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Item 14.    Principal Accounting Fees and Services.

        The following table presents fees for professional services rendered by KPMG LLP for 2011, 2010 and 2009:

 
  Niska   Niska Predecessor  
 
  Year Ended March 31,  
 
  2011   2010   2009  

Audit Fees(1)

  $ 1,370,401   $ 1,970,000   $ 410,000  

Tax Fees(2)

    43,465     30,786      
               
 

Total

  $ 1,413,867   $ 2,000,786   $ 410,000  
               

(1)
Expenditures classified as "Audit fees" above include those related to KPMG USA and KPMG Canada's audit of our consolidated financial statements and work performed in connection with our IPO by KPMG Canada.

(2)
"Tax fees" are related to general tax advisory services provided by KPMG Canada.

        Our audit committee has adopted an audit committee charter, which is available on our website, which requires the audit committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The audit committee does not delegate its pre-approval responsibilities to management or to an individual member of the audit committee.


PART IV

Item 15.    Exhibits, Financial Statement Schedules.

(a) (1)    Financial Statements

        See "Index to the Consolidated Financial Statements" set forth on Page F-1.

(2)
Financial Statement Schedules

        All schedules are omitted because they are not applicable or the required information is presented in the financial statements or notes thereto.

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(3)
Exhibits


EXHIBIT LIST

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     Niska Gas Storage Partners LLC 2010 Long-Term Incentive Plan effective as of May 16, 2010 (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K filed on May 19, 2010)
              
  10.2       Contribution, Assignment and Assumption Agreement dated as of May 17, 2010 (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K filed on May 12, 2010)
              
  10.3       Credit Agreement dated as of March 5, 2010 among Niska Gas Storage US, LLC, as US Borrower, and AECO Gas Storage Partnership, as Canadian Borrower, Niska GS Holdings I, L.P., Niska GS Holdings II, L.P., Royal Bank of Canada, as Administrative Agent and Collateral Agent and the other lenders party thereto (incorporated by reference to exhibit 10.4 Amendment No. 1 to the Company's registration statement on Form S-1 (Registration No. 333-165007), filed on March 29, 2010)
              
  10.4       Indenture dated as of March 5, 2010 among Niska Gas Storage US, LLC, Niska Gas Storage US Finance Corp., Niska Gas Storage Canada ULC and Niska Gas Storage Canada Finance Corp., as issuers, each of the Guarantors party thereto, and The Bank of New York Mellon, as Trustee (incorporated by reference to exhibit 10.5 Amendment No. 1 to the Company's registration statement on Form S-1 (Registration No. 333-165007), filed on March 29, 2010)
              
  10.5     Executive Employment Agreement of David Pope dated August 20, 2006 (incorporated by reference to exhibit 10.8 Amendment No. 1 to the Company's registration statement on Form S-1 (Registration No. 333-165007), filed on March 29, 2010)
              
  10.6     Amendment to Executive Employment Agreement of David Pope dated March 1, 2009 (incorporated by reference to exhibit 10.9 Amendment No. 1 to the Company's registration statement on Form S-1 (Registration No. 333-165007), filed on March 29, 2010)
              
  10.7       Registration Rights Agreement between Niska Gas Storage Partners LLC and Niska Sponsor Holdings Coöperatief U.A. dated May 17, 2010 (incorporated by reference to exhibit 10.2 of the Company's Current Report on Form 8-K filed on May 19, 2010)
              
  10.8       Services Agreement dated March 5, 2010 among AECO Gas Storage Partnership, Niska GS Holdings US, L.P. and Niska GS Holdings Canada, L.P. (incorporated by reference to exhibit 10.3 to Amendment No. 1 to the Company's registration statement on Form S-1 (Registration No. 333-165007), filed on March 29, 2010)
              
  12.1 *     Statement regarding computation of ratios
 
         

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Exhibit
Number
   
  Description
  21.1       List of Subsidiaries of Niska Gas Storage Partners LLC (incorporated by reference to exhibit 21.1 to Amendment No. 1 to the Company's registration statement on Form S-1 (Registration No. 333-165007), 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

*
Filed herewith.

