S-1/A 1 a2198442zs-1a.htm FORM S-1/A

As filed with the Securities and Exchange Commission on April 30, 2010

Registration No. 333-165007

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



Amendment No. 6
to

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



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

Delaware
(State or other jurisdiction of
incorporation or organization)
  4922
(Primary Standard Industrial
Classification Code Number)
  27-1855740
(I.R.S. Employer
Identification Number)

1001 Fannin Street, Suite 2500
Houston, TX 77002
281-404-1890
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)



Jason A. Dubchak
1001 Fannin Street, Suite 2500
Houston, TX 77002
281-404-1890
(Name, address, including zip code, and telephone number, including area code, of agent for service)



Copies to:

Mike Rosenwasser
James J. Fox

Vinson & Elkins L.L.P.
666 Fifth Avenue, 26th Floor
New York, NY 10103
(212) 237-0000

 

Joshua Davidson
Douglass M. Rayburn

Baker Botts L.L.P.
One Shell Plaza
910 Louisiana Street
Houston, TX 77002
(713) 229-1234



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



         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.

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

CALCULATION OF REGISTRATION FEE

       
 
Title of each class of securities
to be registered

  Proposed maximum
aggregate offering
price(1)(2)

  Amount of
registration fee

 

Common units representing limited liability company interests

  $442,750,000   $31,569

 

(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.

(3)
The total registration fee includes $28,699 that was previously paid for the registration of $402,500,000 of proposed maximum aggregate offering price in the filing of the Registration Statement on February 22, 2010, $1,435 for the registration of an additional $20,125,000 of proposed maximum aggregate offering price in the filing of the Registration Statement on April 26, 2010 and $1,435 for the registration of an additional $20,125,000 of proposed maximum aggregate offering price registered hereby.

         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.


Table of Contents

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 April 30, 2010

PRELIMINARY PROSPECTUS

LOGO

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 $20.00 and $22.00 per common unit. Prior to this offering, there has been no public market for our common units. Our common units have been approved for listing on the New York Stock Exchange under the symbol "NKA."

          Investing in our common units involves risks. See "Risk Factors" beginning on page 17.

          These risks include the following:

    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.

    Niska Sponsor Holdings Coöperatief U.A., which we refer to as Holdco, currently controls, and after this offering will continue to control, 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.

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

    You will experience immediate and substantial dilution of $17.84 in our pro forma tangible net book value per common unit.

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

 
  Per Common Unit   Total  

Initial public offering price

  $     $    

Underwriting discount(a)

  $     $    

Proceeds to Niska Gas Storage Partners LLC (before expenses)

  $     $    

(a)
Excludes a structuring fee equal to 0.375% of the gross proceeds from this offering (excluding any proceeds from the exercise of the option to purchase additional units) payable to Goldman, Sachs & Co. and Morgan Stanley & Co. Incorporated.

          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.



