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As filed with the Securities and Exchange Commission on February 22, 2010

Registration No. 333-          

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

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FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

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

2780 West Liberty Road
Gridley, CA 95948
(530) 846-7350
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

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Jason A. Dubchak
2780 West Liberty Road
Gridley, CA 95948
(530) 846-7350
(Name, address, including zip code, and telephone number, including area code, of agent for service)

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Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.

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          If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.    o

          If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

          If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

          If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

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

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CALCULATION OF REGISTRATION FEE

(1)

Includes common units issuable upon exercise of the underwriters' option to purchase additional common units.

(2)

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) of the Securities Act of 1933.

          The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated February 19, 2010

PRELIMINARY PROSPECTUS

Niska Gas Storage Partners LLC

17,500,000 Common Units

Representing Limited Liability Company Interests

         We are offering to sell 17,500,000 common units representing limited liability company interests in Niska Gas Storage Partners LLC. This is the initial public offering of our common units. We currently estimate that the initial public offering price will be between $            and $            per common unit. Prior to this offering, there has been no public market for our common units. We intend to apply to list our common units on the New York Stock Exchange under the symbol "NKA."

         Investing in our common units involves risks. See "Risk Factors" beginning on page 19.

         These risks include the following:

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



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Niska Sponsor Holdings Cooperatief U.A., which we refer to as Holdco, controls our manager, which has sole responsibility for conducting our business and managing our operations. 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.



•

Affiliates of our manager 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, which could limit our commercial activities or our ability to acquire additional assets or businesses.



•

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



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



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You will experience immediate and substantial dilution of $            in our pro forma tangible net book value per common unit.



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You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

         We have granted the underwriters a 30-day option to purchase up to an additional 2,625,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 17,500,000 common units in this offering.

         Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

         The underwriters expect to deliver the common units on or about                        , 2010.

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                        , 2010

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        You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with additional or different information. We and the underwriters are offering to sell, and seeking offers to buy, our common units only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of our common units.

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PROSPECTUS SUMMARY

        This summary highlights information contained elsewhere in this prospectus. It does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including "Risk Factors" beginning on page 19 and the historical and pro forma financial statements and the notes to those financial statements included elsewhere in this prospectus. Unless indicated otherwise, the information presented in this prospectus assumes (1) an initial public offering price of $20.00 per common unit and (2) that the underwriters do not exercise their option to purchase additional common units.

        References in this prospectus 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 are being contributed to Niska Gas Storage Partners LLC in connection with this offering. 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 in this prospectus 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. We include a glossary of some of the terms used in this prospectus as Appendix B. Unless otherwise indicated, all references to "dollars" and "$" in this prospectus are to, and amounts are presented in, U.S. dollars. Unless otherwise indicated, references to storage capacity refer to effective working gas storage capacity.

Niska Gas Storage Partners LLC

Overview

        We are the largest independent owner and operator of natural gas storage assets in North America. We own or contract for approximately 185.5 billion cubic feet, or Bcf, of total gas storage capacity. We own the AECO Hub™, which is comprised of two facilities in Alberta, Canada and has approximately 135.0 Bcf of gas storage capacity. In addition, we own the Wild Goose storage facility in northern California with 29.0 Bcf of storage capacity and the Salt Plains storage facility in Oklahoma with 13.0 Bcf of storage capacity. 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, at cost-of-service based rates that are currently below market rates. 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 organically added 41.3 Bcf of gas storage capacity through expansions, an increase of approximately 29%, at a total cost of approximately $131.0 million (an average of $3.2 million per Bcf).

        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. We believe that our combination of large, high-quality, strategically located storage facilities, access to economically attractive organic growth opportunities, ability to charge market-based rates and an experienced and complete storage business team makes our business difficult to replicate.

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        We believe that our relationship with Niska Sponsor Holdings Cooperatief U.A., or Holdco, and Riverstone Holdings LLC through its affiliation with the Carlyle/Riverstone Funds will enhance our ability to grow our asset base and cash flow. As the owner of our manager,                                     of our common units, all of our subordinated units and all of our incentive distribution rights, Holdco is incentivized to promote and support the successful execution of our business plan and may offer us development projects in the future, although it is not required to do so.

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 our inception on May 12, 2006 to March 31, 2009, we utilized an average of approximately 92% of our operated capacity for storage services provided to third-party customers, and third-party storage services contributed an average of 68% of our total revenue.

        We provide multi-year, multi-cycle storage services to our customers under long-term firm reserved storage contracts, or LTF contracts. The volume-weighted average life of our LTF contracts at December 31, 2009 was 3.3 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. From inception to March 31, 2009, we utilized an average of approximately 78% of our operated capacity for our LTF strategy, and LTF contracts contributed an average of 50% of our total revenue.

        In addition, we provide services for customers under short-term firm fixed-nomination contracts, or 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 margins as spot and future natural gas prices fluctuate prior to that activity date. From inception to March 31, 2009, we utilized an average of approximately 14% of our operated capacity for our STF strategy, and STF contracts contributed an average of 18% of our total revenue.

        Because many contracts extend beyond the end of a fiscal year and because we generally enter into new or replacement third-party storage contracts several months in advance of the beginning of each fiscal year, we can accurately predict a baseline of revenue and cash flow at the beginning of each fiscal year that we will generate for that year under our third-party storage contracts. Throughout the year, as market conditions allow, we augment this baseline revenue and cash flow by entering into additional STF contracts.

Proprietary Optimization

        We purchase, store and sell natural gas for our own account in order to utilize, or optimize, our 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 on a short-term basis. We refer to this as our proprietary optimization strategy. We have a stringent risk policy that limits, among other

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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, 2009, we utilized an average of approximately 8% of our operated capacity for our proprietary optimization strategy, and proprietary optimization revenue, after deducting cost of goods sold, contributed an average of 32% of our total revenue.

        A baseline level of revenue is locked-in with proprietary optimization transactions entered into in advance of, or early in, each fiscal year. We add incremental margins throughout the year by entering into additional transactions when market conditions are favorable.

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 90% of the counterparties under our gas storage contracts and proprietary 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.

Our Assets

        Our owned and operated gas storage facilities consist of AECO Hub™ in Alberta, Canada, our Wild Goose storage facility in northern 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 storage capacity from NGPL on its pipeline system in the mid-continent. The following table highlights certain important design information about our assets.

AECO Hub™

        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

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capacity (2.8 Bcf per day and 3.1 Bcf per day, respectively), AECO Hub™ has supported customer contracts with cycling service of up to 5.2 times per year. AECO Hub™ is the largest natural gas storage provider in western Canada and the largest independent storage hub in North America. 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." Its location on TransCanada Pipeline's Alberta System with direct access to 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 liquidity.

Wild Goose

        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, with an average physical cycling capability of 2.5 cycles per year. In the past, Wild Goose has supported customer contracts with cycling service as high as 6.0 times per year. 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 provides its services at the Pacific Gas & Electric, or PG&E, citygate, a liquid trading point where gas supply from multiple upstream supply basins meets the volatile California end-use gas demands, which creates a dependence on natural gas storage.

Salt Plains

        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 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.

NGPL Contracted Capacity

        Since 2001, our subsidiary has contracted for 8.5 Bcf of gas storage capacity on two legs of the NGPL 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. markets. NGPL is regulated by the Federal Energy Regulatory Commission, or FERC, and is limited to charging cost-of-service based rates for its capacity. Currently, this cost-of-service rate we pay is significantly below the market value of the capacity. Our long-term contracts for NGPL capacity allow us to use the capacity for proprietary optimization. We have a tariff-based right of first refusal to renew these contracts at NGPL's cost-of-service rate, effectively making this capacity a long-term asset without any invested capital, with an option to exit should the cost-of-service ever be above market value.

Business Strategies

        Our primary objective is to generate stable cash flows sufficient to make the minimum quarterly cash distribution per unit to our unitholders and to increase our cash distributions per unit over time by executing the following strategies:

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Maintaining a flexible portfolio of commercial strategies to optimize profitability.  We strive to enhance our returns through a flexible storage utilization strategy that mixes LTF contracts, STF contracts and proprietary optimization transactions to capture the value of natural gas storage. LTF contracts allow us to collect fees based on the seasonal spread and the option value that customers are willing to pay for gas storage, which is partially a function of volatility or expected

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volatility in the price of natural gas. STF contracts and proprietary optimization transactions allow us to profit directly from both the seasonal spread and other opportunities that unfold throughout the year. Initial STF contracts and proprietary optimization transactions are entered into in advance of the beginning of each fiscal year, allowing us to lock-in significant revenues at the beginning of each fiscal year. Additional STF contracts and proprietary optimization transactions are entered into throughout the year to lock-in incremental margins from changes in relative prices of natural gas. We have historically contracted and expect to continue to target contracting 80% to 90% of our gas storage capacity under multi-year LTF contracts and STF contracts with third party storage customers and utilize the balance for proprietary optimization transactions. The gradual expiration of LTF contracts and the short-term duration of STF contracts and proprietary optimization transactions affords us the flexibility to adjust the mix of strategies as necessary to capitalize on market conditions.

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Continuing to expand our existing facilities.  We intend to enhance our profitability and to increase our cash distributions through organic growth at our existing facilities. Since our inception in 2006, we have increased our gas storage capacity by 41.3 Bcf, or approximately 29%, through capital expenditures of approximately $131.0 million. We have near-term projects in progress to expand our existing facilities by an additional 39.0 Bcf, or 21%, with an 18.0 Bcf expansion at AECO Hub™ and a 21.0 Bcf expansion at Wild Goose. We expect that these projects will increase our total working gas capacity by approximately 15.0 Bcf by March 31, 2011, 27.0 Bcf by March 31, 2012, 37.0 Bcf by March 31, 2013 and 39.0 Bcf by March 31, 2014 at a total cost of approximately $175.0 million.



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Growing through acquisitions of complementary assets and pursuing new and existing development projects.  We intend to pursue accretive acquisitions and new and existing opportunities to develop assets that will enable us to increase our cash distributions to unitholders. We intend to seek acquisition and development opportunities in new regions that will provide geographic diversification and in our existing regions where we believe we will be able to realize synergies and operational efficiencies.

Competitive Strengths

        We believe that we are well-positioned to successfully achieve our primary business objectives and execute our business strategies based upon the following competitive strengths:

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High quality, strategically-located assets.  Our facilities are modern, well-maintained and automated and utilize depleted natural gas reservoirs that have optimal storage characteristics. The high injection and withdrawal capabilities of our facilities and their location at strategic points along key North American natural gas pipeline networks provides us and our customers with a high degree of liquidity and opportunities for arbitrage between major natural gas producing and consuming regions. The quality and location of our facilities has helped us to develop our strong reputation for reliability and allowed us to build a base of loyal customers—approximately half of our current customers have been customers of our facilities for at least five years. Additionally, each of our facilities operates in a regulatory jurisdiction that affords us substantial flexibility in pursuing commercial strategies.



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Flexible commercial strategies provide relatively stable and predictable cash flows.  Our assets have generated consistent Adjusted EBITDA over the past three fiscal years despite materially different seasonal spreads available at the start of each of those years. Our proven, flexible commercial strategy allows us to adjust our mix of LTF contracts, STF contracts and proprietary optimization transactions, which have demonstrated to be complementary strategies and enable us to maintain or increase our profitability in diverse market environments. A significant portion of our revenue is generated from gas storage contracts continuing from prior years or new

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contracts that are entered into several months in advance of the beginning of each fiscal year, generating a predictable baseline cash flow.

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Inventory of successful and repeatable expansion projects.  Since our inception in 2006, we have successfully expanded our gas storage capacity organically from 144.2 Bcf to 185.5 Bcf (an increase of 41.3 Bcf, or 29%) through cost-efficient techniques. We are currently applying these proven techniques to further expand our capacity at AECO Hub™ and Wild Goose. At Wild Goose, there are also additional reservoirs similar to the ones that we currently operate that can be developed, if market conditions are favorable, at relatively low costs. We believe the presence of additional opportunities for low-risk growth at each of our operated facilities is a significant competitive advantage.



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Significant barriers to entry.  Many of our competitors seeking to add substantial capacity in the markets where we operate may face significant geographical, marketing, financial, regulatory and logistical difficulties. In particular, there is a scarcity of unexploited reservoirs located near pipeline infrastructure, natural gas supply sources and end-user markets that have the capacity and lithology, or physical rock-formation characteristics, necessary to store gas economically.



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Experienced management and complete storage business team.  We employ one of the natural gas storage industry's most experienced management teams (with an average of over 20 years of experience in the natural gas industry). We are staffed with a comprehensive, in-house team of geologists, reservoir engineers, risk managers, optimizers, marketers, schedulers, accountants, lawyers and regulatory specialists with extensive expertise in natural gas storage operations and development. Because we are a user of natural gas storage through our proprietary optimization strategy, our team has a knowledge of the gas storage industry that many of our competitors do not. Our management team and staff have been involved in the development of approximately 285.0 Bcf of gas storage capacity in North America.

Our Relationship With Holdco

        After this offering, Holdco will own our manager,                                     of our common units, all of our subordinated units and all of our incentive distribution rights. Holdco is pursuing a potential gas storage development project in western Canada and currently holds rights to build a salt-dome cavern gas storage facility in Louisiana and a depleted reservoir in southern Texas. If these projects are developed, Holdco intends to offer us the opportunity to purchase the projects, although it is not obligated to do so.

        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 $13 billion to 65 investments in North America, Latin America, Europe and Asia. Riverstone's management has substantial experience in identifying, evaluating, negotiating and financing acquisitions and investments.

        By providing us with access to strategic guidance, financial expertise and a potential source of new facilities, we believe our relationship with Holdco and the Carlyle/Riverstone Funds will greatly enhance our ability to grow our asset base and cash flow. As the owner of our manager,                                     of our common units, all of our subordinated units and all of our incentive distribution rights, Holdco is incentivized to promote and support the successful execution of our business plan and may offer us development projects in the future although it is not required to do so.

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Formation Transactions

        At or prior to the closing of this offering the following transactions will have occurred:

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Niska GS Holdings U.S., L.P., or US Holdings, will contribute Niska Gas Storage US, LLC, or Niska US, which indirectly owns the Wild Goose and Salt Plains facilities, to us;



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Niska GS Holdings Canada, L.P., or Canada Holdings, will, through a series of steps, contribute Niska Gas Storage Canada ULC, or Niska Canada, which indirectly owns AECO Hub™, to NKA Canada Cooperatief U.A., which will become our wholly-owned subsidiary;



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we will issue                                    common units,                                     subordinated units, a portion of the incentive distribution rights and a portion of the interests that will become a 2% managing member interest in us to US Holdings;



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we will issue                                    common units,                                     subordinated units, a portion of the incentive distribution rights and a portion of the interests that will become a 2% managing member interest in us to Canada Holdings;



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US Holdings and Canada Holdings, collectively referred to as Niska Holdings, will contribute to Holdco the common units, subordinated units, incentive distribution rights and interests that will become a 2% managing member interest in us;



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we will borrow $            million under our anticipated revolving credit facility and will use the proceeds to pay a distribution to Niska Holdings; and



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we will issue 17,500,000 common units to the public in this offering and will use the proceeds of the offering as described in "Use of Proceeds."

        If the underwriters do not exercise their option to purchase additional common units, we will issue 2,625,000 common units to Holdco at the expiration of the option. To the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Holdco. The proceeds from any exercise of the underwriters' option to purchase additional common units will be used to pay a distribution to Holdco.

Contemplated Refinancing Transactions

Expected Non-Public Offerings of Senior Notes by Niska US and Niska Canada

        We expect that Niska Canada and Niska US will undertake non-public offerings of senior notes prior to the closing of this offering. We expect that these offerings will be for approximately $800.0 million aggregate principal amount of senior notes. We expect that the senior notes will be sold in offerings exempt from registration under the Securities Act and will be offered only 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.

Expected New Revolving Credit Facility

        Concurrently with the closing of the expected non-public offerings of senior notes, we expect that we will terminate our existing credit agreement and enter into a new secured credit agreement. We expect this new credit agreement to provide for a revolving credit facility, with a borrowing capacity of $400.0 million. We expect that the availability under our revolving credit facility will be subject to a borrowing base which will be redetermined from time to time and be based primarily on our receivables and our economically hedged inventory of proprietary gas. We anticipate that we may borrow only up to the level of our then current borrowing base. We expect that our initial borrowing base will be approximately $            million.

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Management

        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 will direct the management of our business. Upon the closing of this offering, our board will have six members. Our manager intends to increase the size of our board to eight members following the closing of this offering. Our manager will appoint all members to our board and we expect that, when the size of our board increases to eight directors, at least three of those directors will be independent as defined under the independence standards established by the New York Stock Exchange, or the NYSE. For more information about our directors, see "Management—Directors and Executive Officers."

Ownership of Niska Gas Storage Partners LLC

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(a)

Assumes the underwriters do not exercise their option to purchase additional common units. If the underwriters do not exercise their option to purchase additional common units, we will issue 2,625,000 common units to Holdco at the expiration of the option. If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Holdco. Accordingly, the exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.

(b)

Incentive distribution rights represent a potentially variable interest in distributions and thus are not expressed as a fixed percentage.

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        The following diagram depicts our simplified organizational and ownership structure after giving effect to this offering.

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Principal Executive Offices and Internet Address

        Our principal executive offices are located at 2780 West Liberty Road Gridley, CA 95948, and our telephone number is (530) 846-7350. Our website will be located at                                    and will be activated following the closing of this offering. We will make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or the SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Fiduciary Duties

        Our manager has a legal duty to manage us in a manner beneficial to our members, and this duty will apply to our board as delegate of our manager. This legal duty originates in statutes and judicial decisions and is commonly referred to as a "fiduciary duty." However, because our manager is wholly-owned by Holdco, our officers and directors have fiduciary duties to manage our business in a manner beneficial to Holdco. As a result of this relationship, conflicts of interest may arise in the future between us or holders of our common units, on the one hand, and our manager and its affiliates, on the other hand. For a more detailed description of the conflicts of interest and fiduciary duties of our manager and board, see "Risk Factors—Risks Inherent in an Investment in Us" and "Conflicts of Interest and Fiduciary Duties—Conflicts of Interest."

        Our Operating Agreement limits the liability and reduces the fiduciary duties of our manager and board to holders of our common units. Our Operating Agreement also restricts the remedies available to holders of our common units for actions that might otherwise constitute breaches of our manager's or board fiduciary duties owed to holders of our common units. Our Operating Agreement also provides that affiliates of our manager, including Holdco and its other subsidiaries and affiliates, are not restricted from competing with us. By purchasing a common unit, you are consenting to various limitations on fiduciary duties contained in our Operating Agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable law. See "Conflicts of Interest and Fiduciary Duties—Fiduciary Duties" for a description of the fiduciary duties imposed on our manager and board by Delaware law, the material modifications of these duties contained in our Operating Agreement and certain legal rights and remedies available to holders of our common units.

        For a description of our other relationships with our affiliates, see "Certain Relationships and Related Party Transactions."

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The Offering

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Summary Historical and Pro Forma Financial and Operating Data

        We were formed on January 27, 2010 and do not have our own historical financial statements for periods prior to our formation. Therefore, we present the financial statements of Niska Predecessor, consisting of the combined financial statements of Niska Predecessor. 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 step of the transaction, which closed on November 16, 2006, Niska Predecessor acquired Wild Goose. Prior to the closing of this offering, Niska Holdings will contribute substantially all of its assets to us. The following table presents summary historical combined financial and operating data of Niska Predecessor and summary pro forma financial and operating data of Niska Gas Storage Partners LLC as of the dates and for the periods indicated.

        Financial information for periods prior to May 12, 2006 and for Wild Goose for periods prior to November 16, 2006 is not presented. See "Selected Historical and Pro Forma Financial Operating Data."

        The historical combined financial data presented for the years ended March 31, 2008 and 2009, the nine months ended December 31, 2009 and the period from May 12, 2006 to March 31, 2007 is derived from, and should be read together with and is qualified in its entirety by reference to, the historical audited combined financial statements and the accompanying notes included elsewhere in this prospectus. The historical combined financial data presented for the nine months ended December 31, 2008 is derived from, and should be read together with and is qualified in its entirety by reference to, the historical unaudited combined financial statements and the accompanying notes included elsewhere in this prospectus. Moreover, the table should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations."

        Our summary pro forma statement of operations data for the nine months ended December 31, 2009 and summary pro forma balance sheet data as of December 31, 2009 are derived from the unaudited pro forma combined financial statements of Niska Gas Storage Partners LLC included elsewhere in this prospectus. The pro forma adjustments have been prepared as if the expected non-public offerings of senior notes by Niska Canada and Niska US, this offering and the transactions to be effected at the closing of this offering had taken place on December 31, 2009, in the case of the pro forma balance sheet, and on April 1, 2009, in the case of the pro forma statement of operations. A more complete explanation of the pro forma data can be found in our unaudited pro forma combined financial statements.

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        The following table includes the non-GAAP financial measure of Adjusted EBITDA. For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, see "—Non-GAAP Financial Measure" below.

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Non-GAAP Financial Measure

Adjusted EBITDA

        We use the non-GAAP financial measure Adjusted EBITDA in this prospectus. A reconciliation of Adjusted EBITDA to its most directly comparable financial measure as calculated and presented in accordance with GAAP is shown below.

        We define Adjusted EBITDA as net income 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. 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 nature to the traditional adjustments to net income 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 income. The non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA 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 income and is defined differently by different companies, our

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definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

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RISK FACTORS

        Investing in our common units involves substantial risks. Common units are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

        If any of the following risks were actually to occur, our business, financial condition, results of operations and ability to pay distributions to our members could be materially adversely affected. Additional risks and uncertainties not currently known to us or that we currently consider to be immaterial may also materially adversely affect our business, financial condition, results of operations and ability to pay distributions to our members. In either case, we might not be able to make distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment in our common units.