Management contract or compensatory plan or arrangement required to be filed as an exhibit to this 10-K pursuant to Item 15(b).

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SIGNATURES

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

    NISKA GAS STORAGE PARTNERS LLC

 

 

By:

 

/s/ DAVID F. POPE

David F. Pope
President, Chief Executive Officer and Director

Date: June 14, 2011

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature
 
Title
 
Date

 

 

 

 

 
/s/ DAVID F. POPE

David F. Pope
  President, Chief Executive Officer and Director (Principal Executive Officer)   June 14, 2011

/s/ VANCE E. POWERS

Vance E. Powers

 

Chief Financial Officer (Principal Financial and Accounting Officer)

 

June 14, 2011

/s/ DEBORAH M. FRETZ

Deborah M. Fretz

 

Director

 

June 14, 2011

/s/ JAMES G. JACKSON

James G. Jackson

 

Director

 

June 14, 2011

/s/ E. BARTOW JONES

E. Bartow Jones

 

Director

 

June 14, 2011

/s/ STEPHEN C. MUTHER

Stephen C. Muther

 

Director

 

June 14, 2011

/s/ GEORGE A. O'BRIEN

George A. O'Brien

 

Director

 

June 14, 2011

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Signature
 
Title
 
Date

 

 

 

 

 
/s/ WILLIAM H. SHEA, JR.

William H. Shea, Jr.
  Director   June 14, 2011

/s/ ANDREW W. WARD

Andrew W. Ward

 

Director

 

June 14, 2011

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INDEX TO FINANCIAL STATEMENTS

NISKA GAS STORAGE PARTNERS LLC FINANCIAL STATEMENTS

   
 

Management's Report On Internal Control Over Financial Reporting

  F-2
 

Report of Independent Registered Public Accounting Firm On Internal Control Over Financial Reporting

  F-3
 

Report of Independent Registered Public Accounting Firm for the Year Ended March 31, 2011

  F-4
 

Report of Independent Registered Public Accounting Firm for the Years Ended March 31, 2010 and 2009

  F-5
 

Consolidated Statements of Earnings and Comprehensive Income for the Years Ended March 31, 2011, 2010 and 2009

  F-6
 

Consolidated Balance Sheets as of March 31, 2011 and 2010

  F-7
 

Consolidated Statements of Cash Flows for the Years Ended March 31, 2011, 2010 and 2009

  F-8
 

Consolidated Statements of Members' Equity for the Years Ended March 31, 2011, 2010 and 2009

  F-9
 

Notes to Consolidated Financial Statements

  F-10

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

        Management of Niska Gas Storage Partners LLC ("Niska Partners") is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company's internal control over financial reporting includes those policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        Management evaluated Niska Partners' internal control over financial reporting as of Match 31, 2011. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework ("COSO"). As a result of this assessment and based on the criteria in the COSO framework, management has concluded that, as of March 31, 2011, Niska Partners' internal control over financial reporting was effective.

        Niska Partners' independent registered public accounting firm, KPMG LLP, has audited the internal control over financial reporting. Their opinion on the effectiveness of Niska Partners' internal control over financial reporting appears herein.

Date: June 14, 2011

/s/ DAVID F. POPE

David F. Pope
President, Chief Executive Officer and Director
  /s/ VANCE E. POWERS

Vance E. Powers
Chief Financial Officer

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors
Niska Gas Storage Partners LLC:

        We have audited Niska Gas Storage Partners LLC's (the "Company") internal control over financial reporting as of March 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of March 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by COSO.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Niska Gas Storage Partners LLC as of March 31, 2011, and the related consolidated statements of earnings and comprehensive income, partners' equity, and cash flows for the year then ended March 31, 2011, and our report dated June 10, 2011 expressed an unqualified opinion on those consolidated financial statements.