Joint Book-Running Managers

Goldman, Sachs & Co.   Morgan Stanley

Barclays Capital   Citi   Credit Suisse

RBC Capital Markets   UBS Investment Bank



Raymond James   Wells Fargo Securities



Lazard Capital Markets   Stifel Nicolaus



                        , 2010


Table of Contents

GRAPHIC


TABLE OF CONTENTS

PROSPECTUS SUMMARY

  1
 

Niska Gas Storage Partners LLC

  1
 

Overview

  1
 

Our Operations

  2
 

Our Assets

  2
 

Business Strategies

  3
 

Competitive Strengths

  3
 

Our Relationship With Holdco

  3
 

Formation Transactions

  4
 

Recent Refinancing Transactions

  5
 

Recent Capital Contribution and Contemplated Distribution

  5
 

Management

  5
 

Ownership of Niska Gas Storage Partners LLC

  6
 

Principal Executive Offices and Internet Address

  8
 

Summary of Conflicts of Interest and Fiduciary Duties

  8
 

The Offering

  9
 

Summary Historical and Pro Forma Financial and Operating Data

  13
 

Non-GAAP Financial Measure

  15

RISK FACTORS

  17
 

Risks Inherent in Our Business

  17
 

Risks Inherent in an Investment in Us

  28
 

Tax Risks to Common Unitholders

  36

USE OF PROCEEDS

  42

CAPITALIZATION

  43

DILUTION

  45

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

  47
 

General

  47
 

Minimum Quarterly Distribution

  48
 

Unaudited Pro Forma Cash Available for Distribution

  50
 

Estimated Cash Available for Distribution

  53
 

Assumptions and Considerations

  56
 

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

  58

PROVISIONS OF OUR OPERATING AGREEMENT RELATING TO CASH DISTRIBUTIONS

  59
 

Distributions of Available Cash

  59
 

Operating Surplus and Capital Surplus

  59
 

Subordination Period

  63
 

Distributions of Cash From Operating Surplus During the Subordination Period

  64
 

Distributions of Cash From Operating Surplus After the Subordination Period

  64
 

Managing Member Interest

  64
 

Incentive Distribution Rights

  64
 

Percentage Allocations of Cash Distributions From Operating Surplus

  65
 

Distributions From Capital Surplus

  65
 

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

  66
 

Distributions of Cash Upon Liquidation

  67

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

  69
 

Non-GAAP Financial Measure

  72

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

  74
 

How We Evaluate Our Operations

  74
 

Factors that Impact Our Business

  76
 

Comparability of Our Financial Statements

  77
 

Results of Operations

  78

i


 

Liquidity and Capital Resources

  87
 

Quantitative and Qualitative Disclosures About Market Risks

  97
 

Risk Management Policy and Practices

  99
 

Segment Information

  100
 

Critical Accounting Estimates

  100
 

Recent Accounting Pronouncements

  104

NATURAL GAS STORAGE INDUSTRY

  106
 

Overview of the Natural Gas Value Chain

  106
 

Natural Gas Storage Reservoir Types

  109
 

Natural Gas Storage Value Drivers for Market Based Storage Services

  110
 

Fundamental Industry Trends

  112

BUSINESS

  118
 

Overview

  118
 

Our Operations

  118
 

Business Strategies

  121
 

Competitive Strengths

  122
 

Competition

  124
 

Our Assets

  124
 

Employees

  130
 

Regulation

  130
 

Legal Proceedings

  133
 

Taxation

  133

MANAGEMENT

  137
 

Management of Niska Gas Storage Partners LLC

  137
 

Directors and Executive Officers

  139
 

Reimbursement of Expenses of Our Manager

  141
 

Compensation Discussion and Analysis

  142
 

Executive Compensation

  145
 

Summary Compensation for Years Ended March 31, 2009 and 2010

  145
 

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

  146
 

Option Exercises and Stock Vested

  146
 

Potential Payments Upon Change of Control or Termination

  147
 

Long-Term Incentive Plan

  147
 

Director Compensation

  149

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

  150

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

  151
 

Distributions and Payments to Our Manager and Its Affiliates

  151
 

Agreements Governing the Transactions

  152
 

Services Agreement

  152
 

Registration Rights Agreement

  152
 

Recent Capital Contribution and Contemplated Distribution

  152

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

  153
 

Conflicts of Interest

  153
 

Fiduciary Duties

  158

DESCRIPTION OF THE COMMON UNITS

  161
 

The Units

  161
 

Transfer Agent and Registrar

  161
 

Transfer of Common Units

  161

THE OPERATING AGREEMENT

  163
 

Organization and Duration

  163
 

Purpose

  163
 

Capital Contributions

  163
 

Votes Required For Certain Matters

  164
 

Applicable Law; Forum, Venue and Jurisdiction

  165
 

Limited Liability

  165
 

Issuance of Additional Membership Interests

  166

ii


 