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 $            per unit, or $            per unit per year, which will require cash of approximately $25.3 million per quarter, or $101.3 million per year, based on the number of common and subordinated units to be outstanding after the completion of this offering. 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, which 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;



•

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, some of which are beyond our control, 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;



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fluctuations in our working capital needs;



•

our ability to borrow funds and access capital markets;



•

restrictions on distributions contained in debt agreements;

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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 "Our Cash Distribution Policy and Restrictions on Distributions."

The assumptions underlying our estimate of cash available for distribution included in "Our Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.

        Our estimate of cash available for distribution set forth in "Our Cash Distribution Policy and Restrictions on Distributions" has been prepared by management, and we have not received an opinion or report on it from any independent accountants. If we do not achieve our anticipated results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially. The assumptions underlying our estimate of cash available for distribution are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. For instance, we have estimated that the total capacity of our Wild Goose facility will increase by 6.0 Bcf during the fiscal year ending March 31, 2011. This expansion project, however, is subject to approval by regulatory authorities, which we believe will be granted during the summer of 2010. If we do not receive the required regulatory approval, we estimate that our net revenue and our Adjusted EBITDA for the fiscal year ending March 31, 2011 would decrease by approximately $8.0 million and $6.5 million, respectively.

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 income.

        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 income.

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;



•

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;

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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, 2009, we utilized an average of approximately 78% of our operated capacity for our LTF strategy, representing an average of approximately 50% of annual revenue. The volume-weighted average life of our LTF contracts at December 31, 2009 was 3.3 years. From inception to March 31, 2009, we utilized an average of approximately 14% of our operated capacity for our STF strategy, representing an average of approximately 18% of annual revenue. Over the same period, we utilized an average of approximately 8% of our operated capacity for our proprietary optimization strategy, representing an average of approximately 32% of annual revenue. As of December 31, 2009, approximately 23% of our LTF contracts and all of our STF contracts were due to expire on or before March 31, 2011. 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 California Public Utilities Commission, or 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 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 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

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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:

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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;



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unanticipated equipment failures at our facilities;



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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;



•

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;



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



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operator error; and



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environmental pollution or release of toxic substances.

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        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.

        We expect that Niska Canada and Niska US will undertake non-public offerings of $800.0 million aggregate principal amount of senior notes. In connection with the closing of the expected non-public offerings of senior notes, we expect to enter into a new credit agreement. We expect the new credit agreement will provide for revolving credit facilities for us with combined borrowing capacity of $400.0 million that will be available for general purposes, including working capital, economically hedged inventory purchases and capital expenditures. We expect that we will continue to have the ability to incur additional debt, subject to limitations in our revolving credit facility and the indentures governing our subsidiaries' expected senior notes. 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, regulatory and other factors, some of which are beyond our control. In addition, our ability to service our debt under our credit facility will depend on market interest rates because we anticipate that the

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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 expected credit facility, the indentures governing our subsidiaries' expected 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, we expect our anticipated credit facility and the indentures governing our subsidiaries' expected senior notes will 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;



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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, we expect that our credit facility will contain covenants requiring us to maintain certain financial ratios and tests. 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 facility or the indentures governing our subsidiaries' anticipated 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. Any subsequent replacement of our anticipated credit facility, our subsidiaries' senior notes or any new indebtedness could have similar or greater restrictions. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Expected New Credit Facility" and "—Expected Non-Public Offerings of Senior Notes by Niska US and Niska Canada."

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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.

Unstable market and economic conditions may materially and adversely impact our business.

        Global financial markets and economic conditions have been, and continue to be, experiencing disruption following adverse changes in global capital markets. The debt and equity capital markets are experiencing significant volatility and banks and other commercial lenders have substantially curtailed their lending activities as a result of, among other things, significant write-offs in the financial services sector, the re-pricing of credit risk and current weak economic conditions. These circumstances continue to make it difficult to obtain funding.

        As a result, the cost of raising money in the debt and equity capital markets and commercial credit markets has increased substantially while the availability of funds from those markets has diminished significantly. Many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity—at all or on terms similar to the debt being refinanced—and reduced and in some cases ceased to provide funding to borrowers. In some cases, lenders under existing revolving credit facilities have been unwilling or unable to meet their funding obligations, including one lender under our revolving credit facility. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms or that we will be able to access the full amount of the available commitments under our expected revolving credit facility in the future.

        These circumstances have impacted our business, or may impact our business in a number of ways including but not limited to:

•

limiting the amount of capital available to us to fund new growth capital projects and acquisitions, which would limit our ability to grow our business, take advantage of business opportunities, respond to competitive pressures and increase distributions to our unitholders;



•

adversely affecting our ability to refinance outstanding indebtedness at maturity on favorable or fair terms or at all; and



•

weakening the financial strength of certain of our customers, increasing the credit risk associated with those customers and/or limiting their ability to grow which could affect their ability to pay for our services or prompt them to reduce the volume of natural gas they store in our facilities.

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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 39.0 Bcf, including 15.0 Bcf of capacity expected to become available during the summer of 2010 and an additional 7.0 Bcf of capacity expected to become available during the following fiscal year. 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;



•

we are unable to obtain necessary regulatory and/or government approvals, including approval of the CPUC relating to our application to, among other things, expand Wild Goose's storage capacity by 21.0 Bcf to 50.0 Bcf;



•

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.

Our business depends upon certain key employees who may not continue to work for us.

        We depend on the services and performance of certain executive officers and key employees. We do not maintain key-person insurance for any of these individuals. Our executive officers are not required to dedicate all of their business time to us, and there could be competition for the time and effort of our executive officers who provide services to our manager and its affiliates. The loss of any of these officers or our key employees or their failure to dedicate a sufficient amount of their business time to our business could negatively impact our ability to execute our strategy and adversely affect our business, financial condition, results of operations and ability to pay distributions to our members.

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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 and capital lease 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 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 Alberta Utilities Commission, or 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 recent 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

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this determination, for instance as a result of a complaint in a proceeding, 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. In addition, we have filed applications with the CPUC to, among other things, expand Wild Goose's storage capacity by 21.0 Bcf to 50.0 Bcf. We expect to receive the CPUC's approval during the summer of 2010, but we may not receive the approval at that time or at all.

        Our Salt Plains operations are subject to primary regulation by the Oklahoma Corporation Commission, or the OCC, and are permitted to conduct a limited amount of storage service in interstate commerce under 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;



•

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

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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 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."

The adoption of certain derivatives legislation by Congress, and the imposition of certain new regulations, could have an adverse impact on our ability to hedge risks associated with our business.

        Congress currently is considering legislation that, among other things, may impose new levels of regulation on the over-the-counter derivatives marketplace, which could affect the use of derivatives in hedging transactions. Those proposals are in various stages in the House of Representatives and the Senate and are not sufficiently unified to permit an assessment of which, if any, of the proposals will be enacted by Congress, or whether they would have an impact on our hedging activities. Separately, in mid-January, 2010, the U.S. Commodity Futures Trading Commission, or CFTC, proposed regulations that would impose federal speculative position limits for speculation in some specific futures and option contracts in natural gas, crude oil, heating oil, and gasoline. These proposed regulations would preserve exemptions for many bona fide hedging of commercial risks. Although it is not possible at this time to predict whether or when Congress will act on derivatives legislation or the CFTC will adopt final regulations on the topic, any laws or regulations that subject us to additional capital or margin requirements relating to, or that impose material additional restrictions on, our trading and commodity

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positions, could have an adverse effect on our ability to hedge risks associated with our business or may increase the total cost of our hedging activity.

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. For the nine months ended December 31, 2009, one of our customers accounted for approximately 44% of our gross revenue, and for the fiscal year ended March 31, 2008, two of our customers accounted for approximately 43% of our gross revenue. 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.

Risks Inherent in an Investment in Us

Holdco 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.

        Following this offering, Holdco will own and control our manager. Our manager will appoint all of the members of our board, which will manage and operate 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

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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. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable 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;



•

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 $             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

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•

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

        See "Conflicts of Interest and Fiduciary Duties."

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 will 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. See "Conflicts of Interest and Fiduciary Duties."

Holders of our common units have limited voting rights and are not entitled to elect our manager or our directors, which could reduce the price at which the common units will trade.

        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, will be chosen entirely by our manager. Unlike publicly traded corporations, we will 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 will have little ability to remove our manager. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Upon completion of this offering, we will be a "controlled company" within the meaning of NYSE rules and, as a result, will qualify for, and intend to rely on, exemptions from some of the NYSE listing requirements with respect to independent directors.

        Because Holdco will control more than 50% of the voting power for the election of our directors upon completion of this offering, we will be 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;

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•

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, you may not have the same protections afforded to shareholders of companies that are subject to all of the NYSE corporate governance requirements.

You will experience immediate and substantial dilution of $            in our pro forma tangible net book value per common unit.

        The estimated initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $            per unit. Based on the estimated initial public offering price of $20.00 per unit, you will incur immediate and substantial dilution of $            per common unit. This dilution results primarily because the assets contributed by our manager and its affiliates are recorded at their historical cost, and not their fair value, in accordance with GAAP. See "Dilution."

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;



•

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

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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.

        If you are dissatisfied with the performance of our manager, you will 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. Following the closing of this offering, Holdco will own        % of our outstanding common and subordinated units. Accordingly, our public unitholders are currently unable to remove our manager without Holdco consent because Holdco will own 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 our manager and its 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 your vote or consent.

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.

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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. See "Our Cash Distribution Policy and Restrictions on Distributions."

We may issue additional membership interests without your approval, which would dilute your 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 you to sell your 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, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Our manager is not obligated to obtain a fairness opinion regarding the value of the 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. At the completion of this offering and assuming no exercise of the underwriters' option to purchase additional common units, our manager and its affiliates will own approximately        % 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        % of our outstanding common units. For additional information about this call right, see "The Operating Agreement—Limited Call Right."

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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.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

        Prior to the offering, there has been no public market for the common units. After the offering, there will be only 17,500,000 publicly-traded common units, assuming no exercise of the underwriters' option to purchase additional common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, a lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

        The initial public offering price for the common units has been determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

•

our quarterly distributions;



•

our quarterly or annual earnings or those of other companies in our industry;



•

loss of a large customer;



•

announcements by us or our competitors of significant contracts or acquisitions;



•

changes in accounting standards, policies, guidance, interpretations or principles;



•

general economic conditions;



•

the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;



•

future sales of our common units; and

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•

the other factors described in these "Risk Factors."

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.

        After this offering, we will have            common units and            subordinated units outstanding, which includes the 17,500,000 common units we are selling in this offering that may be resold in the public market immediately. 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. All of the            common units that are issued to Holdco will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of             . Sales by Holdco or other large holders of a substantial number of our common units in the public markets following this offering, 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 have agreed to provide 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. See "Units Eligible for Future Sale."

We will incur increased costs as a result of being a publicly-traded company.

        We have no history operating as a publicly-traded company. As a publicly-traded company we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly-traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our members, we must first pay or reserve cash for our expenses, including the costs of being a public company. As a result, the amount of cash we have available for distribution to our members will be affected by the costs associated with being a public company.

        Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly-traded company, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

        We also expect to incur significant expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board or as executive officers.

        We estimate that we will incur approximately $3.4 million of estimated incremental costs per year associated with being a publicly-traded company; however, it is possible that our actual incremental costs of being a publicly-traded company will be higher than we currently estimate.

We will be exposed to risks relating to evaluations of controls required by Section 404 of the Sarbanes-Oxley Act.

        We are in the process of evaluating our internal controls systems to allow management to report on, and our independent registered public accounting firm to audit, our internal controls over financial reporting. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation

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requirements of Section 404 of the Sarbanes-Oxley Act, and will be required to comply with Section 404 in our annual report for our fiscal year ending March 31,             (subject to any change in applicable SEC rules). Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board, or PCAOB, rules and regulations that remain unremediated. Although we produce our financial statements in accordance with GAAP, our internal accounting controls may not meet all standards applicable to companies with publicly-traded securities. As a publicly-traded company, we will be required to report, among other things, control deficiencies that constitute a "material weakness" or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A "material weakness" is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC or the PCAOB. If we do not implement improvements to our disclosure controls and procedures or to our internal controls in a timely manner, our independent registered public accounting firm may not be able to certify as to the effectiveness of our internal controls over financial reporting pursuant to an audit of our internal controls over financial reporting. This may subject us to adverse regulatory consequences or a loss of confidence in the reliability of our financial statements. We could also suffer a loss of confidence in the reliability of our financial statements if our independent registered public accounting firm reports a material weakness in our internal controls, if we do not develop and maintain effective controls and procedures or if we are otherwise unable to deliver timely and reliable financial information. Any loss of confidence in the reliability of our financial statements or other negative reaction to our failure to develop timely or adequate disclosure controls and procedures or internal controls could result in a decline in the price of our common units. In addition, if we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets and the price of our common units may be adversely affected.

Tax Risks to Common Unitholders

        In addition to reading the following risk factors, you should read "Material U.S. Tax Consequences" and "Material Canadian Federal Income Tax Consequences" for a more complete discussion of the expected material tax consequences of owning and disposing of common units.

We anticipate 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 you would be substantially reduced.

        We anticipate that Niska Gas Storage Partners LLC will be 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. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

        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. Distributions to you would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to you. Because corporate income taxes would be imposed upon us, our cash available for distribution to you would be substantially reduced, likely causing a substantial reduction in the value of

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our common units. For additional discussion regarding the importance of our treatment as a partnership, see "Material U.S. Tax Consequences—Taxation of Niska Gas Storage Partners LLC—Partnership Status."

        Our Operating Agreement provides that the adverse impact of any such additional entity-level taxation will be borne by all members. See "Provisions of Our Operating Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels."

Notwithstanding our treatment for U.S. federal income tax purposes, we will be 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 you could be further reduced.

        Most of our business operations and subsidiaries will be 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 you. 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. For more details, see "Material Canadian Federal Income Tax Consequences—Taxation of Niska Gas Storage Partners LLC." Although these taxes may be properly characterized as foreign income taxes, you may not be able to credit them against your liability for U.S. federal income taxes on your share of our earnings. For more details see "Material U.S. Tax Consequences—U.S. Federal Income Taxation of Unitholders—Foreign Tax Credits."

        Our Operating Agreement provides that the adverse impact of any such additional entity-level taxation will be borne directly or indirectly by all members. See "Provisions of Our Operating Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels."

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 you.

        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 you. 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 forms of taxation. Our Operating Agreement provides that the adverse impact of any such additional entity-level taxation will be borne by all members. See "Provisions of Our Operating Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels."

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

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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 multi national 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 multi national 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 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 you.

        We have not requested a ruling from the IRS or the Canada Revenue Agency with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The tax authorities may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from other 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.

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

        Because our unitholders will be treated as partners for U.S. federal income tax purposes to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your 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 you sell your common units, you will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because for U.S. federal income tax purposes distributions in excess of your allocable share of

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our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you for U.S. federal income tax purposes if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your 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, you may incur a tax liability on the sale of your units in excess of the amount of cash you receive. See "Material U.S. Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss."

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, will be 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 will be required to file U.S. federal tax returns and pay tax on their shares of our taxable income attributable to our U.S. operations. If you are a tax exempt entity (or intend to hold our units through an IRA) or a non-U.S. person, you should consult your tax advisor before investing in our common units. See "Material U.S. Tax Consequences—Non-U.S. Investors" and "Material U.S. Tax Consequences—Tax-Exempt Organizations."

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. 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 will adopt 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 you as a result of your ownership of our units. It also could affect the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. See "Material U.S. Tax Consequences—U.S. Federal Income Taxation of Unitholders—Section 754 Election."

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

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rendered an opinion regarding the validity of our proration method. See "Material U.S. Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."

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 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. See "Material U.S. Tax Consequences—U.S. Federal Income Taxation of Unitholders—Treatment of Short Sales."

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. See "Material U.S. Tax Consequences—Disposition of Common Units—Constructive Termination."

As a result of investing in our common units, you may become 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, you will likely be 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 you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially own assets and conduct business in California and Oklahoma. Each of these states currently imposes a personal income tax on individuals. Many states also imposes 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 your 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.

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USE OF PROCEEDS

        We expect the net proceeds from this offering will be approximately $         million after deducting approximately $         million of underwriting discounts and expenses. We intend to use approximately $         million of the net proceeds of this offering to repay borrowings under the revolving credit facility that we expect to enter into upon the closing of this offering, and the remainder for general company purposes, including to fund a portion of the cost of our expansion projects. Pending such use, we may temporarily pay down indebtedness under our expected revolving credit facility.

        We expect that the amount outstanding under the revolving credit facility as of the closing of this offering will be $             million, with a weighted average interest rate of        %. We expect that the outstanding borrowings under our revolving credit facility will be used to fund a distribution to Holdco or will have been used for working capital borrowings. We expect that our revolving credit facility will have a maturity date of                . We expect that affiliates of the underwriters participating in this offering will be lenders under our revolving credit facility and accordingly, will receive a portion of the proceeds of this offering. Please read "Underwriting—Relationships."

        Our estimates assume an initial public offering price of $20.00 per common unit and no exercise of the underwriters' option to purchase additional common units. An increase or decrease of $1.00 per common unit in the initial public offering price would cause the net proceeds from the offering, after deducting underwriting discounts, to increase or decrease by $17.5 million. If the proceeds increase due to a higher initial public offering price, we will use the additional proceeds to increase the amount of the borrowings in order to increase the distribution to Holdco. If the proceeds decrease due to a lower initial public offering price, we will decrease the amount of the borrowing and correspondingly decrease the distribution to Holdco.

        The proceeds from any exercise of the underwriters' option to purchase additional common units will be used to pay a distribution to Holdco.

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CAPITALIZATION

        The following table shows our cash and cash equivalents and capitalization as of December 31, 2009:

•

on a combined historical basis;



•

as adjusted to give effect to Niska Canada's and Niska US's expected non-public offerings of senior notes and the application of the net proceeds therefrom, the concurrent termination of our existing credit facility and the distribution by Niska Predecessor of certain development projects to one of its affiliates; and



•

as further adjusted to give effect to our formation and related transactions as described under "Prospectus Summary—Formation Transactions," including the application of the net proceeds from this offering as described under "Use of Proceeds."

        This table is derived from and should be read in conjunction with and is qualified in its entirety by reference to, our historical and pro forma combined financial statements and "Prospectus Summary—Formation Transactions" and the accompanying notes included elsewhere in this prospectus. You should read this table in conjunction with "Prospectus Summary—Formation Transactions" and "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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DILUTION

        Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. Assuming an initial public offering price of $            per common unit, on a pro forma basis as of December 31, 2009 our net tangible book value was $             million, or $            per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in pro forma net tangible book value per unit for financial accounting purposes, as illustrated in the following table:

        The following table sets forth the number of units that we will issue and the total consideration contributed to us by the purchasers of common units in this offering and by us to Holdco and its affiliates (including our manager):

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(1)

Upon completion of the transactions contemplated by this prospectus, Holdco and its affiliates (including our manager) will own            common units,            subordinated units and the 2% managing member interest, which has a dilutive effect equivalent to            units. The number of

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units represented by the 2% managing member interest is determined by multiplying the total number of units deemed to be outstanding (i.e., the total number of common and subordinated units outstanding divided by 98%) by the 2% managing member interest.

(2)

The assets and liabilities contributed by Holdco and its affiliates were recorded at historical cost in accordance with GAAP. The following table shows the investment of Holdco and its affiliates in us after giving effect to this offering and certain distributions to Holdco and its affiliates and other related formation transactions.

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

        You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, see "—Assumptions and Considerations" below. In addition, you should read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

        For additional information regarding our historical and pro forma operating results, you should refer to our historical and pro forma financial statements included elsewhere in this prospectus.

General

Our Cash Distribution Policy

        Our Operating Agreement contains a policy pursuant to which we will pay regular quarterly cash distributions in an aggregate amount equal to substantially all of our available cash. Under the policy, each quarter our board will make a determination of the amount of cash available for distribution to members. Our board will determine 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 reserves for payments to our manager and capital expenditures) or for distributions to members in respect of future quarters. Our board's determination of available cash will take 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.

        Our cash distribution policy reflects a 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 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 you than would be the case if we were subject to such tax.

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 the credit facility that we expect to enter into and by the indenture relating to the expected non-public offerings of senior notes by Niska Canada and Niska US as well as by restrictions in future debt agreements that we enter into. Specifically, the credit facility and indenture are expected to 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 credit facility or indenture or if we are otherwise in default under our credit facility or indenture, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Expected Non-Public Offerings of Senior Notes by Niska US and Niska Canada" and "—Expected New Credit Facility."



•

Our board's determination of cash available for distribution will take into account reserves for the prudent conduct of our business (including reserves for cash distributions to our members),

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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.



•

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.

Our Cash Distribution Policy May Limit Our Ability to Grow

        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.

Minimum Quarterly Distribution

        Upon completion of this offering, our board will adopt a policy pursuant to which we will declare a minimum quarterly distribution of $            per unit per complete quarter, or $            per unit per year, to be paid no later than 45 days after the end of each fiscal quarter. This equates to an aggregate cash distribution of approximately $25.3 million per quarter or $101.3 million per year, in each case based on the number of common units and subordinated units and the 2% managing member interest to be outstanding immediately after completion of this offering.

        If the underwriters do not exercise their option to purchase additional common units, we will issue 2,625,000 common units to Holdco at the expiration of the option. If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Holdco. Accordingly, the exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. See "Underwriting."