(signed) KPMG LLP

Houston, Texas
June 14, 2011

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors
Niska Gas Storage Partners LLC:

        We have audited the accompanying consolidated balance sheet of Niska Gas Storage Partners LLC (the "Company") as of March 31, 2011, and the related consolidated statements of earnings and comprehensive income, partners' equity, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of March 31, 2011, and the results of its operations and its cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of March 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)"), and our report dated June 14, 2011 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

        As discussed in Note 2 to the consolidated financial statements, the balance sheet, and the related statements of earnings and comprehensive income, partners' equity, and cash flows prior to May 17, 2010 have been prepared on a combined basis of accounting.

(signed) KPMG LLP

Houston, Texas
June 14, 2011

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors
Niska Gas Storage Partners LLC:

        We have audited the accompanying combined balance sheets of Niska GS Holdings I LP and Niska GS Holdings II LP ("Niska 'Predecessor") as of March 31, 2010, and the related combined statements of earnings, comprehensive income and retained earnings, cash flows and partners' equity for each of the years in the two-year period ended March 31, 2010. These combined financial statements are the responsibility of Niska Predecessor's management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the combined financial statements referred to above present fairly, in all material respects, the combined financial position of Niska Predecessor as of March 31, 2010, and the combined results of its operations and its combined cash flows for each of the years in the two-year period ended March 31, 2010, in conformity with U.S generally accepted accounting principles.

(signed) KPMG LLP

Chartered Accountants
Calgary, Canada
June 24, 2010

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Niska Gas Storage Partners LLC

Consolidated Statement of Earnings and Comprehensive Income

(Thousands of U.S. dollars)

 
  Year ended March 31,  
 
  2011   2010   2009  
 
   
  (Niska Predeceesor)
 

REVENUES

                   

Long-term contract revenue

  $ 119,566   $ 109,795   $ 110,730  

Short-term contract revenue

    40,972     58,375     52,040  

Optimization, net (Note 13)

    69,537     102,335     89,411  
               

    230,075     270,505     252,181  

EXPENSES (INCOME)

                   

Operating

    44,772     38,153     45,412  

General and administrative

    34,568     36,640     24,182  

Depreciation and amortization (Notes 4, 5 and 6)

    46,891     43,062     54,750  

Impairment of goodwill (Note 5)

            21,962  

Interest (Note 14)

    77,007     38,119     53,486  

Foreign exchange gains

    (518 )   (7,189 )   (25,843 )

Other (income) expense (Note 15)

    (48 )   571     (18,717 )
               

EARNINGS BEFORE INCOME TAXES

    27,403     121,149     96,949  
               

Income tax expense (benefit) (Note 9)

                   
 

Current

    1,213     1,344     314  
 

Deferred

    (31,267 )   66,596     (12,185 )
               

    (30,054 )   67,940     (11,871 )
               

NET EARNINGS AND COMPREHENSIVE INCOME

    57,457   $ 53,209   $ 108,820  
                 

Less:

                   

Net earnings prior to initial public offering on May 17, 2010

  $ 36,234              
                   

Net earnings subsequent to initial public offering on May 17, 2010

  $ 21,223              
                   

Net earnings subsequent to initial public offering allocated to:

                   
 

Managing Member

  $ 901              
                   
 

Common unitholders

  $ 10,161              
                   
 

Subordinated unitholder

  $ 10,161              
                   

Earnings per unit allocated to common unitholders

                   
 

—basic and diluted

  $ 0.31              
                   

Earnings per unit allocated to subordinated unitholder

                   
 

—basic and diluted

  $ 0.31              
                   

(See notes to the consolidated financial statements)

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Niska Gas Storage Partners LLC

Consolidated Balance Sheets

(Thousands of U.S. dollars)

 
  As at March 31,  
 
  2011   2010