Amendment of Our Operating Agreement

  166
 

Merger, Sale or Other Disposition of Assets

  169
 

Dissolution

  169
 

Liquidation and Distribution of Proceeds

  170
 

Withdrawal or Removal of Our Manager

  170
 

Transfer of Managing Member Interest

  171
 

Transfer of Ownership Interests in Our Manager

  171
 

Transfer of Subordinated Units and Incentive Distribution Rights

  171
 

Change of Management Provisions

  172
 

Limited Call Right

  172
 

Meetings; Voting

  173
 

Voting Rights of Incentive Distribution Rights

  173
 

Status as Member

  174
 

Non-Citizen Assignees; Redemption

  174
 

Non-Taxpaying Assignees; Redemption

  174
 

Indemnification

  175
 

Reimbursement of Expenses

  175
 

Books and Reports

  175
 

Right to Inspect Our Books and Records

  176
 

Registration Rights

  176

UNITS ELIGIBLE FOR FUTURE SALE

  177

MATERIAL U.S. TAX CONSEQUENCES TO UNITHOLDERS

  178
 

Taxation of Niska Gas Storage Partners LLC

  179
 

U.S. Federal Income Taxation of Unitholders

  179
 

Tax Treatment of Operations

  185
 

Disposition of Common Units

  186
 

Uniformity of Units

  189
 

Non-U.S. Investors

  189
 

Tax-Exempt Organizations

  190
 

Administrative Matters

  191
 

State and Local Taxation of Unitholders

  193

MATERIAL CANADIAN FEDERAL INCOME TAX CONSEQUENCES TO UNITHOLDERS

  194
 

Taxation of Niska Gas Storage Partners LLC

  195
 

Taxation of Unitholders Resident in the United States

  195
 

Taxation of Unitholders Resident in Canada

  196

INVESTMENT IN NISKA GAS STORAGE PARTNERS LLC BY EMPLOYEE BENEFIT PLANS

  199

UNDERWRITING

  201

VALIDITY OF THE COMMON UNITS

  206

EXPERTS

  206

WHERE YOU CAN FIND MORE INFORMATION

  207

FORWARD-LOOKING STATEMENTS

  208

INDEX TO FINANCIAL STATEMENTS

  F-1

APPENDIX A—FORM OF FIRST AMENDED AND RESTATED OPERATING AGREEMENT OF NISKA GAS STORAGE PARTNERS LLC

  A-1

APPENDIX B—GLOSSARY OF SELECTED TERMS

  B-1

        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.

iii


Table of Contents


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. This summary provides an overview of the key aspects of this offering and you should read the entire prospectus carefully, including "Risk Factors" beginning on page 17 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 $21.00 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 a Delaware limited liability company formed to own and operate natural gas storage assets. We own or contract for approximately 185.5 billion cubic feet, or Bcf, of total gas storage capacity. Our assets are located in key North American natural gas producing and consuming regions and are connected at strategic points on the gas transmission network, providing access to multiple end-use markets. Our locations provide us and our customers with substantial liquidity, meaning access to multiple counterparties for transactions to buy and sell gas. Since our inception in 2006, we have 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). We are the largest independent owner and operator of natural gas storage assets in North America, based on our analysis of working gas capacity owned by other storage owners, adjusted according to each such owner's percentage ownership of its respective storage facilities.

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


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 contracts 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. 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. 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 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.


Our Assets

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

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Table of Contents


supporting the working gas. The size and flexibility of our facilities, together with the application of advanced skills in reservoir engineering, drilling, geology and geophysics, enable us to support individual high-cycle contracts in excess of the average physical cycling capabilities of our facilities. In addition to the facilities we own and operate, we also contract for 8.5 Bcf of gas storage capacity on a long-term basis from Natural Gas Pipeline Company of America LLC, or NGPL, on its pipeline system in the mid-continent at cost-of-service based rates that we believe are currently below market rates. The following table highlights certain important design information about our assets.

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

Gas Storage Capacity (Bcf)

    80.0     55.0     29.0     13.0     8.5     185.5  

Peak Withdrawal (MMcf per day)

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

In Service Date

    1988     2003     1999     1995     N/A     1988 – 2003  


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:

    Maintaining a flexible portfolio of commercial strategies to optimize profitability;

    Continuing to expand our existing facilities; and

    Growing through acquisitions of complementary assets and pursuing new and existing development projects.


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:

    High quality, strategically-located assets;

    Flexible commercial strategies provide relatively stable and predictable cash flows;

    Inventory of successful and repeatable expansion projects;

    Significant barriers to entry; and

    Experienced management and complete storage business team.

        For a more detailed description of our business strategies and competitive strengths, see "Business—Business Strategies" and "—Competitive Strengths." However, our business is subject to significant competition. See "Risk Factors—Risks Inherent in Our Business—We face significant competition that may cause us to lose market share, negatively affecting our business" and "Business—Competition."