        As of the date of this offering, our manager will be entitled to 2% of all distributions that we make prior to our liquidation. Our manager's initial 2% interest in distributions may be reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units to Holdco upon expiration of the underwriters' option to purchase additional common units or the issuance of common units upon conversion of outstanding subordinated units) and our manager does not contribute a proportionate amount of capital to us to maintain its initial 2% managing member interest.

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        The table below sets forth the number of outstanding common units and subordinated units upon the closing of this offering and the number of unit equivalents the managing member interest represents and the aggregate distribution amounts payable on such interests for four quarters based on our minimum quarterly distribution of $            per unit per quarter (or $             per unit on an annualized basis).

        If the minimum quarterly distribution on our common units is not paid with respect to any quarter, the common unitholders will not be entitled to receive such payments in the future except that, during the subordination period, to the extent we distribute cash in any future quarter in excess of the amount necessary to make cash distributions to holders of our common units at the minimum quarterly distribution, we will use this excess cash to pay these arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. See "Provisions of Our Operating Agreement Relating to Cash Distributions—Subordination Period."

        The actual amount of our cash distributions for any quarter is subject to fluctuations based on, among other things, the amount of cash we generate from our business and the amount of reserves our manager establishes.

        We expect to pay our quarterly distributions on or about the 15^th day of each February, May, August and November to holders of record on or about the first day of each such month. We will adjust the quarterly distribution for the period from the closing of this offering through June 30, 2010 based on the actual length of the period.

        In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution of $            per unit each quarter for the four quarters ending March 31, 2011. In those sections we present the following two tables:

•

"Unaudited Pro Forma Cash Available for Distribution," in which we present our estimate of the amount of cash we would have had available for distribution for the twelve months ended

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December 31, 2009 based on our unaudited pro forma financial statements that are included in this prospectus.

•

"Estimated Cash Available for Distribution," in which we demonstrate our anticipated ability to generate the cash available for distribution necessary for us to pay the minimum quarterly distribution on all units for the twelve months ending March 31, 2011.

Unaudited Pro Forma Cash Available for Distribution

        The following table illustrates, on a pro forma basis for the twelve months ended December 31, 2009, cash available to pay distributions, assuming that the following transactions had occurred at the beginning of such period:

•

the expected non-public offerings of notes by Niska US and Niska Canada and the application of the proceeds therefrom;



•

the anticipated refinancing of our current revolving credit facility; and



•

the Formation Transactions, including the use of proceeds of this offering.

        If we had completed the transactions contemplated in this prospectus on January 1, 2009, our unaudited pro forma cash available for distribution for the twelve months ended December 31, 2009 would have been approximately $124.2 million. This amount would have been sufficient to make the minimum quarterly distribution of $            per unit per quarter (or $            per unit on an annualized basis) for the twelve months ended December 31, 2009 on all of our common and subordinated units.

        Unaudited pro forma cash available for distribution includes incremental general and administrative expenses that we expect we will incur as a publicly-traded company, including costs associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. We estimate that these incremental general and administrative expenses initially will be approximately $3.4 million per year.

        The pro forma financial statements, from which pro forma cash available for distribution is derived, do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of January 1, 2009. Furthermore, cash available for distribution is a cash accounting concept, while our unaudited pro forma combined financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution stated above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods.

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        The footnotes to the table below provide additional information about the pro forma adjustments and should be read along with the table.

Niska Gas Storage Partners LLC
Unaudited Pro Forma Cash Available for Distribution

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Estimated Cash Available for Distribution

        We estimate we will generate Adjusted EBITDA of $204.9 million for the fiscal year ending March 31, 2011 and will be able to pay the minimum quarterly distribution on all of our common and subordinated units and our managing member interest for each quarter in that period. In "—Assumptions and Considerations" below we discuss the material assumptions underlying this belief, which reflect our judgment of conditions we expect to exist and the course of action we expect to take.

        Our Adjusted EBITDA for the nine months ended December 31, 2009 was $136.0 million, and our net income was $3.2 million. Based upon our preliminary unaudited results from January 1, 2010 to February 8, 2010, taking into account revenues expected to be realized during the remainder of the period from existing third party storage contracts and proprietary optimization transactions that have already been transacted and our budgeted expenses for the remainder of the quarter, we expect to generate Adjusted EBITDA of approximately $67.0 million and net income of approximately $         million for the full quarter ending March 31, 2010. Accordingly, for the fiscal year ending March 31, 2010, we expect Adjusted EBITDA of approximately $           million and net income of approximately $         million. The estimated Adjusted EBITDA should not be viewed as management's projection of the actual Adjusted EBITDA that we will generate during the fiscal year ending March 31, 2011. We can give you no assurance that our assumptions will be realized or that we will generate the expected levels of Adjusted EBITDA or cash available for distribution, in which event we may not be able to pay the minimum quarterly distribution on all of our units.

        We also anticipate that if our Adjusted EBITDA for the fiscal year ending March 31, 2011 is at or above our estimate, we would be permitted to make the minimum quarterly distributions on all the common units and subordinated units and our manager interest under the applicable covenants contained in our new credit facility and the indenture governing our subsidiaries' expected senior notes.

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        When considering our ability to generate Adjusted EBITDA of $204.9 million and how we calculate estimated cash available for distribution, you should keep in mind the risk factors and other cautionary statements under the headings "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements," which discuss factors that could cause our results of operations and cash available for distribution to vary significantly from our estimates.

        We do not, as a matter of course, make public projections as to future operations, earnings or other results. However, we have prepared the prospective financial information and related assumptions and conditions set forth below to present the estimated cash available for distribution for the fiscal year ending March 31, 2011. The accompanying prospective financial information was not prepared with a view toward public disclosure or with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments and presents, to the best of our knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

        Neither our auditor, KPMG LLP, nor any other independent public accounting firm has examined, compiled or performed any procedures with respect to the accompanying prospective financial information and accordingly, KPMG LLP does not express an opinion or any other form of assurance with respect thereto. The KPMG LLP report included in this prospectus relates to the historical information of Niska Predecessor. It does not extend to the prospective financial information and should not be read to do so. As such, neither KPMG LLP nor any other public accounting firm has expressed an opinion or any other form of assurance in respect of information or its achievability and KPMG LLP assumes no responsibility for and disclaims any association with, the prospective financial institution.

        We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast or the assumptions used to prepare the forecast to reflect events or circumstances after the date of this prospectus. In light of this, the statement that we believe that we will have sufficient cash available for distribution to allow us to make the full minimum quarterly distribution on all of our outstanding common units and subordinated units and our managing member interest for each quarter through March 31, 2011 should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

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Niska Gas Storage Partners LLC
Estimated Cash Available for Distribution

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Assumptions and Considerations

General

•

We estimate that the working gas capacity at AECO Hub™, Wild Goose, and Salt Plains will be 144.0 Bcf, 35.0 Bcf and 13.0 Bcf, respectively, a total increase of 15.0 Bcf (approximately 9.0 Bcf at AECO Hub™ and approximately 6.0 Bcf at Wild Goose) from the prior year. We estimate that the capacity expansions at AECO Hub and Wild Goose will commence commercial service prior to us reaching our maximum current storage capacity such that we are not adjusting for a partial year of commercial service for the expansions. See "—Capital Expenditures."



•

Our expectations are based on a combination of transactions already entered into and transactions we expect to enter into. As of January 25, 2010 we have entered into transactions amounting to revenues of $168.7 million, representing over 63.5% of our total forecasted revenues for the twelve months ending March 31, 2011.



•

We assume that Canadian dollars are converted into dollars at an average rate of $0.9538, which was the average forward rate as of January 25, 2010 for the forecast period.

Revenue

•

Volume Assumptions.  We estimate we will contract 85% of our operated capacity to third parties for the twelve months ending March 31, 2011, compared with 79% for the twelve months ended December 31, 2009. We expect 114.0 Bcf will be contracted as LTF contracts and 49.5 Bcf as STF contracts compared to 103.9 Bcf and 36.8 Bcf, respectively for the fiscal year ending March 31, 2010. We estimate using the remaining 15% of our operated capacity (37.0 Bcf) as well as all of our NGPL capacity (8.5 Bcf) for our optimization business.



•

Services Fees and Optimization Margins.  We estimate that our LTF contracts will generate an average reservation fee of $0.98 per Mcf for the year ending March 31, 2011, as compared to an average of $0.99 for the three years ended March 31, 2009 and to an average fee of $1.02 per Mcf for our existing LTF contracts. We estimate that we will receive an average of $1.69 per Mcf for STF contracts and $1.75 per Mcf for proprietary optimization activities for the year ending March 31, 2011, compared to $1.88 per Mcf for STF contracts and $3.68 per Mcf for proprietary optimization activities for the three years ended March 31, 2009 ($3.37 on a realized basis before unrealized marked to market gains and losses and inventory writedowns).



•

Resulting Revenue Components.  We expect revenue from the reservation fees associated with LTF contracts will be $123.4 million for the fiscal year ending March 31, 2011 as compared to $97.2 million for the twelve months ended December 31, 2009. The increase is due to a combination of higher contracted volumes and higher fees on new and replacement contracts. We estimate that we will recognize $77.6 million in revenue derived from STF contracts compared to $59.2 million for the twelve months ended December 31, 2009. Total revenue from third-party storage services are expected to equal $201.0 million in the fiscal year ending March 31, 2011 compared to $165.8 million in the twelve months ended December 31, 2009. We estimate that we will recognize $91.8 million in revenue from realized optimization revenues for the year ending March 31, 2011, compared $83.8 million for the twelve months ended December 31, 2009. This estimated realized optimization revenue includes estimated revenue of $27.2 million associated with the realization of certain locked-in derivative positions.

Operation and Maintenance Expenses

•

We estimate that total operating and maintenance expenses for the year ending March 31, 2011 will be $54.9 million, as compared to $39.3 million for the twelve months ended December 31, 2009. The increase in operating expenses is the result of an expected increase in fuel costs associated with compression equipment required to inject and withdraw gas in to, and out of, our facilities. Total fuel requirements are expected to be 1.7 Bcf for the fiscal year ending

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March 31, 2011, compared to 1.3 Bcf for the twelve months ended December 31, 2009. The increase in fuel requirements is due to expanded gas storage capacity and increased facility injections and withdrawals that are expected for the year ended March 31, 2011 reflecting a normalized physical injection and withdrawal cycle, as compared to an abnormal carryover of inventory, which occurred in the prior year. In addition, average fuel costs are expected to be $5.67 per Mcf for the fiscal year ending March 31, 2011 (based on forward curves as of January 25, 2010), compared to $3.93 per Mcf for the twelve months ended December 31, 2009 due to an expected increase in the price of natural gas.

General and Administrative Expenses

•

We estimate that general and administrative expenses will be $33.0 million for the year ending March 31, 2011, compared to $25.3 million for the twelve months ended December 31, 2009. Our general and administrative expenses will include one-time costs associated with the expected refinancing of our existing debt facilities as well as additional general and administrative costs of approximately $3.4 million that result from our being publicly-traded.

Depreciation and Amortization Expenses

•

We estimate depreciation and amortization expenses for the year ending March 31, 2011 of $47.0 million, compared to $44.2 million for the twelve months ended December 31, 2009. The increase in depreciation and amortization is the result of additional depreciation on expansion capital expenditures incurred in 2009 that were put into effective use in 2010.



•

We assume that financing costs of $37.0 million associated with the expected senior unsecured notes of Niska Canada and Niska US will be amortized on a straight line basis over 7 years.

Capital Expenditures

•

We estimate total capital expenditures of $75.1 million for the fiscal year ending March 31, 2011, compared to $48.3 million for the twelve months ended December 31, 2009.



•

We estimate that maintenance capital expenditures for the fiscal year ending March 31, 2011 will total $1.7 million. These expenditures relate to replacing partially or fully depreciated assets and to overhaul existing assets.



•

We estimate that expansion capital expenditures for the fiscal year ending March 31, 2011 will be $73.4 million. These expenditures are comprised of two major projects:



•

First, we expect to spend $60.0 million associated with continued expansion of our Wild Goose facility that we expect to complete by March 2011. This project is designed to develop a new reservoir above our existing storage zones which will add 6.0 Bcf of new gas storage capacity during the fiscal year ended March 31, 2011 and an additional 7.0 Bcf in the following fiscal year. We have applied for the regulatory approval required for this project and expect that this approval will be granted during the summer of 2010. If we do not receive the required regulatory approval, we estimate that our net revenue and our Adjusted EBITDA for the fiscal year ending March 31, 2011 would decrease by approximately $8.0 million and $6.5 million, respectively. We estimate that we would be required to decrease our cash reserve by no more than $6.5 million and would still be able to pay the full minimum quarterly distribution on all of our common and subordinated units.



•

Second, we expect to spend $13.4 million in connection with delta pressuring and de-watering projects at AECO Hub™. Regulatory approvals required for this project have already been granted. By modifying some of our surface equipment to allow us to increase the operating pressures and drilling new wells to remove water from our reservoirs, we expect to add 9.0 Bcf of capacity that will be available during the summer of 2010.

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Financing

•

We estimate Niska Canada and Niska US will issue an aggregate of $800.0 million in senior notes, bearing a fixed interest rate of 8.0%, in their expected non-public offerings. We expect to incur interest expense of $64.0 million for the year ending March 31, 2011 associated with these notes.



•

We expect to finance all of our expansion capital expenditures during the forecast period with proceeds from this offering and existing working capital.



•

We estimate that the capacity expansions at AECO Hub and Wild Goose will commence commercial service prior to us reaching our maximum current storage capacity such that we are not adjusting for a partial year of commercial service for the expansions. See "—Capital Expenditures."



•

We estimate we will enter into a new revolving credit facility which we expect will provide up to $400.0 million in senior secured indebtedness. We expect to utilize an annualized average of $141.9 million under this facility to fund the purchase of inventory for our proprietary optimization activities. We expect to purchase 38.7 Bcf of gas evenly over the seven month summer injection season and sell it ratably over the five month winter withdrawal season. At our assumed average interest rate of 5.0%, we anticipate these borrowings will generate interest expense of $7.1 million and a commitment fee on the undrawn portion of $1.9 million for the year ending March 31, 2011.



•

We will remain in compliance with the financial and other covenants in our revolving credit facility.

Regulatory, Industry and Economic Factors

•

We assume there will not be any new federal, state, provincial or local regulations of the natural gas storage industry, or any new interpretations of existing regulations, that will be materially adverse to our business during the twelve months ending March 31, 2011.



•

We assume there will not be any major adverse changes in the natural gas storage industry or in general economic conditions during the three months ending March 31, 2010 or the twelve months ending March 31, 2011.



•

We assume that industry and insurance conditions will not change substantially during the three months ending March 31, 2010 or the twelve months ending March 31, 2011.



•

We assume that we will not be subject to U.S. federal income taxation on our operations or any new or additional entity-level taxation by individual states and localities or non-U.S. jurisdictions during the twelve months ending March 31, 2011.

Payments of Distributions on Common Units, Subordinated Units and the Managing Member Interest

        Distributions on common units, subordinated units and the 2% managing member interest for the twelve months ending March 31, 2011 are estimated to be $101.3 million in the aggregate, assuming we distribute the $            minimum quarterly distribution in respect of each quarter during such periods. Quarterly distributions will be paid within 45 days after the close of each quarter.

        While we believe that these assumptions are reasonable based upon management's current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties, including those described in "Risk Factors," that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual cash available for distribution that we generate could be substantially less than that currently expected and could, therefore, be insufficient to permit us to make the full minimum quarterly distribution on all units, in which event the market price of the common units may decline materially.

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PROVISIONS OF OUR OPERATING AGREEMENT RELATING TO CASH DISTRIBUTIONS

        Set forth below is a summary of the significant provisions of our Operating Agreement that relate to cash distributions. This summary assumes that we do not issue additional classes of equity interests. Statements of percentages of cash and allocations of gain and loss paid or allocated to our manager and Holdco assume that our manager maintains its 2% managing member interest and Holdco does not transfer its incentive distribution rights.

Distributions of Available Cash

General

        Within 45 days after the end of each quarter, beginning with the quarter ending June 30, 2010, we intend to make cash distributions to members of record on the applicable record date.

Intent to Distribute the Minimum Quarterly Distribution

        We will distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $            per unit, or $            per unit per year, to the extent we have sufficient available cash. Our Operating Agreement permits us to borrow to make distributions, but we are not required to do so. Accordingly, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is ultimately determined by our board. We may be prohibited from making any distributions to unitholders by agreements governing our expected and any future indebtedness. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" for a discussion of the restrictions expected to be included in our new credit agreement that may restrict our ability to make distributions.

Managing Member Interest and Incentive Distribution Rights

        As of the date of this offering, our manager will be 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. The manager's initial 2% interest in distributions will be reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units to Holdco upon expiration of the option to purchase additional common units, or the issuance of common units upon conversion of outstanding subordinated units) and our manager does not contribute a proportionate amount of capital to us to maintain its 2% managing member interest.

        Holdco also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48%, of the cash we distribute from operating surplus (as defined below) in excess of $            per unit per quarter. The maximum distribution of 48% does not include any distributions that Holdco may receive through the manager or on common or subordinated units that it owns. See "—Incentive Distribution Rights" for additional information.

Operating Surplus and Capital Surplus

General

        All cash distributed will be characterized as either "operating surplus" or "capital surplus." We distribute cash from operating surplus differently than we would distribute cash from capital surplus. Operating surplus distributions will be made to our unitholders and manager and, if we make quarterly distributions above the first target distribution level described above, the holder of our incentive

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distribution rights. We do not anticipate that we will make any distributions from capital surplus, but any capital surplus distribution would be made pro rata to our manager and all unitholders, but the holder of the incentive distribution rights would generally not participate in any capital surplus distributions with respect to those rights.

Operating Surplus

        Operating surplus for any period generally consists of:

•

$50 million (as described below); plus



•

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as described below) and the termination of commodity hedge contracts with a duration of more than one year (provided that cash receipts from such termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge contracts); plus



•

working capital borrowings made after the end of the period but before the date of determination of operating surplus for the period; plus



•

cash distributions paid on equity interests issued by us (including incremental distributions on incentive distribution rights) to finance all or a portion of the construction, expansion or improvement of our facilities in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service or the date it is abandoned or disposed of; plus



•

cash distributions paid on equity interests issued by us (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the construction, expansion and improvement projects referred to above; less



•

our operating expenditures (as described below) during the period; less



•

the amount of cash reserves established by our board to provide funds for future operating expenditures.

        Working capital borrowings are borrowings under a credit facility, commercial paper facility or similar financing arrangement, incurred in the ordinary course of business solely for working capital purposes or to pay distributions to members and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings.

        The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such a working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deemed repayment.

        As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes a basket of $50 million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of membership interests and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus would be to increase operating surplus by the amount of any such cash distributions. As a

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result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

        Operating expenditures generally means all of our cash expenditures, including taxes, reimbursement or payments of expenses incurred by our manager or its affiliates on our behalf, interest payments, payments made in the ordinary course of business under interest rate swap agreements and commodity hedge contracts (provided that (i) with respect to amounts paid in connection with the initial purchase of a hedge contracts with a duration of more than one year, such amounts will be amortized over the life of the applicable hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contracts with a duration of more than one year prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such hedge contract), repayments of working capital borrowings and maintenance capital expenditures, provided that operating expenditures will not include:

•

repayments of working capital borrowings, if such working capital borrowings were outstanding for twelve months, not repaid, but deemed repaid, thus decreasing operating surplus at such time;



•

payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings;



•

expansion capital expenditures;



•

investment capital expenditures;



•

payment of transaction expenses relating to interim capital transactions (as described below);



•

distributions to our members (including distributions in respect of incentive distribution rights); or



•

repurchases of any equity interest.

        Maintenance capital expenditures reduce operating surplus, but expansion capital expenditures and investment capital expenditures do not. Maintenance capital expenditures represent 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, or other capital expenditures that are incurred in maintaining existing operating capacity of our assets. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets will be treated as maintenance expenses as we incur them. Maintenance capital expenditures include expenditures required to maintain equipment reliability, plant integrity and safety and to address environmental laws and regulations. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

        Expansion capital expenditures are capital expenditures made to increase the long-term operating capacity of our assets or our asset base whether through construction or acquisition. Examples of expansion capital expenditures include the acquisition of equipment, and the development or acquisition of additional gas storage capacity, to the extent such capital expenditures are expected to expand our operating capacity. Expansion capital expenditures will also include interest (and related fees) on debt incurred to finance all or any portion of the construction of such a capital improvement in respect of the period that commences when we enter into a binding obligation to commence construction of a capital improvement and ending on the date such capital improvement commences commercial service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

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        Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of our existing operating capacity or operating income, but which are not expected to expand for the long-term our operating capacity or asset base.

        As described above, none of our investment capital expenditures or expansion capital expenditures will be included in operating expenditures, and thus will not reduce operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all of the portion of the construction, replacement or improvement of a capital asset in respect of the period that begins when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital asset commences commercial service or the date that it is abandoned or disposed of, such interest payments are also not subtracted from operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

        Where capital expenditures are made in part for expansion and in part for other purposes, our board shall determine the allocation between the amounts paid for each. Our officers and directors will determine how to allocate a capital expenditure for the acquisition or expansion of our assets between maintenance capital expenditures and expansion capital expenditures.