Our Relationship With Holdco

        After this offering, Holdco will own our manager, approximately 48.2% of our outstanding 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 storage facility 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.

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Table of Contents

        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 $13.6 billion to 69 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, approximately 48.2% of our outstanding 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.


Formation Transactions

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

    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;

    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 us;

    we will borrow $279.6 million under our revolving credit facilities and will use the proceeds to pay a distribution to US Holdings and Canada Holdings, collectively referred to as Niska Holdings;

    we will issue 4,787,911 common units, 11,831,661 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;

    we will issue 8,891,834 common units, 21,973,084 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;

    US Holdings and Canada Holdings will, through a series of steps, contribute to Holdco the common units, subordinated units, incentive distribution rights and interests that will become a 2% managing member interest in us;

    Holdco will contribute to our manager the interests that will become a 2% managing member interest in us; and

    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.

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Recent Refinancing Transactions

    Non-Public Offering of Senior Notes by Niska US and Niska Canada

        On March 5, 2010, Niska US and Niska Canada closed a non-public offering of 800,000 units, each unit consisting of $218.75 principal amount of 8.875% senior notes due 2018 of Niska US and $781.25 principal amount of 8.875% senior notes of Niska Canada. The units were sold in an offering exempt from registration under the Securities Act of 1933, as amended, or the Securities Act, to qualified institutional investors in reliance on Rule 144A under the Securities Act and to non-U.S. persons in offshore transactions in reliance on Regulation S under the Securities Act. Niska US and Niska Canada received net proceeds of approximately $782 million in the aggregate from the offering, after deducting initial purchasers' commissions. Niska Predecessor used the net proceeds from the offering to pay a distribution to Niska Holdings, pay expenses associated with our new credit facilities and repay Niska Predecessor's syndicated term loans and previous revolving credit facilities. References in this prospectus to "our senior notes" refer to the 8.875% senior notes due 2018 of Niska US and Niska Canada. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our 8.875% Senior Notes Due 2018."

    Our New $400.0 Million Credit Agreement

        Concurrently with the closing of the non-public offering of units, Niska US and AECO Gas Storage Partnership, or the AECO Partnership, entered into a new agreement providing for senior secured asset-based revolving credit facilities, and we terminated our previous credit agreement. The new credit facilities provide for a maximum borrowing capacity of $400.0 million, which is available for general purposes, including working capital, economically hedged inventory purchases and capital expenditures. Borrowings under these credit facilities are limited to a borrowing base which will be redetermined from time to time, and is based primarily on our receivables, our economically hedged inventory of proprietary gas and certain of our fixed assets. We may only borrow up to the lesser of the level of our then current borrowing base and $400.0 million. Our borrowing base is currently $460.0 million. References in this prospectus to "our new credit facilities" or "our $400.0 million credit agreement" refer to the credit agreement and credit facilities, respectively, of the AECO Partnership and Niska US. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our $400.0 Million Credit Agreement."


Recent Capital Contribution and Contemplated Distribution

        On January 25, 2010, the holders of Niska Predecessor's Class A units made a contribution to the capital of Niska Predecessor of $18 million in order to fund capital expenditures limited by the previous credit facility. On April 16, 2010, Niska Holdings paid a cash distribution of approximately $25 million to the holders of its Class A units, and prior to the closing of this offering, we expect that Niska Holdings will pay the holders of its Class A units an additional $20 million cash distribution.


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

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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

Public Common Units

    25.4 %(a)

Common Units held by Holdco

    23.6 %(a)

Subordinated Units held by Holdco

    49.0 %

Incentive Distribution Rights

          (b)

Managing Member Interest

    2.0 %
       

Total

    100 %
       

(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. See "Provisions of Our Operating Agreement Relating to Cash Distributions—Incentive Distribution Rights." Distributions in respect of the incentive distribution rights will be classified as distributions in respect of equity interests.

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

GRAPHIC

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Principal Executive Offices and Internet Address

        Our principal executive offices are located at 1001 Fannin Street, Suite 2500, Houston, TX 77002, and our telephone number is 281-404-1890. Our website will be located at http://www.niskapartners.com 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 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's 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

Common units offered to the public

  17,500,000 common units.

Common units subject to the underwriters' option to purchase additional common units

 

If the underwriters exercise their option to purchase additional common units in full, we will issue 2,625,000 additional common units to the public.

Units outstanding after this offering

 

33,804,745 common units and 33,804,745 subordinated 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.

Use of proceeds

 

We estimate that the net proceeds from this offering will be approximately $339.6 million after deducting approximately $27.9 million of underwriting discounts and structuring fees (based on an assumed initial public offering price of $21.00 per common unit) and expenses. We intend to use approximately $279.6 million of the net proceeds of this offering to fully repay all borrowings under our revolving credit facilities and the remainder for general company purposes, including to fund a portion of the cost of our expansion projects. The borrowings under our revolving credit facilities will be used to fund a distribution to Holdco in partial consideration for the assets contributed to us in connection with the closing of this offering.

 

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

Cash distributions

 

We expect to make a minimum quarterly distribution of $0.35 per common unit ($1.40 per common unit on an annualized basis) to the extent we have sufficient cash after the establishment of cash reserves by our board of directors in its discretion and the payment of fees and expenses. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption "Our Cash Distribution Policy and Restrictions on Distributions."

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We will pay investors in this offering a prorated distribution for the first quarter during which we are a publicly-traded company. Such distribution will cover the period from the closing date of this offering to and including June 30, 2010. We expect to pay this cash distribution before August 14, 2010.

 

Our Operating Agreement generally provides that we distribute cash each quarter in the following manner:

 

•       first, 98% to the holders of common units and 2% to our manager, until each common unit has received the minimum quarterly distribution of $0.35 plus any arrearages from prior quarters;

 

•       second, 98% to the holders of subordinated units and 2% to our manager, until each subordinated unit has received the minimum quarterly distribution of $0.35; and

 

•       third, 98% to all unitholders, pro rata, and 2% to our manager, until each unit has received a distribution of $0.4025.

 

If cash distributions to our unitholders exceed $0.4025 per unit in any quarter, the holders of our incentive distribution rights will receive increasing percentages, up to 48%, of the cash we distribute in excess of that amount. We refer to these distributions as "incentive distributions."

 

See "Provisions of Our Operating Agreement Relating to Cash Distributions."

 

We believe that, based on the assumptions and considerations included in "Our Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations," we will have sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our common and subordinated units for the fiscal year ending March 31, 2011. We estimate that our pro forma cash available for distribution for the fiscal year ended March 31, 2009 and the twelve months ended December 31, 2009 would have been sufficient to pay the full minimum quarterly distribution on all of our common and subordinated units. See "Our Cash Distribution Policy and Restrictions on Distributions."

Subordinated units

 

Holdco will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution of $0.35 per unit only after the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. If we do not pay distributions on our subordinated units, our subordinated units will not accrue arrearages for those unpaid distributions.

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Subordination period

 

If we meet three requirements set forth in our Operating Agreement, the subordination period will end and all subordinated units will convert into common units on a one-for-one basis. The three requirements are:

 

•       we must make quarterly distributions from operating surplus of at least the minimum quarterly distribution on all outstanding common and subordinated units in respect of each of the prior twelve consecutive quarters;

 

•       our aggregate 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) must equal or exceed the aggregate amount of distributions made in respect of such quarters; and

 

•       the conflicts committee of our board, or our board based on the recommendation of the conflicts committee, must determine that it is more likely than not that we will be able to maintain or increase our quarterly distribution per unit from operating surplus for the four succeeding quarterly distributions.

 

Our 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.

 

The subordination period also 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.

 

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages. See "Provisions of Our Operating Agreement Relating to Cash Distributions—Subordination Period."

Issuance of additional units

 

We can issue an unlimited number of units, including units senior to the common units, without the consent of our unitholders. See "Units Eligible for Future Sale" and "The Operating Agreement—Issuance of Additional Membership Interests."