Capital Surplus

        Capital surplus is defined in our Operating Agreement as any distribution of cash in excess of our cumulative operating surplus. Accordingly, capital surplus would generally be generated only by the following (which we refer to as "interim capital transactions"):

•

borrowings other than working capital borrowings;



•

sales of our equity interests and debt securities; and



•

sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions

        We treat all cash distributed as coming from operating surplus until the sum of all cash distributed from the closing of this offering (other than distribution of the proceeds from any exercise of the underwriters' option to purchase additional common units) equals the operating surplus as of the most recent date of determination. The characterization of cash distributions as operating surplus versus capital surplus does not result in a different impact to unitholders for U.S. federal tax purposes. See "Material U.S. Tax Consequences—U.S. Federal Income Taxation of Unitholders—Treatment of Distributions" for a discussion of the tax treatment of cash distributions.

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Subordination Period

General

        During the subordination period (which we describe below), the common units will have the right to receive distributions of cash from operating surplus each quarter in an amount equal to $            per common unit, which amount is defined in our Operating Agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of cash from operating surplus may be made on the subordinated units. Furthermore, no arrearages will accrue or be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient cash from operating surplus to pay the minimum quarterly distribution on the common units.

Definition of Subordination Period

        Except as described below, the subordination period will begin on the closing date of this offering and expire the second business day after the distribution to members in respect of any quarter, beginning with the quarter ending March 31, 2013, if each of the following has occurred:

•

quarterly distributions from operating surplus on each outstanding common and subordinated unit equaled or exceeded the minimum quarterly distribution in respect of each of the prior twelve consecutive quarters;



•

operating surplus generated in respect of such twelve consecutive quarters (including operating surplus generated by increases in working capital borrowings and treating any drawdowns from cash reserves established in prior periods as cash received during such quarters but excluding the $50 million basket contained in the definition of operating surplus) equaled or exceeded the aggregate amount of distributions made in respect of such quarters; and



•

we believe that we reasonably should be expected to maintain or increase our quarterly distribution per unit from operating surplus in respect of each of the four succeeding quarters.

        For purposes of the foregoing test, operating surplus shall not include working capital borrowings made in a period but not used to fund operating expenditures during such period. The determination that we reasonably should be expected to maintain or increase our quarterly distribution per unit from operating surplus in respect of each of the four succeeding quarters shall be based upon projections and estimates related to such four succeeding quarters that shall not include any net increase in working capital borrowings (comparing the balance as of the date prior to such quarters to the expected balance as of the end of such quarters) other than those reasonably related to growth or other change in our business or an increase in our distributions expected to occur during such quarters. Our Operating Agreement provides that either the conflicts committee of our board, or the board based on the recommendation of the conflicts committee, shall make the determination of whether and when the subordination period has expired.

        The Operating Agreement provides that the requirements could first be satisfied in connection with a distribution of cash in respect of the quarter ending March 31, 2013 and, if not satisfied in respect of that quarter, could be satisfied on any date thereafter.

        In addition, the subordination period will end upon the removal of our manager other than for cause if no subordinated units or common units held by the holders of subordinated units or their affiliates are voted in favor of that removal.

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Effect of End of the Subordination Period

        Upon expiration of the subordination period, any outstanding arrearages in payment of the minimum quarterly distribution on the common units will be extinguished and each outstanding subordinated unit will immediately convert into one common unit and will thereafter participate pro rata with the other common units in distributions.

Distributions of Cash From Operating Surplus During the Subordination Period

        Distributions from operating surplus in respect of any quarter during the subordination period will be made in the following manner:

•

first, 98% to the common unitholders, pro rata, and 2% to the manager, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter and any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters;



•

second, 98% to the subordinated unitholders, pro rata, and 2% to the manager, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and



•

thereafter, in the manner described in "—Incentive Distribution Rights" below.

Distributions of Cash From Operating Surplus After the Subordination Period

        Distributions from operating surplus in respect of any quarter after the subordination period will be made in the following manner:

•

first, 98% to all unitholders, pro rata, and 2% to the manager, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and



•

thereafter, in the manner described in "—Incentive Distribution Rights" below.

Managing Member Interest

        As of the date of this offering, our manager will be entitled to 2% of all distributions that we make prior to our liquidation. Our manager's initial 2% interest in distributions may be reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units to Holdco upon expiration of the underwriters' option to purchase additional common units or the issuance of common units upon conversion of outstanding subordinated units) and our manager does not contribute a proportionate amount of capital to us to maintain its initial 2% managing member interest. Our Operating Agreement does not require that the manager fund its capital contribution with cash and our manager may fund its capital contribution by the contribution to us of common units.

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 will initially hold 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

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•

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 $            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 $            per unit for that quarter (the "second target distribution");



•

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 $            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.

        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.

Percentage Allocations of Cash Distributions From Operating Surplus

        The following table illustrates the percentage allocations of cash distributions from operating surplus between the unitholders, our manager and the holders of the incentive distribution rights, or based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest in Cash Distributions" are the percentage interests of our manager, the incentive distribution right holders and the unitholders in any cash distributions from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit Target Amount." The percentage interests shown for the unitholders and the manager for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

Distributions From Capital Surplus

How Distributions From Capital Surplus Will Be Made

        Distributions from capital surplus, if any, will be made in the following manner:

•

first, 98% to all unitholders, pro rata, and 2% to the manager, until the minimum quarterly distribution is reduced to zero, as described below;

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•

second, 98% to the common unitholders, pro rata, and 2% to the manager, until we distribute for each common unit an amount of cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution; and



•

thereafter, we will make all distributions of cash from capital surplus as if they were from operating surplus.

Effect of a Distribution From Capital Surplus

        Our Operating Agreement treats a distribution of capital surplus as the repayment of the consideration for the issuance of the unit, which is a return of capital. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution had in relation to the fair market value of the common units prior to the announcement of the distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels, after any of these distributions are made, it may be easier for Holdco to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

        If we reduce the minimum quarterly distribution and the target distribution levels to zero, all future distributions from operating surplus will be made such that 50% is paid to all unitholders, pro rata, and 2% is paid to our manager and 48% is paid to the holders of the incentive distribution rights, pro rata.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

        In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into a lesser number of units or subdivide our units into a greater number of units, we will proportionately adjust:

•

the minimum quarterly distribution;



•

the target distribution levels; and



•

the initial unit price, as described below under "—Distributions of Cash Upon Liquidation."

        For example, if a two-for-one split of the units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units using the same ratio applied to the common units. We will not make any adjustment to the minimum quarterly distribution, the target distribution levels or the initial unit price by reason of the issuance of additional units for cash or property.

        In addition, if we or any of our subsidiaries is treated as an association taxable as a corporation or are otherwise subject to taxation as an entity for U.S. federal, state, local or foreign (including Canadian) income tax purposes, our board may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (after deducting our board's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter plus our board's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

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Non-Cash Distributions

        We do not anticipate that we will make any non-cash distributions but our Operating Agreement does not prohibit us from making non-cash distributions. If we make any non-cash distributions (other than distributions of our own securities) our managing member will determine the fair market value of the assets being distributed and such assets will be distributed as if they were cash from operating surplus or cash from capital surplus, as applicable, and will be deemed to have been distributions of cash from operating surplus or capital surplus for all purposes under our Operating Agreement.

Distributions of Cash Upon Liquidation

General

        If we dissolve in accordance with the Operating Agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to our unitholders, our manager, and the holders of our incentive distribution rights in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

        The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by a unitholder to us for their units, which we refer to as the "initial unit price" for each unit. The initial unit price for the common units will be the price paid for the common units issued in this offering. The allocations of gain and loss upon liquidation are also intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights.

Manner of Adjustments for Gain

        If our liquidation occurs before the end of the subordination period, we will allocate any gain to the members in the following manner:

•

first, to the manager and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;



•

second, 98% to the common unitholders, pro rata, and 2% to the manager, until the capital account for each common unit is equal to the sum of: (1) the initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;



•

third, 98% to the subordinated unitholders, pro rata, and 2% to the manager, until the capital account for each subordinated unit is equal to the sum of: (1) the initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

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•

fourth, 98% to all unitholders, pro rata, and 2% to the manager, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to the manager, for each quarter of our existence;



•

fifth, 85% to all unitholders, pro rata, 2% to the manager and 13% to the holders of the incentive distribution rights, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, 2% to the manager and 13% to the holders of the incentive distribution rights for each quarter of our existence;



•

sixth, 75% to all unitholders, pro rata, and 2% to the manager and 23% to the holders of the incentive distribution rights, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, 2% to the manager and 23% to the holders of the incentive distribution rights for each quarter of our existence; and



•

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

        The percentages set forth above for our manager and the holders of the incentive distribution rights include its 2% managing member interest.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses

        If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our manager, the holders of the incentive distribution rights and the unitholders in the following manner:

•

first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to the manager, until the capital accounts of the subordinated unitholders have been reduced to zero;



•

second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the manager, until the capital accounts of the common unitholders have been reduced to zero;



•

third, 98% to all unitholders, pro rata, and 2% to the manager, provided that the allocation of the loss does not reduce the capital account of a unitholder below zero; and



•

thereafter, 100% to our manager.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

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Adjustments to Capital Accounts Upon Issuance of Additional Units

        We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we generally will allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders, the holders of the incentive distribution rights and our manager in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will first allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in our manager's capital account balance equaling the amount that it would have been if no earlier positive adjustments to the capital accounts had been made. By contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our manager based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. In the event we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders' capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

        We were formed on January 27, 2010 and do not have our own historical financial statements for periods prior to our formation. Therefore, we present the financial statements of Niska Predecessor, consisting of the combined financial statements of US Holdings and Canada Holdings. 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. The historical financial statements of Niska Predecessor contained elsewhere in this prospectus represent the combined historical and operating data of US Holdings and Canada Holdings. Prior to the closing of this offering, Niska Holdings will contribute Niska Predecessor. This prospectus 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. The following table presents selected historical combined financial and operating data of Niska Predecessor and selected pro forma financial and operating data of Niska Gas Storage Partners LLC as of the dates and for the periods indicated.

        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 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 Corporations'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 combined financial data presented for the years ended March 31, 2008 and 2009, the nine months ended December 31, 2009 and the period from May 12, 2006 to March 31, 2007 is derived from, and should be read together with and is qualified in its entirety by reference to, the historical audited financial statements and the accompanying notes included elsewhere in this prospectus. The historical combined financial data presented for the nine months ended December 31, 2008 is derived from, and should be read together with and is qualified in its entirety by reference to, the historical unaudited financial statements and the accompanying notes included elsewhere in this prospectus. Moreover, the table should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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        Our selected pro forma statement of operations data for the nine months ended December 31, 2009 and selected pro forma balance sheet data as of December 31, 2009 are derived from the unaudited pro forma combined financial statements of Niska Gas Storage Partners LLC included elsewhere in this prospectus. The pro forma adjustments have been prepared as if the expected non-public offering of senior notes by Niska Canada and Niska US, this offering and the transactions to be effected at the closing of this offering had taken place on December 31, 2009, in the case of the pro forma balance sheet, and on April 1, 2009, in the case of the pro forma statement of operations. A more complete explanation of the pro forma data can be found in our unaudited pro forma combined financial statements.

        The following table includes the non-GAAP financial measure of Adjusted EBITDA.

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Non-GAAP Financial Measure

Adjusted EBITDA

        We use the non-GAAP financial measure Adjusted EBITDA in this prospectus. A reconciliation of Adjusted EBITDA to its most directly comparable financial measure as calculated and presented in accordance with GAAP is shown below.

        We define Adjusted EBITDA as net income 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. 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 nature to the traditional adjustments to net income 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;

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•

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 income. The non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA 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 income and is defined differently by different companies, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The historical financial statements included elsewhere in this prospectus reflect the combined assets, liabilities and operations of Niska Predecessor. Prior to the closing of this offering, Niska Predecessor will be contributed to us. The following discussion analyzes the historical financial condition and results of operations of Niska Predecessor before the impact of pro forma adjustments related to the contribution of our assets by Niska Predecessor, the expected non-public offerings of senior notes by Niska Canada and Niska US and use of proceeds therefrom, our expected entry into a new credit agreement prior to the closing of this offering, and this offering. You should read the following discussion of the historical combined financial condition and results of operations in conjunction with the historical financial statements and accompanying notes of Niska Predecessor and the pro forma financial statements for Niska Gas Storage Partners LLC included elsewhere in this prospectus. 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."

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 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 inception to March 31, 2009, we utilized an average of approximately 78% of our operated capacity for our LTF strategy. The volume weighted average life of our LTF contracts at December 31, 2009 was 3.3 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, 2009, our LTF contracts generated average reservation fees of $0.99 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.

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Volume and Fees Derived from STF Contracts

        In addition, we provide short term services for customers under STF contracts. From inception to March 31, 2009, we utilized an average of approximately 14% 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, 2009, our STF contracts generated average fees of $1.88 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 on the contract rates available for STF contracts.

Volume and Margin Derived from Our Proprietary Optimization Activities

        From inception to March 31, 2009, we utilized an average of approximately 8% 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 transactions, we are able to determine in advance the minimum margins that will be realized and add incremental margins by rehedging 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 already been locked in by choosing to hold inventory into a subsequent period and rehedging 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.

        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 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 gains when the inventory is sold. From inception to March 31, 2009, our proprietary optimization business generated average margins of $3.68 per Mcf (3.37 on a realized basis before unrealized marked to market gains and losses and inventory writedowns).

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 salaries, bonus compensation, legal and accounting fees and our office lease. Following this offering we expect our general and

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administrative expenses will increase substantially as a result of an increase in legal and accounting costs and related public company regulatory and compliance expenses.

Adjusted EBITDA

        We define Adjusted EBITDA as net income 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. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP, see "Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure."

Capitalization and Leverage

        We regularly monitor our leverage statistics to ensure a conservative capital structure. As of December 31, 2009, we had a debt to Adjusted EBITDA ratio of 3.2x, debt to capitalization of 38%, and an Adjusted EBITDA to interest coverage ratio of 6.1x. 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.

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 facility. We therefore closely monitor the utilization and remaining available capacity under our credit facility 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 will be 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

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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 will impact 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.

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.

Comparability of Our Financial Statements

        Our results of operations, statements of cash flows and financial condition, set forth in our audited financial statements and contained elsewhere in this prospectus, for the period from May 12, 2006 through March 31, 2007 do not contain data for Wild Goose prior to November 16, 2006, the date that we acquired Wild Goose. As a result they are not directly comparable with our results of operations, statements of cash flows and financial condition for subsequent periods. Accordingly, we recommend that you do not place undue reliance on data contained in this prospectus for the period from May 12, 2006 through March 31, 2007.

        Since our inception on May 12, 2006, we have added approximately 41.3 Bcf of capacity to our facilities. As a result, our revenues and expenses have not only been impacted by changing utilization patterns and pricing environments, but also by increasing overall capacity. This further limits your ability to compare year-over-year changes in our results from operations.

        We anticipate incurring incremental general and administrative expenses attributable to operating as a publicly-traded entity. These costs include expenses associated with SEC compliance, including annual and quarterly reporting, tax return and Schedule K-1 preparation, compliance with Sarbanes-Oxley, listing on the NYSE, engaging attorneys and independent auditors, obtaining incremental director and officer liability insurance and engaging a registrar and transfer agent. We expect these expenses to total approximately $3.4 million per year. These expenses are not reflected in our historical financial statements.

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Results of Operations

        The following provides a summary of our results for the period from May 12, 2006 through March 31, 2007, for the fiscal years ended March 31, 2008 and 2009, and for the nine months ended December 31, 2008 and 2009:

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        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 period from May 12, 2006 through March 31, 2007, for the fiscal years ended March 31, 2008 and 2009 and for the nine months ended December 31, 2008 and 2009:

Nine Months Ended December 31, 2009 Compared to Nine Months Ended December 31, 2008

        Revenues.    Revenues decreased 33.5% to $140.7 million for the nine months ended December 31, 2009 compared to $211.6 million for the nine months ended December 31, 2008. This change was primarily attributable to the following:

•

LTF Revenues.  LTF revenues for the nine months ended December 31, 2009 decreased 4.8% to $81.8 million from $85.9 million for the nine months ended December 31, 2008. This decrease was primarily attributable to a 41.4% decrease in fuel and commodity revenue to $6.5 million for the twelve months ended December 31, 2009 from $11.1 million for the twelve months ended December 31, 2008 due to lower natural gas prices and less cycling.



•

STF Revenues.  STF revenues for the nine months ended December 31, 2009 increased 21.9% to $39.9 million from $32.8 million for the nine months ended December 31, 2008. This increase was primarily attributable to an 11.9% increase in capacity utilized for STF contracts, from 32.9 Bcf for the nine months ended December 31, 2008 to 36.8 Bcf for the nine months ended December 31, 2009. The balance relates to a 9% improvement in margins in the nine months ended December 31, 2009.



•

Optimization Revenues.  Optimization revenues for the nine months ended December 31, 2009 decreased to $18.9 million from $92.9 million for the nine months ended December 31, 2008 primarily due to 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

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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.  Revenue increased by 30.2% to $64.2 million for the nine months ended December 31, 2009 from $49.3 million for the nine months ended December 31, 2008, while storage capacity utilized for proprietary optimization activities increased from 24.5 Bcf for the nine months ended December 31, 2008 to 44.8 Bcf for the nine months ended December 31, 2009. A lower-priced commodity environment led to increased proprietary inventory purchases in the nine months ended December 31, 2009, while a portion of the revenue associated with these purchases will be recognized in the last quarter of the fiscal year.



•

Unrealized Risk Management Gains/(Losses).  Unrealized risk management losses for the nine months ended December 31, 2009 were $45.3 million compared to a gain of $93.8 million for the nine months ended December 31, 2008. This was primarily attributable to prices rising after financial hedges were transacted for the nine months ended December 31, 2009 compared to a falling price environment during the same period in the prior year. 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 summer of 2008 in the high priced commodity environment was subject to a writedown for the nine months ended December 31, 2008 when commodity prices retreated significantly. These losses were offset by gains from financial hedges that were transacted at higher prices at the time inventory was purchased as described above. For the nine months ended December 31 2008 this loss amounted to $50.1 million, compared to zero for the nine months ended December 31, 2009.

        Earnings before Income Taxes.    Earnings before income taxes for the nine months ended December 31, 2009 decreased 35.5% to $55.0 million from $85.4 million for the nine months ended December 31, 2008. This decrease was primarily attributable to the items discussed above, offset by the following:

•

Operating Expenses.  Operating expenses for the nine months ended December 31, 2009 decreased 17.7% to $28.4 million from $34.5 million for the nine months ended December 31, 2008. This decrease was primarily attributable to lower fuel and electricity costs resulting from lower prices in the nine months ended December 31, 2009.



•

General and Administrative Expenses.  General and administrative expenses for the nine months ended December 31, 2009 increased by 5.5% to $21.5 million from $20.4 million for the nine months ended December 31, 2008. This increase was primarily attributable to increased legal and accounting services related to activities related to refinancing the company's debt facilities. This was partially offset by reduced rent expenses from subletting a portion of the company's office space in the nine months ended December 31, 2009 and to reduced legal fees as a result of the settlement of arbitration proceedings in 2008.



•

Depreciation and Amortization.  Depreciation and amortization for the nine months ended December 31, 2009 decreased 24.3% to $32.9 million from $43.4 million for the nine months ended December 31, 2008. This decrease was primarily attributable to a provision booked in the nine months ended December 31, 2008 amounting to $11.9 million to record the impact of cushion gas ineffectiveness at AECO. The provision against cushion gas is an estimate based on tests of its effectiveness. Through continued monitoring of cushion effectiveness over a series of

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withdrawal and injection cycles, management is able to better estimate the extent of effectiveness deterioration. Based on this assessment, a charge amounting to $11.9 million was included in depreciation to reflect management's ability to better assess cushion gas effectiveness after monitoring operations over our ownership period.

•

Interest Expense.  Interest expense for the nine months ended December 31, 2009 decreased 53.7% to $20.1 million from $43.5 million for the nine months ended December 31, 2008. This decrease was primarily attributable to a significant decrease in the principal balance of our term debt during the nine months ended December 31, 2009 compared to the prior period. In addition, the interest rates on our term debt and revolvers were floating and the average interest rates applied to our term debt and revolver balances were lower by approximately 55.7% and 54.7%, respectively, in the nine months ended December 31, 2009 than in the nine months ended December 31, 2008.

        Net Income.    Net income for the nine months ended December 31, 2009 decreased to $3.2 million from $100.8 million for the nine months ended December 31, 2008. This change was primarily attributable to the items discussed above, plus the following:

•

Income Tax Expense/(Benefit).  Income tax expense for the nine months ended December 31, 2009 increased to $51.8 million from a benefit of $15.4 million for the nine months ended December 31, 2008. This is the result of two of our Canadian subsidiaries electing to adopt the U.S. dollar as their functional currency for our Canadian tax returns, the result of which increased future tax expense by $23.4 million. In addition, Niska recorded a valuation allowance of $16.7 million relating to the uncertainty of realization of certain capital losses.

Year Ended March 31, 2009 Compared to Year Ended March 31, 2008

        The fiscal year ended March 31, 2009 was characterized by an environment of high natural gas prices at the beginning of the year which reduced the seasonal spread. An emerging oversupply of natural gas in mid-2008 due to the growth in domestic supply caused near term natural gas prices to decline while long term prices were generally not affected to the same degree. This pricing dynamic created an incentive for our customers to carry inventory in storage over the winter and sell it in the following fiscal year, rather than to withdraw inventory during the winter months which is what would otherwise be expected.

        Revenue.    Revenues for the fiscal year ended March 31, 2009 increased 8.3% to $252.2 million from $232.9 million for the year ended March 31, 2008. This increase was primarily attributable to the following:

•

LTF Revenues.  LTF revenues for the year ended March 31, 2009 decreased 8.8% to $110.7 million from $121.4 million for the year ended March 31, 2008. This was primarily attributable to a 6% decrease in the quantity of capacity contracted under LTF contracts to 106.3 Bcf for the year ended March 31, 2009 from 112.8 Bcf for the year ended March 31, 2008. In addition, new or replacement contract rates were 22.5% lower in the fiscal year ended March 31, 2009 as compared to the year ended March 31, 2008 due to a lower value LTF storage environment. Due to the lower storage value environment, we elected not to re-contract some of the contracts that expired in 2009. In addition, the minimum contracting covenant contained in our existing debt facility expired during the year and we elected to alter the capacity utilization towards STF contracts which offered higher value in the then current period.



•

STF Revenues.  STF revenues for the year ended March 31, 2009 increased 46.5% to $52.0 million from $35.5 million for the year ended March 31, 2008 due to an increase in capacity used in STF contracts from 19.1 Bcf for the fiscal year ended March 31, 2008 to 32.9 Bcf for the fiscal year ended March 31, 2009. Unit margins contributed by STF capacity

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were $1.58 per MMbtu for the year ended March 31, 2009 compared to $1.86 per MMbtu for the year ended March 31, 2008.

•

Optimization Revenues.  Net optimization revenue for the year ended March 31, 2009 increased 17.6% to $89.4 million from $76.0 million for the year ended March 31, 2008. Although we utilized slightly more storage capacity for proprietary optimization in the fiscal year ended March 31, 2009 due to expansions at our facilities, optimization activities were somewhat constrained by our working capital revolver. The components of optimization revenues are as follows:

•

Realized Optimization Revenues.  Realized optimization revenues for the fiscal year ended March 31, 2009 decreased 7.6% to $68.9 million from $74.6 million for the fiscal year ended March 31, 2008. Unit margins contributed by our proprietary optimization strategy were $2.82 per MMbtu for the fiscal year ended March 31, 2009 compared to $3.18 per MMbtu for the fiscal year ended March 31, 2008. This is primarily attributable to a decision to carry inventory into the following fiscal year to generate incremental margins. This was somewhat offset by a small increase in storage capacity utilized for our optimization activities. For the fiscal year ended March 31, 2009, 24.5 Bcf of storage capacity was utilized for proprietary optimization, compared to 23.4 Bcf for the fiscal year ended March 31, 2008.

•

Unrealized Risk Management Gains/(Losses).  Income from unrealized risk management gains for the year ended March 31, 2009 increased to $82.8 million from $1.5 million for the year ended March 31, 2008. This increase was primarily attributable to $78.2 million in mark-to-market gains on our financial hedges related to our natural gas inventory that was carried over the fiscal year end in a falling price environment, unlike the prior year in which comparatively little inventory was carried forward. In addition, mark-to-market gains on foreign currency exchanges totaled $4.6 million in the fiscal year ended March 31, 2009 as compared to mark-to-market losses of $0.6 million for the year ended March 31, 2008.

•

Unrealized Inventory Writedown.  Inventory purchased early in the fiscal year ended March 31, 2009 in the high priced commodity environment was subject to a writedown for that year after commodity prices retreated significantly. These losses were offset by the financial hedge positions that were transacted when the inventory was purchased as described above. For the fiscal year ended March 31, 2009 this unrealized inventory writedown amounted to $62.3 million, compared to zero for the fiscal year ended March 31, 2008.

        Earnings before Income Taxes.    Earnings before income taxes for the fiscal year ended March 31, 2009 increased 115.6% to $96.9 million from $45.0 million for the fiscal year ended March 31, 2008. This increase was primarily attributable to the items discussed above, plus the following:

•

Operating Expenses.  Operating expenses for the fiscal year ended March 31, 2009 remained largely unchanged from the fiscal year ended March 31, 2008. Higher per unit fuel costs in the fiscal year ended March 31, 2009 were offset by lower fuel consumption created by lower inventory withdrawals in the winter of 2009. Because natural gas prices were higher in the following summer we and our customers had an incentive to carry inventory over the end of the fiscal year ended March 31, 2009 and benefit by selling it in the following year at higher prices.



•

General and Administrative Expenses.  General and administrative expenses for the fiscal year ended March 31, 2009 decreased 19.7% to $24.2 million from $30.1 million for the fiscal year ended March 31, 2008. This decrease was primarily attributable to $3.2 million in legal and consulting fees incurred as the result of the EnCana Corporation arbitration in the fiscal year ended March 31, 2008, $1.5 million of which were recovered from an arbitration award and

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treated as a deduction against general and administrative expenses for the fiscal year ended March 31, 2009.

•

Depreciation Amortization.  Depreciation and amortization for the fiscal year ended March 31, 2009 increased 28.8% to $54.8 million from $42.5 million for the fiscal year ended March 31, 2008. This increase was primarily attributable to a provision amounting to $11.9 million to record the impact of declining cushion gas effectiveness at AECO. The provision against cushion gas is an estimate based on tests of its effectiveness. Through continued monitoring of cushion effectiveness over a series of withdrawal and injection cycles, management is able to better estimate the extent of effectiveness deterioration. For the year ended March 31, 2009, based on this assessment, a charge amounting to $11.9 million was included in depreciation to reflect management's ability to better assess cushion gas effectiveness after monitoring operations over our ownership period.



•

Interest Expense.  Interest expense for the fiscal year ended March 31, 2009 decreased 27.6% to $53.5 million from $73.9 million for the fiscal year ended March 31, 2008. This decrease was primarily attributable to a lower average outstanding balance on our term debt and revolvers of approximately $16.8 million and $26.5 million, respectively, in the fiscal year ended March 31, 2009 than in the fiscal year ended March 31, 2008. In addition, the interest rates on our term debt and revolvers were floating and the average interest rates applied to our term debt and revolver balances were lower by approximately 36% and 39%, respectively, in the fiscal year ended March 31, 2009 than in the fiscal year ended March 31, 2008.



•

Loss on Sale of Assets.  Losses on sales of assets for the fiscal year ended March 31, 2009 decreased to zero from $2.3 million for the fiscal year ended March 31, 2008. No fixed assets were disposed of in the fiscal year ended March 31, 2009 as compared to sales of pipe originally purchased for a development project in the fiscal year ended March 31, 2008 on which we realized a loss.



•

Other Income.  Other income for the year ended March 31, 2009 increased to $20.8 million from $0.7 million for the year ended March 31, 2008. This increase was primarily attributable to an award amounting to $19.8 million granted to us as a result of the resolution of the EnCana Corporation arbitration in the fiscal year ended March 31, 2009. The arbitration resulted from a dispute over a working capital adjustment related to the acquisition of Wild Goose, or the EnCana Corporation arbitration. While EnCana Corporation maintained that certain natural gas held in storage at the acquisition date was inventory and subject to a working capital adjustment, we maintained that such gas was required for operational support of the facilities, and as such, included in the acquisition price. In order to close the acquisition we agreed to pay for the natural gas via a working capital adjustment and then submitted our request for arbitration, which commenced shortly after the close of the acquisition. After examining the evidence from both parties, the arbitrator ruled in our favor in July 2008. In addition to recovering the initial working capital adjustment, which is treated as other income, the arbitrator awarded us some, but not all, of the costs we incurred in connection with the arbitration process.



•

Foreign Exchange Losses/(Gains).  Foreign exchange gains for the year ended March 31, 2009 increased to $25.8 million from $7.2 million for the year ended March 31, 2008. This increase was primarily attributable to the translation of a Canadian dollar-denominated deferred tax liability into fewer U.S. dollars on March 31, 2009 as compared with March 31, 2008, caused by a decline in the value of the Canadian dollar to $0.7928 from $0.9742, resulting in an unrealized foreign exchange gain amounting to $37.2 million for the fiscal year ended March 31, 2009. The foreign exchange gains for the fiscal year ended March 31, 2009 were offset by realized foreign exchange losses amounting to $11.4 million due to settlements of Canadian dollar-denominated receivables in cash in a weakening Canadian dollar environment.

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        Net Income.    Net income for the year ended March 31, 2009 increased to $108.8 million from $48.3 million for the year ended March 31, 2008. This change was primarily attributable to the items discussed above, plus the following:

•

Income Tax Expense/(Benefit).  Income tax benefit for the year ended March 31, 2009 increased to $11.9 million from $3.4 million for the year ended March 31, 2008. This increase was primarily attributable to increases in the accounting and tax timing differences related to capital assets and intangible assets and limitations on the deductibility of interest on debt, in conjunction with decreases in tax rates (from 32.1% to 29.6%).

Year Ended March 31, 2008 Compared to the Period from May 12, 2006 to March 31, 2007

        Niska Predecessor acquired most of our assets, other than Wild Goose, on May 12, 2006 and acquired Wild Goose on November 16, 2006. Accordingly, the year ended March 31, 2007 was a partial year compared to the full year ended March 31, 2008. The period ended March 31, 2007 was characterized by very high storage values in the early part of the year that gave us an incentive to increase the amounts of volumes contracted. Spreads narrowed in September 2006 leading to lower storage values entering the subsequent year.

        Revenues.    Revenues for the year ended March 31, 2008 increased 20.2% to $232.9 million from $193.8 million for the period from May 12, 2006 to March 31, 2007. This increase was primarily attributable to the following:

•

LTF Revenues.  LTF revenues for the fiscal year ended March 31, 2008 increased 16.2% to $121.4 million from $104.5 million for the period from May 12, 2006 to March 31, 2007. This increase was primarily attributable to a full year of operations for the fiscal year ended March 31, 2008 compared to a partial year for the period from May 12, 2006 to March 31, 2007 (November 16, 2006 to March 31, 2007 in the case of Wild Goose). This was offset by a reduction in LTF contracted storage capacity of 5.9% to 112.8 Bcf for the fiscal year ended March 31, 2008 from 119.9 Bcf for the period from May 12, 2006 to March 31, 2007 and a 5.9% decrease in incremental contract rates from the period ended March 31, 2007 to the fiscal year ended March 31, 2008.



•

STF Revenues.  STF revenues for the fiscal year ended March 31, 2008 increased 10.6% to $35.5 million from $32.1 million for the period from May 12, 2006 to March 31, 2007. For the fiscal year ended March 31, 2008, 19.1 Bcf of capacity was used for STF contracts, compared to 11.7 Bcf for the period from May 12, 2006 to March 31, 2007. This increase was primarily attributable to an increase of 11.0 Bcf in aggregate capacity of our storage facilities and a shift of 7.0 Bcf of capacity contracted to customers using STF contracts and proprietary optimization that was previously utilized by LTF contracts. Our STF capacity contributed margins of $1.86 per MMbtu for the fiscal year ended March 31, 2008 compared to $2.74 per MMbtu for the period ended March 31, 2007.



•

Optimization Revenues.  Net optimization revenue for the fiscal year ended March 31, 2008 increased 32.9% to $76.0 million from $57.2 million for the period from May 12, 2006 to March 31, 2007. The components of optimization revenues are as follows:



•

Realized Optimization Revenues.  Realized optimization revenues for the year ended March 31, 2008 increased 24.3% to $74.6 million from $60.0 million for the period from May 12, 2006 to March 31, 2007. For the fiscal year ended March 31, 2008, 23.4 Bcf of capacity was utilized by proprietary optimization, compared to 12.6 Bcf for the period ended March 31, 2007. Unit margins contributed by this strategy were $3.18 per MMbtu for the fiscal year ended March 31, 2008 compared to $4.77 per MMbtu for the period ended March 31, 2007. Proprietary optimization revenue includes $16.7 million and $11.1 million

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from the sale of inventory that was held in our facilities on a temporary basis to support higher cycling LTF contracts for the period from May 12, 2006 to March 31, 2007 and the fiscal year ended March 31, 2008, respectively.

•

Unrealized Risk Management Gains/(Losses).  Unrealized risk management gains for the fiscal year ended March 31, 2008 increased to $1.5 million from a loss of $2.8 million for the period from May 12, 2006 to March 31, 2007. This increase was primarily attributable to the realization of financial hedges coinciding with the physical sales of physical inventory during the fiscal year ended March 31, 2008.

        Earnings Before Income Taxes.    Earnings before income taxes for the fiscal year ended March 31, 2008 increased 8.7% to $45.0 million from $41.4 million for the period from May 12, 2006 to March 31, 2007. This increase was primarily attributable to the items discussed above, offset by the following:

•

Operating Expenses.  Operating expenses for the fiscal year ended March 31, 2008 increased 55.2% to $44.6 million from $28.8 million for the period from May 12, 2006 to March 31, 2007. This increase was primarily attributable to a full year of operations for the fiscal year ended March 31, 2008 compared to a partial year for the period from May 12, 2006 to March 31, 2007.



•

General and Administrative Expenses.  General and administrative expenses for the fiscal year ended March 31, 2008 increased 51.5% to $30.1 million from $19.9 million for the period from May 12, 2006 to March 31, 2007. This increase was primarily attributable to a full year of operations for the fiscal year ended March 31, 2008 compared to a partial year for the period from May 12, 2006 to March 31, 2007 and increased legal fees in the fiscal year ended March 31, 2008, $3.2 million of which was due to the EnCana Corporation arbitration.



•

Depreciation and Amortization.  Depreciation and amortization for the fiscal year ended March 31, 2008 decreased 8.8% to $42.5 million from $46.6 million for the period from May 12, 2006 to March 31, 2007. This decrease was primarily attributable to a smaller amortization of customer intangible assets acquired at inception that are not amortized in a straight line method.



•

Interest Expense.  Interest expense for the fiscal year ended March 31, 2008 increased 22.7% to $73.9 million from $60.2 million for the period from May 12, 2006 to March 31, 2007. This increase was primarily attributable to a full year of operations for the fiscal year ended March 31, 2008 compared to a partial year for the period from May 12, 2006 to March 31, 2007. In addition, we drew additional borrowings and had a greater amount of debt outstanding under our revolver in the fiscal year ended 2008, due to increased optimization activity and as a substantial amount of term debt added in November 2006 due to the consummation of the Wild Goose acquisition.



•

Loss on Sale of Assets.  Losses on sales of assets for the fiscal year ended March 31, 2008 was $2.3 million compared to zero for the period from May 12, 2006 to March 31, 2007. We purchased approximately 30 miles of pipe to build a pipeline at one of our development projects and some of it was sold after the project was delayed. As we sold this pipe for less than we paid for it, we realized a loss on the sale during the fiscal year ended March 31, 2008.



•

Asset Impairment.  Asset impairment for the fiscal year ended March 31, 2008 was $2.5 million compared to zero for the period from May 12, 2006 to March 31, 2007. The value of the pipe that we bought for our development project was worth less at March 31, 2008 than it was when we bought it, the pipe that was not sold was subject to an impairment of $2.5 million. See "—Loss on Sale of Assets."



•

Foreign Exchange Losses/(Gains).  Foreign exchange gains for the fiscal year ended March 31, 2008 increased to $7.2 million from $2.6 million for the period ended March 31, 2007. The

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change relates to translation gains and losses, the major component of which are driven by the change in exchange rates between accrual and settlement of physical gas purchases and sales.

        Net Income.    Net income for the fiscal year ended March 31, 2008 decreased 9.6% to $48.3 million from $53.5 million for the period from May 12, 2006 to March 31, 2007. This decrease was primarily attributable to the following factors offsetting the earnings before income tax discussed above:

•

Income Tax Benefit.  Income tax benefit for the fiscal year ended March 31, 2008 decreased 72.2% to $3.4 million from $12.1 million for the period ended March 31, 2007. This decrease was primarily attributable to increases in the accounting and tax timing differences related to capital assets and intangible assets and the limitations on the deductibility of interest in debt, in conjunction with decreases in tax rates from 32.1% for the period ending March 31, 2007 to 31.5% for the fiscal year ended March 31, 2008.

Liquidity and Capital Resources

        The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common units, subordinated units and the 2% managing member interest to be outstanding immediately after this offering is $            . Our pro forma cash available for distribution during the twelve months ended December 31, 2009 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common and subordinated units during such period. See "Our Cash Distribution Policy and Restrictions on Distributions."

        Our primary short-term liquidity needs will be to pay our quarterly distributions, to pay interest and principal payments under our debt agreements and to fund our operating expenses and maintenance capital and near-term liquidity needs, which we expect to fund through a combination of cash on hand and cash from operations. 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 this offering, borrowings under 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.

        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 being offered under this prospectus. 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.

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Historical Cash Flows

        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 facility 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 fluctuate significantly from period to period.

        The following table summarizes our sources and uses of cash for the period from May 12, 2006 through March 31, 2007, the fiscal years ended March 31, 2008 and 2009, and the nine months ended December 31, 2008 and 2009.

        Operating Activities.    The variability in net cash provided by operating activities is primarily due to varying market conditions that exist at the end of any given fiscal period, and timing differences related to the subsequent decision that is made to either 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.

        For the period ended March 31, 2007, the price of natural gas in the following summer was higher than winter prices during such period. We thus chose to carry some of our inventory into the following fiscal year by rehedging the sale of our inventory to the following summer. This had the effect of increasing our overall margins and profitability, although income was deferred from the period from May 12, 2006 to March 31, 2007 to the fiscal year ended March 31, 2008 and this also reduced cash provided by operating activities for the period from May 12, 2006 to March 31, 2007. This timing

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difference was reversed in the following year when inventory was ultimately sold, at a higher margin than we had previously locked in.

        For the fiscal year ended March 31, 2008, the price of natural gas in the following summer was less than winter prices during such period and therefore there was no economic incentive to hold inventory over the year end. We sold essentially all of our available proprietary inventory prior to the end of the year and this resulted in no unusual timing anomalies in net cash provided by operating activities.

        For the fiscal year ended March 31, 2009, the price of natural gas in the following summer was higher than winter prices during such period, similar to the situation experienced at the end of March 31, 2007. As in the period ended March 31, 2007, we chose to carry our inventory into the following fiscal year, which had the effect of increasing our overall margins and profitability, although income was deferred from the fiscal year ended March 31, 2009 to the fiscal year ending March 31, 2010.

        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, 2009, we had net working capital of $90.2 million (working capital ratio of 1.3 to 1.0), compared to net working capital of $75.6 million (working capital ratio of 1.5 to 1.0) and $82.8 million (working capital ratio of 1.6 to 1.0) at March 31, 2008 and 2007, respectively. These changes are primarily due to increased capital spending in 2008 which temporarily reduced working capital while expanding our existing facilities.

        Investing Activities.    With the exception of the period ended March 31, 2007, most of the investing activities in each annual and nine-month period 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 41.3 Bcf. However, maintenance capital expenditures have consistently ranged between $1.0 million and $2.0 million each year (except for the period ending March 31, 2007, which was a partial year).

        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 working capital revolver 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 to cover income tax obligations. During the 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 working capital revolver 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 year ending March 31, 2008, we retired $79.9 million of term debt via optional and mandatory prepayments and repaid $60.0 million of working capital revolver drawings following the sale of our proprietary inventory. During the period ending March 31, 2007, we received $1.5 billion through a combination of debt and equity proceeds to fund the acquisition of the assets and drew $60.0 million on our working capital revolver to fund proprietary inventory purchases. We

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also used $51.3 million of cash provided by operations to retire some of the term debt borrowed by us at inception.

        For the nine months ended December 31, 2008, we repaid $7.2 million of our existing term debt from cash provided by operations. During the same period, we drew $85.0 million from our working capital revolver to fund proprietary inventory purchases. We also made a $37.6 million distribution to our equity holders to cover income tax obligations of our unitholders. See Note 14 to our combined financial statements.

        For the nine months ended December 31, 2009, we repaid $3.0 million of our existing term debt from cash provided by operations. During the same period, we drew $125.0 million from our working capital revolver to fund proprietary inventory purchases. We also made a $37.6 million distribution to our equity holders to cover income tax obligations of our unitholders. See Note 14 to our combined financial statements.

Capital Expenditures

        Our capital expenditures for the period from May 12, 2006 through March 31, 2007, the years ended March 31, 2008 and 2009, and the nine months ended December 31, 2008 and 2009 were as follows:

        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 addition, we anticipate spending a total of $71.0 million in the fiscal year ending March 31, 2010 to expand the capacity and services of our facilities. We are evaluating additional projects to further expand our storage capacity at existing facilities and to develop new storage projects in the fiscal year ending March 31, 2011 and beyond. We expect that these projects will allow us to grow our total working gas capacity by approximately 15.0 Bcf by March 31, 2011, 27.0 Bcf by March 31, 2012, 37.0 Bcf by March 31, 2013 and 39.0 by March 31, 2014 and that the total cost of these identified expansions will be approximately $175.0 million. We expect to fund our maintenance capital

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expenditures through internally generated funds and our expansion capital expenditures through internally generated funds as well as borrowings under our credit facility, issuances of membership interests or debt offerings or a combination of the foregoing.

Credit Facility

        Certain subsidiaries of U.S. Holdings and Canada Holdings entered into a $1.2 billion credit facility, dated as of May 12, 2006, with a syndicate of financial institutions. The credit facility consists of a U.S. revolver loan (which includes a U.S. swing line facility) of $175.0 million, a Canadian revolver loan (which includes a Canadian swing line facility) of $175.0 million, an asset sale term loan of $100.0 million, a U.S. term loan of $175.0 million, and a Canadian term loan of $550.0 million. The term loans were used to fund the acquisitions of our assets. The interest rates on amounts drawn from the facility could range from (1) between 0.75% and 1.25% above the higher of (a) the federal funds rate plus 0.5% and (b) Bank of America's prime rate for revolver loans drawn as a base rate loan, (2) between 1.75% and 2.25% over LIBOR for revolver loans drawn as a Eurodollar loan, (3) 0.75% above the higher of (a) the federal funds rate plus 0.5% and (b) Bank of America's prime rate for term loans drawn as a base rate loan and (4) 1.75% over LIBOR for term loans drawn as Eurodollar loans.

Expected Non-Public Offerings of Senior Notes by Niska US and Niska Canada

        We expect that Niska Canada and Niska US will undertake non-public offerings of senior notes prior to the closing of this offering. We expect that the non-public offerings will be for $800.0 million aggregate principal amount of senior notes. We expect that the senior notes will be sold in offerings exempt from registration under the Securities Act and will be offered only 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.

        We expect that the senior notes will be senior obligations of Niska US and Niska Canada, and will be (1) effectively junior to the respective issuer's secured obligations; (2) structurally subordinated in right of payment to all existing and future indebtedness and other liabilities of any of our subsidiaries that do not guarantee the senior notes; (3) pari passu in right of payment with all existing and future senior indebtedness of the respective issuer; and (4) unconditionally guaranteed by us and certain of our subsidiaries on a senior basis.

        We expect that the senior notes will be issued under a trust indenture that will contain negative covenants which in general will restrict our, and our subsidiaries', ability to engage in certain activities, including without limitation:

•

making distributions, purchases or redemptions of equity and certain investments and retiring any indebtedness that is subordinated to the notes or the note guarantees (except a payment of interest or principal at the stated maturity thereof);



•

incurring certain indebtedness or issuing disqualifying stock, subject to certain exceptions, unless for the most recent four fiscal quarters for which internal financial statements are available our fixed charge coverage ratio had been at least 2.0 to 1.0; and



•

consolidations, mergers and sales of assets.

        If an event of default exists under the indentures, the holders of the expected senior notes may declare the entire principal of all senior notes and interest accrued thereon to be due and payable immediately.

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Expected New Credit Facility

        Concurrently with the closing of the expected non-public offerings of senior notes, we expect that we will terminate our existing credit agreement and enter into a new secured credit agreement. We expect this new credit agreement to provide for a revolving credit facility, with an initial maximum borrowing capacity of $400.0 million. We anticipate that availability under our revolving credit facility will be subject to a borrowing base which will be redetermined from time to time and based initially on our receivables, inventory of proprietary gas and certain fixed assets. We anticipate that we may borrow only up to the level of our then current borrowing base.

Contractual Obligations

        The following table summarizes by period the payments due for our estimated contractual obligations as of March 31, 2009:

Off-Balance Sheet Arrangements

        As of December 31, 2009, we did not have any off-balance sheet arrangements. Prior to the closing of this offering, we will enter into a credit facility. 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.

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.

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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 transaction.

        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 operational tolerances specified in our risk policy.

        As at December 31, 2009, 50.2 Bcf of natural gas inventory was economically hedged, representing 99.2% of total current inventory. Long-term inventory, and fuel gas used for operating our facilities are not offset. Total volumes of long-term inventory and fuel gas at December 31, 2009 are 8.1 Bcf and 0.3 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 Combined Financial Statements and "—Critical Accounting Estimates."

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.

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        At December 31, 2009, we had forward currency exchange contracts for a notional value of $126.5 million. The value of the forward currency contracts at March 31, 2009 and December 31, 2008 and 2007 was an asset of $4.6 million, $8.7 million and $0.6 million, respectively, and is recorded in derivative assets and derivative liabilities on the combined balance sheets. These open contracts at March 31, 2009, mature on various dates through 2010 and are for the exchange of U.S. dollars into 78.4 million Canadian dollars at an average rate of 1.17 Canadian dollars to 1.00 dollar.

Interest Rate Risk

        We will be exposed to interest rate risk due to variable interest rates under the credit facility that we will enter into prior to the closing of this offering. All such borrowings under the facility will bear interest at variable rates. 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 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.

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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.

        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."

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 periods ending December 31, 2009 and 2008 as well as March 31, 2009, 2008 and 2007.

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

Critical Accounting Estimates

        The historical financial statements included elsewhere in this prospectus have been prepared in accordance with GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and

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requirements, the application of which requires management 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 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, valuing asset retirement obligations and in determining liabilities, if any, for legal contingencies.

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 25^th 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 their 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 12 to our combined financial statements included elsewhere in this prospectus.

Fair Value of Risk Management Assets and Liabilities

        The Partnerships use natural gas derivatives and other financial instruments to manage their exposure to changes in natural gas prices, foreign exchange, and interest rates. These financial assets

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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 reflect 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.

Inventory

        Our inventory is natural gas injected into storage which is 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

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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 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 cycle-ability of similar entities. Results using the multiples of potential earnings and the multiples of gas capacity and cycle-ability 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.

        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.

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 Canada 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.

Recent Accounting Pronouncements

        The following new accounting pronouncements were adopted during 2009 and the effect of such adoption has been presented in the accompanying combined financial statements:

Generally Accepted Accounting Principles (ASC 105)

        This accounting standard results in the Financial Accounting Standards Board, or the FASB, Accounting Standards Codification, or the Codification, becoming the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC are also considered sources of authoritative GAAP for SEC registrants. The

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Codification supersedes all then-existing non-SEC accounting and reporting standards. All other non-grandfathered, non-SEC accounting literature not included in the Codification is non-authoritative. The adoption of the provisions of this accounting standard did not change the application of existing GAAP, and as a result, did not have any impact on our combined results of operations, combined financial position or cash flows.

Fair Value Measurement (ASC 820)

        We adopted a new fair value measurement standard as of April 1, 2008. ASC 820 defines fair value, establishes a framework for measuring fair value under existing accounting pronouncements that require fair value measurements and expands fair value measurement disclosures. ASC 820 defines fair value as 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 (exit price). The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

Level 1—inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).

Level 2—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market corroborated inputs).

Level 3—inputs that are not observable from objective sources, such as our internally developed assumptions about market participant assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in our internally developed present value of future cash flows model that underlies the fair value measurement).

        In determining fair value, we utilize observable market data when available, or models that utilize observable market data. In addition to market information, we incorporate transaction-specific details that, in management's judgment, market participants would take into account in measuring fair value.

        In forming fair value estimates, we utilize the most observable inputs available for the valuation technique employed. If a fair value measurement reflects inputs at multiple levels within the hierarchy, the fair value measurement is characterized based upon the lowest level of input that is significant to the fair value measurement. Recurring fair value measurements are performed for commodity, interest rate and foreign currency derivatives.

        The carrying amount of cash and cash equivalents, margin deposits, trade receivables, accrued receivables, trade payables and accrued liabilities reported on the balance sheet approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on valuations of similar debt at the balance sheet date and supported by observable market transactions when available. See Note 9 to our combined financial statements included elsewhere in this prospectus for disclosures regarding the fair value of debt. See Note 13 to our combined financial statements included elsewhere in this prospectus for disclosures regarding the fair value of derivative instruments.

        We elected to implement the standard with the one-year deferral permitted for nonfinancial assets and nonfinancial liabilities, except those nonfinancial items recognized or disclosed at fair value on a recurring basis (at least annually). The deferral period ended on April 1, 2009. Accordingly, we now apply the fair value framework to nonfinancial assets and nonfinancial liabilities initially measured at

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fair value, such as assets acquired in a business combination, impaired long-lived assets (asset groups), intangible assets and goodwill and initial recognition of asset retirement obligations.

Disclosures about Derivative Instruments and Hedging Activities (ASC 815-10)

        We adopted a new standard for our derivative instruments and hedging activities, effective April 1, 2009. ASC 815-10 does not change our accounting for derivatives, but requires enhanced disclosures regarding our methodology and purpose for entering into derivative instruments, accounting for derivative instruments and related hedged items (if any), and the impact of derivative instruments on our combined financial position, results of operations and cash flows. See Notes 12 and 13 to our combined financial statements included elsewhere in this prospectus.

Business Combinations (ASC 805)

        We adopted a new accounting standard for business combinations, effective April 1, 2009. ASC 805 applies prospectively to us for future business combinations. ASC 805 expands the definition of what qualifies as a business, thereby increasing the scope of transactions that qualify as business combinations. Furthermore, under ASC 805, changes in estimates of income tax liabilities existing at the date of, or arising in connection with, past business combinations are accounted for as adjustments to current period income as opposed to adjustments to goodwill. The adoption of ASC 805 had no impact on our combined financial position, results of operations or cash flows.

Subsequent Events (ASC 855-10)

        We adopted a new standard on subsequent events, effective April 1, 2009. ASC 855-10 defines subsequent events as either recognized subsequent events (events that provide additional evidence about conditions at the balance sheet date) or nonrecognized subsequent events (events that provide evidence about conditions that arose after the balance sheet date). Recognized subsequent events are recorded in the financial statements for the current period presented, while nonrecognized subsequent events are not. Both types of subsequent events require disclosure in the combined financial statements if nondisclosure of such events causes the financial statements to be misleading. We are also required to disclose the date through which subsequent events have been evaluated. The adoption of ASC 855-10 had no impact on our combined financial statements. We have evaluated subsequent events through February 19, 2010. See Note 23 to our combined financial statements included elsewhere in this prospectus.

        The following new accounting pronouncements were issued but not adopted as of December 31, 2009:

Fair Value Measurement (ASC 810-10)

        This new standard requires disclosure of 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. The guidance was effective for interim and annual periods beginning after December 15, 2009. For period beginning as of April 1, 2010, we will be required to disclose additional fair value measurement information such as transfers into and out of levels 1 and 2 and further details of movements within level 3. The new standard clarifies the level of disaggregation required and inputs and valuation techniques used to measure fair value.

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NATURAL GAS STORAGE INDUSTRY

        In this prospectus, we refer to information regarding the natural gas storage industry in the United States and Canada from the U.S. Energy Information Administration, or the EIA, the National Petroleum Council (an Advisory Committee to the U.S. Secretary of Energy), or the NPC, the U.S. Federal Energy Regulatory Commission, or FERC, and Canadian Enerdata.

Overview of the Natural Gas Value Chain

Introduction

        Collectively, the United States and Canada consume approximately 27.0 trillion cubic feet, or Tcf, of natural gas per year. This amount represents approximately 28% of the total annual energy consumption in those countries, and is growing. In 2008, residential and commercial consumers accounted for 23% and 15%, respectively, of the total delivered volume of natural gas in the United States and Canada. The use of relatively clean-burning natural gas for power generation has increased significantly in recent years, constituting 29% of the total delivered volume of natural gas in 2008. The industrial sector constituted 32% of the total delivered volume of natural gas in 2008. While the portion of total natural gas consumed by residential and commercial customers and for power generation has increased over recent years, the portion used by industrial customers has declined.

        The natural gas "value chain" refers to the steps involved in bringing natural gas from beneath the earth's surface to the ultimate consumer and consists of gas production at the wellhead, gathering, processing, transmission, storage, marketing and distribution, as shown in the following illustration.

Production

        The first segment of the natural gas value chain is natural gas production, which consists of the exploration for, and the extraction of, natural gas from underground reservoirs. The main North American natural gas production regions are the Gulf Coast, the Permian basin, the Mid-Continent, the San Juan basin, the Rocky Mountain region, the Appalachian region and Western Canada. In addition, overseas production arrives by ship as liquefied natural gas, or LNG.

Gathering

        Gathering systems, primarily made up of small-diameter, low-pressure pipelines, move raw natural gas from the wellhead to a natural gas processing plant or to an interconnection with a larger mainline pipeline.

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Processing

        There are four main steps involved in natural gas processing: (1) treating; (2) dehydration; (3) recovery of natural gas liquids, or NGLs and (4) fractionation. These processes separate pipeline quality gas, or dry natural gas (predominantly methane), from NGLs and the heavier hydrocarbon components that are not suitable for long-haul pipeline transportation or commercial use.

Pipeline Transmission

        Natural gas is transported from gathering facilities and processing plants to downstream consumption areas by transmission pipelines. In North America, there are approximately 305,000 miles of large-diameter, high-pressure interstate and intrastate transmission pipelines operated by more than 200 companies.

Storage

        Natural gas storage is a critical element of the natural gas value chain, and serves two primary purposes. First, gas storage augments natural gas production and delivery systems, enhancing reliability of supply during periods of heavy gas demand. Second, gas storage is used to inject excess production during periods of low or off-peak demand and to withdraw gas when demand is higher, thus balancing the mismatch between relatively steady production and oscillating demand. Natural gas storage can serve to decrease peak-demand gas costs through injection of lower priced gas in off-peak periods and withdrawal in peak demand periods. In addition to managing seasonal price differentials, gas in storage is used increasingly to arbitrage movements in gas prices across time. The following chart illustrates the imbalance between fluctuating demand and relatively stable supply:

Source: Energy Information Administration

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        Producers, transmission pipelines, local distribution companies, or LDCs, marketers and end-users, including gas-fired electric power plants, benefit directly from the load balancing and supply reliability functions of gas storage. Storage facilities are typically utilized by:

•

Natural gas distributors and end-users, such as LDCs, which serve residential and commercial customers, large industrial users and gas-fired electric power plants, to manage fluctuations in monthly, daily or hourly gas demand, to avoid penalties assessed by pipelines and other parties for temporary imbalances, and to balance often significant seasonal variations in their gas demand profile;



•

Pipelines, to provide short-term advances to shippers in order to manage temporary imbalances or to maintain the operational integrity of the pipeline; and



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Independent natural gas marketing companies, energy merchants, and financial institutions in connection with the execution of their gas marketing and energy trading strategies and commodities portfolios.

        According to the EIA, there are approximately 120 natural gas storage operators in North America, which control approximately 400 underground storage facilities with an aggregate gas storage capacity of 4.2 Tcf. The principal operators of underground natural gas storage facilities are:

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Interstate pipeline companies, which developed underground storage to facilitate load balancing and system supply management on their long haul transmission pipelines and use much of it to serve their shippers;



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Intrastate pipeline companies, which use underground storage to serve their end-user customers, as well as to facilitate load balancing and system supply management;



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LDCs or utilities, which use underground storage to serve the primarily seasonal demand variations of their own end-use customer portfolio; and



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Independent storage operators, which operate underground storage as a business primarily to serve third-party customers.

        Prior to deregulation in 1994, interstate pipeline companies generally owned the gas flowing through their systems, including gas held in storage, and had exclusive control over the capacity and utilization of their storage facilities. As natural gas markets were deregulated and interstate pipelines were required to provide open-access to their systems, the number of direct participants in natural gas markets increased significantly. With each participant seeking to manage its own requirements, rather than a pipeline operating an aggregated supply system, major changes in the inventory management practices and storage utilization in the natural gas industry have occurred.

Distribution

        Once natural gas reaches the market through transmission lines, it is (1) directly delivered from transmission lines to large industrial, commercial and power generation customers or (2) delivered to residential and commercial consumers at reduced pressures through LDCs. More than 1,500 LDCs deliver natural gas to end users through hundreds of thousands of miles of small-diameter service lines.

Marketing

        Natural gas marketers are separate entities that compete to provide natural gas services to producers, resellers or to end users and may be affiliates of producers, pipelines or LDCs, or may be separate business entities unaffiliated with other participants in the natural gas industry. Marketers find buyers for natural gas, ensure secure supplies of natural gas in the market, and arrange transportation and storage for natural gas to efficiently reach the end-user.

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Natural Gas Storage Reservoir Types

        Natural gas may be stored in a number of different ways. It is most commonly held underground and under pressure in one of three major types of "reservoirs:" (1) depleted reservoirs in oil and gas fields; (2) aquifers; and (3) salt cavern formations. Depleted reservoirs, aquifers and salt caverns make up approximately 86%, 10% and 4%, respectively, of North America's total underground gas storage capacity. Besides location, the key attributes of any storage facility are the amount of inventory that can be stored for later use (the gas storage capacity) and the rate at which that inventory capacity can be filled or emptied (injection and withdrawal capability, or cycling capacity). The different types of natural gas storage have distinctly different characteristics in each of these areas.

        The following charts provide an overview of the major types of reservoir storage in North America:

Depleted Reservoirs

        Depleted reservoirs are naturally occurring underground formations that originally contained and produced oil or natural gas and that have been depleted through earlier production. Geologically, they are permeable underground rock formations that are confined by barriers of impermeable rock and sometimes water.

        Of the three primary types of underground storage facilities, depleted reservoirs are typically the least expensive to develop, operate and maintain. In order to maintain sufficient pressure to support design withdrawal rates in depleted reservoirs, approximately 50% of the formation's volume must be kept filled with cushion gas. The remaining capacity is the gas storage capacity.

        Depending on the quality of the reservoir, depleted reservoirs can be developed with cycling capability between 1.0 and 5.0 cycles per year, but most commonly are capable of cycling their working gas 1.0 or 2.0 times per year. Reservoirs with rock of higher permeability and porosity, when combined with modern techniques such as horizontal well technology, are capable of the higher cyclabilities.

Aquifers

        Aquifers are underground, porous, permeable rock formations that act as natural water reservoirs. In certain situations, these formations may be reconditioned and used as natural gas storage facilities. The cushion gas requirement for aquifers is higher than for depleted reservoirs or salt caverns and can be as high as 90% of the total gas volume. Typical aquifer storage can only be cycled once per year. Most aquifer storage development has occurred in the upper mid-west of the United States, where there is a significant need for seasonal storage, and few depleted reservoirs or salt deposits.

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Salt Cavern Formations

        Salt cavern formations are reservoirs that are leached or mined out of underground salt deposits (salt domes or salt beds). The cushion gas requirement for salt caverns is approximately 25% of the total gas volume.

        Salt caverns typically have much smaller working gas (inventory) capacity than depleted gas reservoirs and aquifers. As such, salt caverns cannot hold the volume of gas necessary to meet base load storage requirements. However, because deliverability (in proportion to inventory capacity) from salt caverns is typically much higher than for either aquifers or depleted reservoirs, natural gas may be more readily (and quickly) withdrawn and injected into salt caverns. These types of facilities can be designed for working gas to be cycled as much as twelve times a year.

Natural Gas Storage Value Drivers for Market Based Storage Services

        The value of a natural gas storage facility or storage services contract is principally based on a number of drivers, including:

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Operational characteristics and location of the storage facility;



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Seasonal spreads in natural gas prices;



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Volatility and absolute levels of natural gas prices; and



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Interest rate levels.

Operational Characteristics and Location of the Storage Facility

        The operational characteristics of a storage facility have a significant impact on the value of storage services at the facility. These characteristics include overall gas storage capacity, cyclability (or the number of times the working gas volume can be fully injected and withdrawn in a year) and geographic location. The length of time a facility can sustain its peak withdrawal rate before it starts to decline and the steepness of the decline in withdrawal rate as further inventory is removed, are the basic elements of a facility's profile and determine its cyclability. The more flexibility (cyclability) that a facility profile offers, the more value it can generate, whether through contract services or optimization. A storage facility's value can also be impacted by its location within the natural gas infrastructure, such as location near market regions or multiple pipeline interconnects.

Seasonal Spreads

        On average, total natural gas consumption levels in the United States are approximately 28% higher in the winter months than summer months primarily due to the requirements of residential and commercial market sectors where gas is used principally for heating. Accordingly, natural gas prices are significantly lower in the summer than in the winter, and this price differential is referred to as the seasonal spread. Gas storage capacity allows the capacity holder to take advantage of the seasonal spread by injecting and storing gas when prices are low and then withdrawing the gas during periods of high demand when prices are higher. The gross margin available from buying and injecting gas in summer months for withdrawal in winter months can be locked in at the time of injection by entering into a forward sale for the gas, establishing a minimum value for the gas storage user.

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        Below is an example of a hypothetical gas price futures curve to illustrate the seasonal spread:

        The changes in supply and demand dynamics discussed below in "—Fundamental Industry Trends" have resulted in higher seasonal gas price differentials, and thus, in higher gas storage contract values in recent years. While the seasonal differential tends to be influenced by a number of short-term factors, the growing trend in storage contract values established over the last several years indicates, in part, the natural gas market's recognition that previous levels of gas storage capacity may no longer be sufficient to provide adequate supply for the expected range of winter demand conditions.

Price Volatility and Absolute Level of Natural Gas Prices

        In times when natural gas prices are more volatile, the value of storage capacity increases because storage capacity holders with the contractual ability to withdraw or inject gas, as applicable, are able to capture more value from their storage capacity. When near-term natural gas prices are volatile, storage capacity holders often have opportunities to inject and withdraw natural gas from storage in an effort to earn incremental margins above the seasonal spread as market opportunities permit. This is sometimes referred to as the option value of gas storage. In addition, increased volatility in demand can intensify the demand for storage for supply reliability. Gas storage facilities with higher injection and withdrawal capabilities are best able to capture value from gas market volatility.

        Higher natural gas price levels result in greater absolute movement in natural gas prices in response to ordinary market volatility and higher margins available to be captured through natural gas storage. In high market price environments, storage users have a greater incentive to mitigate their exposure to significant price changes. Higher prices typically generate higher storage values where the benefit from greater price movements more than offsets higher variable costs.

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Interest Rate Levels

        There is a financing cost for the storage capacity holder to carry the cost of the inventory while it is stored in the facility. That financing cost is impacted by the cost of capital or interest rate incurred by the storage user as well as the commodity cost of the natural gas in inventory. The higher the financing cost, the lower the margin that will be left over from the price spread that was intended to be captured.

Fundamental Industry Trends

        We believe recent trends in the industry suggest continued demand for and increased value of natural gas storage.

Increased Natural Gas Consumption and Production

        According to the EIA, natural gas consumption in the United States and Canada will increase by an average of 0.5% and 1.5%, respectively, per year through 2030. In order to meet this projected demand growth, natural gas producers will need to increase supplies, which is likely to result in increased demand for gas storage capacity, especially in off-peak periods. Natural gas storage facilities are already beginning to see the effects of increased gas production. The EIA reported that during the week ended November 27, 2009, the amount of working gas in storage was 3.8 Tcf, the highest amount on record.

        There is evidence that the current North American natural gas storage system will be unable to meet this growing demand unless there is a significant expansion of storage facilities. The limited growth in storage capacity in recent years and the significant barriers to the construction of new facilities suggests that such an expansion is unlikely to occur and that gas storage prices will increase in the future. See "—Limited Storage Supply Growth."

Increasingly Seasonal and Weather-Sensitive Natural Gas Demand

        Demand for natural gas in North America is typically higher during the winter than the summer, primarily due to residential and commercial heating applications. In some regions of North America, peak air conditioning loads during hot summer months place greater demand on natural gas to fuel power plants. Natural gas produced in excess of demand during the shoulder (spring and fall) months is typically stored to meet the increased demand for natural gas during the winter months and an emerging summer demand peak. Seasonal winter demand has shown steady growth even as warmer average winter temperatures over the past four years have dampened the full potential impact of increasing demand. Increasing winter demand for natural gas, coupled with increased overall demand, should result in an increased need to store natural gas, especially in the lower-demand months during spring and fall.

        In addition to being influenced by seasonal weather changes, severe storms such as Hurricanes Katrina and Rita in 2005 have demonstrated the influence of catastrophic weather events on the energy industry. These natural disasters caused major disruption in the oil and gas industries by destroying infrastructure in the U.S. gulf region. To mitigate the impact of similar events in the future, FERC and CPUC have followed policies that encourage developers to build more natural gas storage facilities.

Production of Natural Gas Decreasingly Sensitive To Seasonal Factors

        While gas demand continues to grow and become more seasonal, gas production is essentially flat and is becoming less seasonal, making natural gas storage even more important. Before the gas market

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was deregulated, some producers were required to shut-in some amount of production during summer months, when demand and prices tended to be at their lowest levels. Those wells were brought back onto production in the fall and winter months as demand and gas prices rose. This slight seasonality of gas production provided some minor offset to the need for seasonal storage capacity, but has almost entirely disappeared. The NPC has noted that the current environment in which gas supply is increasingly challenged to keep pace with growing demands for natural gas gives producers an incentive to maintain gas production at near maximum capability at all times.

        Unlike many products, where production can be increased and sustained in a matter of days, increases in natural gas production involve much longer lead time measured in months or even years (possibly requiring exploratory seismic work, the drilling of wells and the connection of wells to pipelines.) As a result, the supply of natural gas is relatively inelastic in response to changes in the price of natural gas. In addition, it would be economically inefficient and poor production practice for producers to routinely shut-in wells when natural gas prices are low. By continuing their production efforts when demand for natural gas is low producers create a surplus of natural gas which creates downward price pressure and a requirement for storage.

Gas-Fired Power Generation Increases Volatility

        Over 83% of electric generating capacity added in the last decade has been natural gas-fired. The rapid growth in gas-fired power generation since the 1990's, fueled in part by environmental legislation that makes natural gas a more attractive alternative to coal and oil, is significantly contributing to increased natural gas demand volatility and consumption by amplifying winter spikes and adding significant demand on the hottest days in summer. First, gas-fired electric power plant demand is adding to the consumption spikes of winter as cold days now see the dual impact of increased gas heating load and increased power loads. Second, the greatest demand for electrical power from gas-fired power generation is during the hottest days of summer for air-conditioning loads. The relatively new phenomenon of a secondary summer demand peak reduces gas available for injection into storage to build inventories during the traditional summer injection period, compressing the storage injection season to the shoulder months of spring and fall.

        In addition to increasing volatility, the growth in the number of gas-fired power plants has resulted in a greater need for storage facilities with high deliverability capabilities. The need to produce energy rapidly in order to meet suddenly increased demand requires that gas-fired power plants have access to natural gas quickly. Only facilities that have relatively high deliverability capabilities can provide this level of flexibility.

Reduction of Industrial Base-Load Consumption Increases Volatility

        While natural gas demand from the residential, commercial and power generation sectors has been growing, demand from the industrial sector, which has the least seasonality and weather sensitivity, is in decline in the United States. The result is a reduction in base load gas demand, further amplifying the sensitivity of remaining demand. Furthermore, the loss of industrial load reduces the market's ability to respond to demand spikes. Historically, price sensitive industrial users typically switched fuels or temporarily halted operations for a few days when gas prices got too high. This industrial "shock absorber" in natural gas markets is diminishing. These trends further reduce the overall flexibility of demand and are likely to contribute to greater gas price volatility and increased reliance on natural gas storage.

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Renewable Energy Creates Increased Demand for Gas Storage Capacity

        Several states have introduced renewable portfolio standards, requiring a certain portion of that state's energy supply portfolio be derived from renewable sources. Solar and wind power generation is intermittent, requiring backup when, for example, the wind is calm but demand for power is high. Natural gas fired power generation is the most easily dispatchable and will naturally fill the backup role, but will require more gas storage capacity to hold readily available supply.

Increasing Seasonal Spread and Continued Volatility

        Since 2000, the seasonal spread at Henry Hub, one of the main reference prices for the North American natural gas market, has increased, on average, from $0.31 per MMbtu in 2000 to $2.15 per MMbtu in 2009. The summer/winter NYMEX forward spread is the difference between the highest price month and the lowest price month in any future April through March period. The chart below highlights the seasonal trend that has been observed in the North American natural gas market.

NYMEX Seasonal Price Spread Trends

Source: New York Mercantile Exchange (NYMEX)

        There has been a corresponding sustained upward trend in the value of natural gas storage over the past several years, which reflects many of the recent natural gas market trends. For example, summer/winter NYMEX differentials increased from $0.38 per MMbtu in early 2003, to $1.24 per MMbtu in early 2005, to $3.80 per MMbtu in early 2006. After a dramatic increase in those differentials in 2006, summer/winter differentials have narrowed but have not fallen below approximately $1.30 per MMbtu.

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        Recent trends suggest that volatility in natural gas demand and prices will remain a large factor in the natural gas storage industry. The chart below highlights the historical volatility trend for natural gas prices observed at Henry Hub from 2001 to late 2009. Volatility of natural gas prices at Henry Hub from 2001 to 2009 on a cash basis show extreme spikes in price volatility in the winter season due to natural gas demand volatility and the need for additional supply reliability during these peak demand months.

Historical Henry Hub Cash Price Volatility- 90 Day Trailing Average

Source: Platts Gas Daily

        Growing weather-sensitive demand is increasing demand for, and the value of, gas storage services. Cold winter temperatures significantly augment the demand for natural gas storage. Despite the increase in weather sensitive demand in recent years, market prices have not fully increased correspondingly, due to a number of factors such as the 2008-2009 economic downturn which muted the economy, and a pattern of warmer-than-normal winters, which reduced demand for storage withdrawals. The 2003 fiscal year illustrates that moderately colder-than-normal winter temperatures can have a large effect on the amount of natural gas cycled from storage—2.9 Tcf was withdrawn to

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satisfy winter demand that winter and Henry Hub spot prices reached $18.00 per MMbtu. The chart below illustrates the extreme sensitivity of natural gas prices to modestly colder than normal winters.

Winter Weather Effects on Henry Hub Cash Price

Source: NOAA National Climate Data Center, Platts Gas Daily

        The NPC estimated in 2003 that as much as 700.0 Bcf of additional storage capacity may be required by 2025 to meet demand trends under assumptions of "normal" weather each year. Demand for storage could be as much as 25% higher than normal in a year in which winter weather is significantly colder than normal. A single cold winter that highlights the current limitations on storage capacity may be sufficient impetus for a further increase in storage values.

Limited Storage Supply Growth

        There is evidence that new facilities will need to be built to keep up with the projected growth in demand. While some official statistics suggest that North America's aggregate storage capacity is 4.1 to 4.6 Tcf, other data shows that these estimates could be unreliable. The EIA estimated that in 2009 the maximum practical working gas inventory level in the U.S. was 3.9 Tcf, based on demonstrated non-coincident peak inventories at all facilities over the past five years. This estimated maximum capacity is only slightly above the actual level of inventory reached November 20, 2009, at the end of the most recent injection season. The NPC, however, has stated that the largest volume of inventory actually cycled in any year has been 2.9 Tcf, suggesting that storage capacity may be incapable, for a variety of reasons, of cycling more than that volume without extreme seasonal price variability.

        Unlike the growth in demand, the supply of storage capacity in North America has experienced only modest growth recently. This trend is partly due to the fact that most of the high-quality locations have been developed. Remaining prospects are of poorer quality, and thus require a larger capital investment. Additionally, recent efforts to build additional storage facilities have been hampered by factors such as: (1) a lack of available capital due to the global financial crisis; (2) capped, regulated storage rates; and (3) the need for long-term contracts at attractive rates prior to construction. Finally, during periods of high prices for natural gas in the past decade, some smaller, less efficient gas storage facilities have been removed from service in order to recover cushion gas for sale. According to the

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EIA, between 1997 and 2007 the number of active storage fields in the U.S. declined slightly from 418 to 400.

        In the natural gas storage business there are significant barriers to entry, particularly in depleted reservoir storage development where we have successfully developed a leading presence. Barriers include:

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Geology:  Only the best reservoirs will provide the capacity, security and performance characteristics for economic gas storage. Rock quality, structure, depth, containment and reservoir size heavily influence development opportunities;



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Geography:  Access to supply and demand markets impact the value of a storage facility. Distance to existing pipeline infrastructure, incompatible surface uses and difficulty obtaining title to or the right to use property can all combine to increase the cost and difficulty of developing and operating natural gas storage facilities;



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Development costs:  Costs for new gas storage capacity development have continued to increase:



•

Most of the current installed gas storage capacity was developed prior to 1980 when gas prices were well below $2.00 per MMbtu. With prices reaching multiples of that level in recent years, and paired with lower quality reservoirs that often require higher than historical ratios of cushion to working gas, the cost of new development has increased substantially due to higher cushion gas costs alone; and



•

Increasing costs for oilfield services, equipment, steel, compression and labor have also contributed substantially to higher storage development costs;



•

Long lead times:  It typically takes between three and five years from the time a development prospect is identified until the time cash flow commences due in part to the amount of time required to secure rights to reservoir pore space for subsurface storage and to develop and obtain necessary permits from regulatory authorities; and



•

Specialized skills:  Finding and retaining qualified and skilled natural gas storage professionals is an enormous challenge due to the specialized nature of the skills required.

        New natural gas storage projects are typically built when they are able to garner storage revenues that support their economic development. Over the past fifteen years, the majority of new capacity development has taken place in supply basins. Initially developed by producers to manage fluctuations associated with having excess production and limited market options, supply basins have now become where downstream markets increasingly look to meet their incremental storage requirements. In Alberta, for instance, excess pipeline capacity and a scarcity of downstream storage opportunities have resulted in the supply basin storage's emergence as a competitive alternative to market area storage.

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BUSINESS

Overview

        We are the largest independent owner and operator of natural gas storage assets in North America. We own or contract for approximately 185.5 Bcf of total gas storage capacity. We own the AECO Hub™, which is comprised of two facilities in Alberta, Canada and has approximately 135.0 Bcf of gas storage capacity. In addition, we own the Wild Goose storage facility in northern California with 29.0 Bcf of storage capacity and the Salt Plains storage facility in Oklahoma with 13.0 Bcf of storage capacity. We also contract for 8.5 Bcf of gas storage capacity on a long-term basis from NGPL at cost-of-service based rates that are currently below market rates. 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 organically added 41.3 Bcf of gas storage capacity through expansions, an increase of approximately 29%, at a total cost of approximately $131.0 million (an average of $3.2 million per Bcf).

        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. We believe that our combination of large, high-quality, strategically located storage facilities, access to economically attractive organic growth opportunities, ability to charge market-based rates and an experienced and complete storage business team makes our business difficult to replicate.

        We believe that our relationship with Holdco and the Carlyle/Riverstone Funds will enhance our ability to grow our asset base and cash flow. As the owner of our manager,                                      of our common units, all of our subordinated units and all of our incentive distribution rights, Holdco is incentivized to promote and support the successful execution of our business plan and may offer us development projects in the future although it is not required to do so.

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, 2009, we utilized an average of approximately 92% of our operated capacity for storage services provided to third-party customers, and our third-party storage contracts contributed an average of 68% of our total 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 December 31, 2009 was 3.3 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

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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, 2009, we utilized an average of approximately 78% of our operated capacity for our LTF strategy, and LTF contracts contributed an average of 50% of our total revenue. Our LTF contracts generated average reservation fees of $0.99 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, 2009, we utilized an average of approximately 14% of our operated capacity for our STF strategy, and STF contracts contributed an average of 18% of our total revenue. From inception to March 31, 2009, our STF contracts generated average fees of $1.88 per Mcf.

        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 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.

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        Because many contracts extend beyond the end of a fiscal year and because we generally enter into new or replacement third-party storage contracts several months in advance of the beginning of each fiscal year, we can accurately predict a baseline of revenue and cash flow at the beginning of each fiscal year that we will generate for that year under our third-party storage contracts. Throughout the year, as market conditions allow, we augment this baseline revenue and cash flow by entering into additional STF contracts.

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, 2009, we utilized an average of approximately 8% of our operated capacity for our proprietary optimization strategy, and proprietary optimization revenue, after deducting cost of goods sold, contributed an average of 32% of our total revenue. From inception to March 31, 2009, our proprietary optimization business generated average margins of $3.68 per Mcf ($3.37 on a realized basis before market to market gains and leases 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.

        Sophisticated 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 NYMEX and 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.

        A baseline level of revenue is locked-in with proprietary optimization transactions entered into in advance of, or early in each fiscal year. We add incremental margins throughout the year by entering into additional transactions when market conditions are favorable.

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 90% of the counterparties under our gas storage contracts and proprietary 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.

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Business Strategies

        Our primary objective is to generate stable cash flows sufficient to make the minimum quarterly cash distribution per unit to our unitholders and to increase our cash distributions per unit over time by executing the following strategies:

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Maintaining a flexible portfolio of commercial strategies to optimize profitability.  We strive to enhance our returns through a flexible storage utilization strategy that mixes LTF contracts, STF contracts and proprietary optimization transactions to capture the value of natural gas storage. LTF contracts allow us to collect fees based on the seasonal spread and the option value that customers are willing to pay for gas storage, which is partially a function of volatility or expected volatility in the price of natural gas. STF contracts and proprietary optimization transactions allow us to profit directly from both the seasonal spread and other opportunities that unfold throughout the year. Initial STF contracts and proprietary optimization transactions are entered into in advance of the beginning of each fiscal year, allowing us to lock-in significant revenues at the beginning of each fiscal year. Additional STF contracts and proprietary optimization transactions are entered into throughout the year to lock-in incremental margins from changes in relative prices of natural gas. We have historically contracted and expect to continue to target contracting 80% to 90% of our gas storage capacity under LTF and STF contracts with third party storage customers and utilize the balance for proprietary optimization transactions. The gradual expiration of LTF contracts and the short term duration of STF contracts and proprietary optimization transactions affords us the flexibility to adjust the mix of strategies as necessary to capitalize on market conditions.



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Continuing to expand our existing facilities.  We intend to enhance our profitability and to increase our cash distributions through organic growth at our existing facilities. Since our inception in 2006, we have increased our gas storage capacity by 41.3 Bcf, or approximately 29%, through capital expenditures of approximately $131.0 million. We have near-term projects in progress to expand our existing facilities by an additional 39.0 Bcf, or 21%, with an 18.0 Bcf expansion at AECO Hub™ and a 21.0 Bcf expansion at Wild Goose. We expect that these projects will increase our total working gas capacity by approximately 15.0 Bcf by March 31, 2011, 27.0 Bcf by March 31, 2012, 37.0 Bcf by March 31, 2013 and 39.0 Bcf by March 31, 2014 at a total cost of approximately $175.0 million. Our most economically attractive growth opportunities are expanding our overall capacity and injection and withdrawal capabilities through the enhancement of existing facilities. We are familiar with the geological and structural characteristics of our reservoirs, such as the rock quality, structure, depth, containment and size. In addition, the facilities and equipment that are necessary to inject, store and withdraw gas are already in operation at our existing sites. We believe that additional reservoirs located above, below or adjacent to some of our developed reservoirs have similar lithology, or physical characteristics of rock formation, as our existing reservoirs and can be added-on to existing reservoirs relatively inexpensively.



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Growing through acquisitions of complementary assets and pursuing new and existing development projects.  We intend to pursue accretive acquisitions and new and existing opportunities to develop assets that will enable us to increase our cash distributions to unitholders. In recent years, major independent and integrated oil and gas, power and utility companies and independent developers have sold storage assets in an effort to focus their operations or monetize their investments. We expect that gas storage businesses and assets will continue to become available and believe we are well positioned to take advantage of acquisition opportunities. We intend to seek acquisition and development opportunities in new regions that will provide geographic diversification and in our existing regions where we believe we will be able to realize synergies and operational efficiencies. Holdco is pursuing a potential gas storage development project in western Canada and currently holds rights to build a salt-dome cavern

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gas storage facility in Louisiana and a depleted reservoir in southern Texas. If these projects are developed, Holdco intends to offer us the opportunity to purchase the projects, although it is not obligated to do so. When evaluating acquisitions and new development projects, we look for opportunities that allow us to apply the specialized technical and commercial skills of our management team and staff to increase the capacity utilization or improve the physical performance of the facility.

Competitive Strengths

        We believe that we are well positioned to successfully achieve our primary business objectives and execute our business strategies based upon the following competitive strengths:

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High quality, strategically-located assets.  Our facilities are modern, well-maintained and automated and utilize depleted natural gas reservoirs that have optimal storage characteristics. Such characteristics include high permeability and porosity, and development has been with extensive use of modern horizontal well technology. Our facilities are located in some of the most attractive gas storage locations in North America. For instance, AECO Hub™ is located in the Western Canadian Sedimentary Basin, one of the most important gas producing basins in North America, and is connected to the Alberta System (also known as the Nova Gas Transmissions System) which is an integral part of the TransCanada pipeline system and acts as a hub connecting the WCSB to most major gas markets in the U.S. and Canada. Wild Goose is located in California at the PG&E citygate, providing us and our customers PG&E citygate pricing and liquidity and arbitrage opportunities based upon the state's constrained natural gas supply, mostly from out-of-state, and growing, volatile demand. Salt Plains is located between the prolific Rocky Mountain natural gas supply basin, the growing shale gas plays to the south and east, the U.S. Gulf of Mexico and the important mid-continent market region. The high injection and withdrawal capabilities of our facilities and their location at strategic points along key North American natural gas pipeline networks, provides us and our customers with a high degree of liquidity and opportunities for arbitrage between major natural gas producing and consuming regions. The quality and location of our facilities has helped us to develop our strong reputation for reliability and allowed us to build a base of loyal customers—approximately half of our current customers have been customers of our facilities for at least five years. Additionally each of our facilities operates in a regulatory jurisdiction that affords us substantial flexibility in pursuing commercial strategies.



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Flexible commercial strategies provide relatively stable and predictable cash flows.  Our assets have generated consistent Adjusted EBITDA over the past three fiscal years despite materially different seasonal spreads available at the start of each of those years. Our proven, flexible commercial strategy allows us to adjust our mix of LTF contracts, STF contracts and proprietary optimization transactions, which have demonstrated to be complementary strategies and enable us to maintain or increase our profitability in diverse market environments. A significant portion of our revenue is generated from gas storage contracts continuing from prior years or new contracts that are entered into several months in advance of the beginning of each fiscal year, generating a predictable baseline cash flow.



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Inventory of successful and repeatable expansion projects.  We have organic growth opportunities at our facilities through the application of proven reservoir engineering techniques or the development of adjacent reservoirs. This has been made possible because our ongoing operations have given us a thorough understanding of the characteristics and capabilities of our current reservoirs. By expanding our existing facilities or developing reservoirs that are adjacent to our existing reservoirs we believe we can add working capacity relatively inexpensively and at low risk, providing us with access to cost savings and synergies that are not available to many of our competitors. Since our inception in 2006, we have successfully expanded our gas storage

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capacity organically from 144.2 Bcf to 185.5 Bcf (an increase of 41.3 Bcf, or approximately 29%) through cost-efficient techniques. We are currently applying these proven techniques to further expand our capacity at AECO Hub™ and Wild Goose. In addition, we can increase our storage capacity by expanding into unused reservoirs that are located above, below or adjacent to some of our operating reservoirs. For instance, we currently use only two of the twelve natural gas reservoirs at Wild Goose. These twelve reservoirs are stacked vertically, giving us significant potential for organic expansion. We believe developing some of these reservoirs offers the potential for substantial low risk growth opportunities provided that we receive the necessary regulatory and governmental approvals, that the market can support additional storage capacity and that additional pipeline infrastructure is developed to handle the increased flow of natural gas. We believe the presence of additional opportunities for low-risk growth at each of our operated facilities is a significant competitive advantage.

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Significant barriers to entry.  Many of our competitors seeking to add substantial capacity in the markets where we operate may face significant geographical, marketing, financial, regulatory and logistical difficulties. In particular, there is a scarcity of unexploited reservoirs located near pipeline infrastructure, natural gas supply sources and end-user markets that have the capacity and lithology necessary to store gas economically. In addition, there are development challenges and high upfront capital costs associated with the development of natural gas storage facilities, including obtaining title to land and permits to operate, constructing facilities for injecting, storing and withdrawing gas and meeting high cushion gas requirements. Potential competitors whose operations are subject to governmental regulations that limit the rates they can charge customers may not enter the gas storage business or expand their facilities because the reduced potential for profit may not justify the costs. Additionally, significant industry skills are required to identify, construct and operate successful gas storage facilities, and these skills are uncommon.



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Experienced management and complete storage business team.  We employ one of the natural gas storage industry's most experienced management teams (with an average of over 20 years of experience in the natural gas industry). We are staffed with a comprehensive, in-house team of geologists, reservoir engineers, risk managers, optimizers, marketers, schedulers, accountants, lawyers and regulatory specialists with extensive expertise in natural gas storage operations and development. A comprehensive in-house team provides for continuity of knowledge, cross-functional integration and alignment for successful results. Because we are a user of natural gas storage through our proprietary optimization strategy, our team has a knowledge of the gas storage industry that many of our competitors do not. Our management team and staff have been involved in the development of approximately 285.0 Bcf of gas storage capacity in North America.

Our Assets

        Our owned and operated gas storage facilities consist of AECO Hub™ in Alberta, Canada, our Wild Goose storage facility in northern 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

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and operate, we also contract for storage capacity from NGPL on its pipeline system in the mid-continent. The following table highlights certain important design information about our assets.

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™ has supported customer contracts with cycling service of up to 5.2 times per year. AECO Hub™ is the largest natural gas storage provider in western Canada and the largest independent storage hub in North America. Its location on TransCanada Pipeline's Alberta System with direct access to 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 liquidity.

        AECO Hub™ is located in the Western Canadian Sedimentary Basin, or WCSB, which is the major hydrocarbon basin in Canada and one of the most important gas producing regions in North America. WCSB accounts for more than 95% of annual Canadian natural gas production and approximately 24% of annual North American natural gas production according to the 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. So many transactions were being transacted by storage customers and others at the Suffield facility, that a 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."

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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 wellsites 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 close to 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.

        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 34,000 horsepower. The two reservoirs have total effective working capacity of approximately 55.0 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 about 4.6 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

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year ending March 31, 2011. The weighted average contract life of our LTF storage contracts at AECO Hub™ is 3.6 years but our current customers have been customers of AECO Hub™ for an average of 6.1 years. The largest contract we have at AECO Hub™ is in the fifth 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 26.0 Bcf. We are currently engaged in de-watering activities at AECO Suffield and delta pressuring activities at AECO Countess. We expect that these de-watering and delta pressuring activities will increase the gas storage capacity of AECO Hub™ by up to approximately 9.0 Bcf by March 31, 2011 and 18.0 Bcf by March 31, 2014.

Regulatory

        AECO Hub™ is subject to provincial regulatory jurisdiction. Operations are subject to the regulation of the Alberta ERCB, which must also approve proposed expansions of storage capacity. AECO Hub™ is not subject to active market regulation. With the exception of the utility-owned Carbon storage facility which is in the process of being withdrawn from financial 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 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.

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 an HDMC storage facility, with an average physical cycling capability of 2.5 cycles per year. In the past, Wild Goose has supported customer contracts with cycling service as high as 6.0 times per year. 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 two independent operating storage facilities in northern California. Wild Goose provides natural gas receipt and delivery services at 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

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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 12 gas storage wells that are completed in two depleted natural gas reservoirs. 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 73% of Wild Goose's capacity for the fiscal year ending March 31, 2011. The weighted average contract life of our LTF and STF storage contracts at Wild Goose is 2.4 years, but our current customers have been customers of Wild Goose for an average of 4.4 years.

Historic and Future Expansion

        Since our inception, we have increased the gas storage capacity of Wild Goose by 11.0 Bcf. We have filed applications with the 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 in order to maintain a cyclability of 2.5 times annually. We expect to obtain approval for this expansion during the summer of 2010. Upon receipt of such approval, we expect to quickly increase Wild Goose's gas storage capacity to 35.0 Bcf. In addition, upon receipt of such approval we could then commence the construction necessary to increase the capacity further to 50.0 Bcf as soon as is practicable. We expect that the remaining 15.0 Bcf of capacity will be available by March 31, 2013.

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 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.

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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 delays or unexpected costs, by initially bringing forward development plans that mitigate any environmental impacts to the satisfaction of all responsible agencies and stakeholders. As further evidence of our commitment to safe, efficient and environmentally clean operations, even in such a sensitive locale, Wild Goose has received the State of California—Department of Conservation, Award for Outstanding Oilfield Lease and Facility Maintenance, for five 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 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 Caney/Woodford shales, is also adding significant supply to the mid-continent region, which has the potential to increase demand for gas storage services.

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 33% of Salt Plains' capacity for the 2011 fiscal year. The weighted average contract life of our LTF and STF storage contracts at Salt Plains is 1.9 years, but our current customers have been customers of Salt Plains for an average of 5.6 years. The largest contract we have at Salt Plains is in the second year of a three year term.

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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 are currently assessing the feasibility of such expansion in the future.

Regulatory

        Our Salt Plains intrastate operations are subject to regulation by the OCC. Salt Plains is also authorized to provide interstate storage service under the Natural Gas Policy Act of 1978 and 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 intra and inter-state service and has no restrictions on affiliate interactions.

Environmental

        We are not currently aware of any 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 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 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. The cost-of-service rate that we pay is currently significantly below the market value of such capacity. We have a tariff-based right of first refusal to renew these contracts at NGPL's 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.

        We are able to apply the commercial skills used for our owned and operated facilities to optimize and generate revenues by utilizing our NGPL contract capacity. For example, at November 27, 2009 the approximate value that we could immediately secure by entering into forward commodity contracts was equal to the spread between the forward commodity contracts, which were trading at an average price of $1.15 per dekatherm, or Dth, and the reservation fee that we paid to NGPL of $0.49 per Dth. We expect that this spread will remain positive for the foreseeable future.

Access Gas Services

        In Canada, we have responded to the growing need for commercial, industrial and retail natural gas marketing services by forming Access Gas Services to serve markets in the lower mainland and interior of British Columbia. In 2008, Access Gas Services Ontario was established to serve similar markets in Eastern Canada, and EnerStream Agency Services was formed to provide agency services to natural gas end-users in Eastern Canada.

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Employees

        As of February 16, 2010, we had 126 employees. Our executive officers are employed by AECO Partnership.

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 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.

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, 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 costs 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, you should not rely on such discussion as 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, 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, the Clean Air Act, and the Safe Drinking Water Act, 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,

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

Climate Change

        There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases, or GHG. Legislation has been introduced in Congress that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission "allowances" corresponding to their annual emissions of GHGs. Similar legislation is also being proposed by various states, including California. Depending on the scope of any particular GHG program, either at the state, regional or federal level, 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, which seeks to reduce GHG emissions to 1990 levels by the year 2020, and 80% of 1990 levels by 2050. 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 has been working with stakeholders to design a California cap-and-trade program that is enforceable and meets the requirements of AB 32. On November 24, 2009, the CARB released a preliminary draft regulation for a California cap-and-trade program for public comment. Consistent with AB 32, the CARB must adopt the cap-and-trade regulation by January 1, 2011, and the program itself must begin in 2012. 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 equipment and operations could require us to incur costs to reduce the GHG emissions associated with our operations.

        In addition, in December of 2009, the U.S Environmental Protection Agency, or EPA, issued a final rule declaring that six GHGs, including carbon dioxide and methane, "endanger both the public health and the public welfare of current and future generations." The issuance of this "endangerment finding" allows the EPA to begin regulating GHG emissions under existing provisions of the federal Clean Air Act. In late September and early October of 2009, in anticipation of the issuance of the endangerment finding, the EPA officially proposed two sets of rules regarding possible future regulation of GHG emissions under the CAA, one that would regulate GHG emissions from motor vehicles and the other GHG emissions from large stationary sources such as power plants or industrial facilities. Although it may take the EPA several years to adopt and impose regulations limiting GHG emissions,

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any limitation on such emissions from our equipment and operations could require us to incur costs to reduce the GHG emissions associated with our operations.

        As part of the 2008 Consolidated Appropriations Act, the EPA was required to issue a rule requiring mandatory reporting of GHG emissions above certain thresholds from all sectors of the U.S. economy. The proposed rule included GHG reporting requirements for oil and natural gas systems, or Subpart W, including underground natural gas storage facilities, but the EPA received extensive comments to Subpart W relating to the reporting of fugitive and vented emissions from the oil and gas sector. As a result, Subpart W was not included in the final rule. While EPA may reissue a proposed rule regarding the reporting of GHG emissions from oil and natural gas systems, we do not believe that any such future requirement will have a material adverse affect on our business, financial position or results of operations.

Energy

        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 is 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.

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.

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MANAGEMENT

        

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. 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. See "The Operating Agreement—Votes Required For Certain Matters" for information regarding matters that require unitholder approval.

        Our directors will oversee our operations. Upon the closing of this offering, our board will have six members. Our manager intends to increase the size of our board to eight members following the closing of this offering. Our manager will appoint all members to our board and we expect that, when the size of our board increases to eight directors, at least three of those directors will be independent as defined under the independence standards established by the NYSE.

        In compliance with the requirements of the NYSE, upon the effective date of the registration statement, our manager will have appointed at least one independent member to our board. Our manager will appoint two additional independent members within 12 months of the effective date of the registration statement. The independent members of our board will serve as the initial members of the audit committee of our board. We are not required under NYSE rules to have a nominating/corporate governance committee or compensation committee so long as we are a controlled company, which is defined as a company in which more than 50% of the voting power is held by an individual, a group or another company. As discussed below, we will establish a compensation committee.

        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.

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.

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        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.

Audit Committee

        Our board will establish 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. The audit committee will be composed entirely of independent directors under NYSE listing standards and SEC requirements. The audit committee will have 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. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee.

Compensation Committee

        Our board will establish a compensation committee to, among other things, oversee the compensation plans described below. The compensation committee will establish and review general policies related to our compensation and benefits. The compensation committee will determine and approve, or make recommendations to the board with respect to, the compensation and benefits of our board and executive officers.

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

        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. 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

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that has had various positions in the natural gas industry since 1980. 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.

        Darin T. Olson—Mr. Olson is our Chief Financial Officer. Mr. Olson has served as our Chief Financial Officer since May 2006. 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.

        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 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.

        Paul Amirault—Mr. Amirault is our Senior Vice President. Mr. Amirault has served as our Senior Vice President since May 2006. He began working for Alberta Energy Company Ltd. in 1994 in its marketing and gas storage group and commenced working for EnCana Corporation in 2002 when Alberta Energy Company Ltd. and PanCanadian Petroleum Ltd. merged to form EnCana Corporation. Mr. Amirault graduated from McMaster University in Hamilton, Ontario with a degree in Electrical Engineering and Management.

        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 in 1985.

        Jason S. Kulsky—Mr. Kulsky is our Vice President, Business Development. Mr. Kulsky is currently our Vice President of 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 predecessors, 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.

        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 predecessors, Alberta Energy Company Ltd., respectively, since 2001. He has a Bachelor of Arts in Political Science (Honors) from the University of Calgary and a Bachelor of Laws (LL.B.) from the University of Alberta.

        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. 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.

        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. Mr. Jones is currently a Managing Director of Riverstone

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Holdings LLC where he served as a Principal from 2007 to 2010. Mr. Jones has been with Riverstone Holdings since 2001.

        George 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., 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 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.

        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 of Penn Virginia Corp. since July 2007. 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.

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.

Compensation Discussion and Analysis

        We have been operated as a private company since we acquired our assets in 2006. Since that date, the compensation committee of the board of supervisors of Niska Predecessor, or the predecessor compensation committee, established the compensation of our named executive officers. After the closing of this offering our manager and our board, as its delegate, will manage our operations and activities and will make decisions on our behalf. The compensation of each of our executive officers, including David Pope, Darin Olson, Simon Dupéré, Paul Amirault and Rick Staples (collectively, the "named executive officers"), will be determined 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.

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        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 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. Following the closing of this offering, we expect our compensation committee will 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, 2009 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 the named executive officers with respect to the fiscal year ended March 31, 2009.

Setting Executive Compensation.

        Historically the predecessor compensation committee determined the size, timing and allocation of the bonus based on initial recommendations from our chief executive officer. In addition, the predecessor compensation committee has been responsible for approving any significant changes to executive salaries.

        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, 2009, the compensation for our named executive officers consisted of the following elements:

•

base salary;



•

discretionary cash bonus awards;



•

Niska Holdings Class B and Class C units; 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.

        For the fiscal year ended March 31, 2009, 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). 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. Mr. Pope's salary could 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, the predecessor compensation committee determined that Mr. Pope's current salary continued to be consistent with the duties and the everyday tasks for which he is responsible.

        The predecessor compensation committee also reviewed the base salaries of the remaining named executive officers in connection with setting compensation levels for the year following March 31, 2009.

        Discretionary Bonus Awards.    A significant portion of the compensation of our named executive officers consists of an annual cash bonus. 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 the company. We pay bonuses in three installments each year because we believe that this aids in employee retention. Small advances of the total award are made in September and December and the total award, less the advances, are paid in April.

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        Additionally, there are adverse tax consequences that incent us to make a September advance bonus payment to employees. We accrue for the total yearly bonus each month and hold a portion of that accrued cash over the end of the fiscal year in case of audit adjustments to our financial statements that would have the affect of changing the overall bonus pool. All accrued bonus cash that remains after any audit adjustments is used to fund the advance bonus payment in September. From a Canadian tax perspective, if we did not pay the accrued but unpaid bonus amounts within 180 days of the end of the fiscal year, these amounts would be included as net income and taxed accordingly.

        Historically, we have established a bonus pool for each fiscal year to be allocated among all employees, including the named executive officers. There were 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. At the end of the year, Mr. Pope made recommendations to our compensation committee of individual bonus allocations to all employees, including the named executive officers. These recommendations were based in part on input from various supervisors reporting to Mr. Pope, taking into consideration our results of operations, the individual performance and contributions by our employees and other relevant factors.

        Niska Predecessor Class B and Class C Units.    In 2006, Niska Predecessor issued Class B units to our employees, including the named executive officers, and Class C units to Mr. Pope pursuant to the terms of his employment agreement and Niska Predecessor's partnership agreements. Prior to our acquisition of Niska Predecessor, Niska Holdings will issue identical Class B units and Class C units to the holders thereof. The Class B and Class C units represent 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.

        The Class B and Class C units were granted subject to certain forfeiture restrictions, with the risk of forfeiture set to lapse with respect to half of the units held by each individual upon the passage of set intervals of time and with respect to half upon our meeting Adjusted EBITDA targets.

        The compensation committee of Niska Predecessor did not exercise subjective discretion with regard to the Class B or C units. As of May, 2009, 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.

Other Benefits

        Health and Welfare Benefits.    Pursuant to his 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 also 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.

        Retirement and Pension Benefits.    Our RRSP Plan/Non-Registered Employee Savings Plan provides employees with an opportunity to participate in a retirement savings plan. Our employees, including our named executive officers, 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. The 5% corporate match program was discontinued subsequent to March 31, 2009, at which time all employees received a 5% increase in their base salaries.

        Mr. Pope's prior employer maintained a Supplemental Executive Retirement Plan, or the SERP, which Mr. Pope participated in prior to his employment with us. The SERP was intended to provide

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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. Pursuant to Mr. Pope's 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 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.

        Perquisites.    Our named executives received additional payments to be applied to expenses for home computers, club membership and other personal expenses, as well as a monthly automobile allowance and paid parking at our office facilities.

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

        The following table and footnotes provide information regarding the compensation of the named executive officers during the fiscal year ended March 31, 2009. Compensation to our named executive officers was paid primarily in Canadian dollars, but is reported in U.S. dollars in the tables that follow, using an exchange rate of 0.952 U.S. dollars for each Canadian dollar, the exchange rate on December 31, 2009.

Summary Compensation Table For Year Ended March 31, 2009

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Outstanding Equity at Fiscal Year-End

        The following table shows the total number of outstanding equity awards in the form of Niska Predecessor Class B and Class C units that remained subject to forfeiture as of the end of the fiscal year ended March 31, 2009.

Outstanding Equity Awards at March 31, 2009

Option Exercises and Stock Vested

        The following table presents information regarding the vesting during the fiscal year ended March 31, 2009 of Niska Predecessor Class B and Class C units for the named executive officers. We have not issued any awards in the form of options on our units to any employees, including the named executive officers.

Option Exercises and Stock Vested For Year Ended March 31, 2009

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Potential Payments Upon Change of Control or Termination

        As of March 31, 2009, 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. His employment agreement with the AECO Gas Storage Partnership was executed in August of 2006.

        In the event we terminate Mr. Pope for Just Cause (as defined below), all compensation payments to Mr. Pope would cease. If we terminate Mr. Pope other than for Just Cause, or Mr. Pope terminates his employment for Good Reason (as defined below), Mr. Pope shall receive a cash payment of $900,000 (Canadian dollars) less applicable withholding taxes. Where Mr. Pope voluntarily resigns without Good Reason (including a normal retirement), or his employment relationship is terminated due to death or a mental or physical incapacity, all compensation payments would cease at such time.

        Any payments that Mr. Pope would be entitled to receive upon a termination of employment will be conditioned upon his execution of a general release in our favor. Mr. Pope will also remain 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" is 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.

        "Just Cause" includes (1) any improper conduct by Mr. Pope which is 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 provides for the continuation of Mr. Pope's SERP benefit. See "—Compensation Discussion and Analysis—Other Benefits."

Long-Term Incentive Plan

        General.    We intend to adopt a Long-Term Incentive Plan, or the Plan, for our employees, consultants and directors. The summary of the Plan contained herein does not purport to be complete and is qualified in its entirety by reference to the Plan. The Plan provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and substitute awards. Subject to adjustment for certain events, an aggregate of            common units may be delivered pursuant to awards under the Plan. Units that are cancelled, forfeited or are withheld to satisfy our manager's tax withholding obligations are available for delivery pursuant to other awards.

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The Plan will be administered by our compensation committee. The Plan has been designed to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common unitholders.

        Unit Awards.    Our compensation committee may grant unit awards to eligible individuals under the Plan. A unit award is an award of common units that are fully vested upon grant and not subject to forfeiture.

        Restricted Units and Phantom Units.    A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equal to the fair market value of a common unit. The compensation committee may make grants of restricted units and phantom units under the Plan to eligible individuals containing such terms, consistent with the Plan, as the compensation committee may determine, including the period over which restricted units and phantom units granted will vest. The compensation committee may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest automatically upon a change of control (as defined in the Plan) of us or our manager, subject to any contrary provisions in the award agreement.

        If a grantee's employment, consulting or membership on the board terminates for any reason, the grantee's restricted units and phantom units will be automatically forfeited unless, and to the extent, the award agreement or the compensation committee provides otherwise.

        Distributions made by us with respect to awards of restricted units may, in the discretion of our compensation committee, be subject to the same vesting requirements as the restricted units. Our compensation committee, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units.

        We intend for restricted units and phantom units granted under the Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our manager will receive remuneration for the units delivered with respect to these awards.

        Unit Options and Unit Appreciation Rights.    The Plan also permits the grant of options covering common units and unit appreciation rights. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units as determined by our compensation committee. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the compensation committee may determine, consistent with the Plan; however, a unit option or unit appreciation right must have an exercise price equal to the fair market value of a common unit on the date of grant.

        Distribution Equivalent Rights.    Distribution equivalent rights are rights to receive all or a portion of the distributions otherwise payable on units during a specified time. Distribution equivalent rights may be granted alone or in combination with another award.

        By giving participants the benefit of distributions paid to unitholders generally, grants of distribution equivalent rights provide an incentive for participants to operate our business in a manner that allows us to provide increasing distributions to our unitholders. Typically, distribution equivalent rights will be granted in tandem with a phantom unit, so that the amount of the participant's compensation is tied to both the market value of our units and the distributions that unitholders

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receive while the award is outstanding. We believe this aligns the participant's incentives directly to the measures that drive returns for our unitholders.

        Substitute Awards.    Our compensation committee, in its discretion, may grant substitute or replacement awards to eligible individuals who, in connection with an acquisition made by us, our manager or an affiliate, have forfeited an equity-based award in their former employer. A substitute award that is an option may have an exercise price less than the value of a common unit on the date of grant of the award.

        Source of Common Units.    Common units to be delivered with respect to awards may be common units acquired by our manager on the open market, common units already owned by our manager, common units acquired by our manager directly from us or any other person or any combination of the foregoing. Our manager will be entitled to reimbursement by us for the cost incurred in acquiring common units. With respect to unit options, our manager will be entitled to reimbursement by us for the difference between the cost incurred by our manager in acquiring these common units and the proceeds received from an optionee at the time of exercise. Thus, we will bear the cost of the unit options. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our manager will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash, our manager will be entitled to reimbursement by us for the amount of the cash settlement.

        Amendment or Termination of Long-Term Incentive Plan.    Our board, in its discretion, may terminate the Plan at any time with respect to the common units for which a grant has not theretofore been made. The Plan will automatically terminate on the earlier of the 10th anniversary of the date it was initially approved by our unitholders or when common units are no longer available for delivery pursuant to awards under the Plan. Our board will also have the right to alter or amend the Plan or any part of it from time to time and the compensation committee may amend any award; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant.

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. We anticipate that directors who are not officers, employees or paid consultants and advisors of our manager or its affiliates will receive a combination of cash and restricted common unit grants as compensation for attending meetings of our board and committees thereof. Such 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.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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

•

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



•

each of our directors;



•

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.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

        After this offering, Holdco will own            common units and            subordinated units, representing approximately % of our units. In addition, our manager will own a 2% managing member interest in us and the incentive distribution rights.

Distributions and Payments to Our Manager and Its Affiliates

        The following table summarizes the distributions and payments made or to be made by us to our manager and its affiliates in connection with our formation and ongoing operation and distributions and payments that would be made by us if we were to liquidate in accordance with the terms of our Operating Agreement. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.

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