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Limited voting rights

 

Our manager or our board will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our manager or our directors on an annual or other continuing basis. Our manager may not be removed except by a vote of the holders of at least 662/3% of our outstanding units, including any units owned by our manager and its affiliates (including Holdco), voting together as a single class. Upon completion of this offering, Holdco will own an aggregate of approximately 74.1% of our common and subordinated units. This will give Holdco the ability to prevent removal of our manager. See "The Operating Agreement—Withdrawal or Removal of Our Manager."

Limited call right

 

If at any time our manager and its affiliates own more than 80% of the then outstanding common units, our manager will have the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our manager or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. See "The Operating Agreement—Limited Call Right."

Estimated ratio of taxable income to
distributions

 

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2012, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.40 per common unit, we estimate that your average allocable taxable income per year will be no more than $0.28 per common unit. See "Material U.S. Tax Consequences to Unitholders—U.S. Federal Income Taxation of Unitholders—Ratio of Taxable Income to Distributions."

Material tax consequences

 

For a discussion of certain material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States or Canada, see "Material U.S. Tax Consequences to Unitholders" and "Material Canadian Federal Income Tax Consequences to Unitholders."

Agreement to be bound by Operating Agreement

 

By purchasing a common unit, you will be admitted as a unitholder and will have agreed to be bound by all of the terms of our Operating Agreement.

Exchange listing

 

Our common units have been approved for listing on the NYSE under the symbol "NKA."

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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 GS Holdings I, L.P. and Niska GS Holdings II, L.P. 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. In connection with 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 non-public offering of our senior notes, 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.

 
   
   
   
   
   
  Niska Gas
Storage
Partners
LLC
 
 
  Niska Predecessor   Pro Forma  
 
  Period from
May 12,
2006 to
March 31,

   
   
  Nine Months Ended
December 31,
   
 
 
  Year Ended March 31,   Nine Months
Ended
December 31,
2009
 
 
  2007(a)   2008   2009   2008   2009  
 
   
   
   
  (unaudited)
   
  (unaudited)
 
 
   
  (dollars in millions)
 

Combined Statement of Earnings and Comprehensive Income Data:

                                     

Revenues:

                                     
 

Long-term contract revenue

  $ 104.5   $ 121.4   $ 110.7   $ 85.9   $ 81.9   $ 81.9  
 

Short-term contract revenue

    32.1     35.5     52.0     32.8     39.9     39.9  
 

Optimization revenue, net(b)

    57.2     76.0     89.4     92.9 (c)   27.9 (c)   27.9 (c)
                           

  $ 193.8   $ 232.9   $ 252.2   $ 211.6   $ 149.7   $ 149.7  

Expenses (Income):

                                     
 

Operating expenses

  $ 28.8   $ 44.6   $ 45.4   $ 34.5   $ 28.4   $ 28.4  
 

General and administrative expenses

    19.9     30.1     24.2     20.4     21.5     20.9  
 

Depreciation and amortization

    46.6     42.5     54.8     43.4     32.9     32.9  
 

Interest expense

    60.2     73.9     53.5     43.5     20.1     62.2  
 

Impairment of assets

        2.5     24.1 (d)            
 

Loss/(gain) on sale of assets

        2.3         0.7          
 

Other income

    (0.4 )   (0.7 )   (20.8) (e)   (0.4 )   (0.1 )   (0.1 )
 

Foreign exchange (gains)/losses

    (2.6 )   (7.2 )   (25.8 )   (16.0 )   (8.2 )   (8.2 )
                           
 

Earnings before income taxes

  $ 41.4   $ 45.0   $ 96.9   $ 85.4   $ 55.0   $ 13.6  

Income tax expense/(benefit):

                                     
 

Current

        0.3     0.3     0.3     0.2     0.2  
 

Deferred

    (12.1 )   (3.7 )   (12.2 )   (15.7 )   51.6     40.7  
                           

    (12.1 )   (3.4 )   (11.9 )   (15.4 )   51.8     40.9  
                           

Net earnings/(loss) and comprehensive income for the period ended

 
$

53.5
 
$

48.3
 
$

108.8
 
$

100.8
 
$

3.2
 
$

(27.3

)
                           

Balance Sheet Data (at period end):

                                     

Total assets

  $ 1,931.1   $ 1,905.2   $ 2,002.9   $ 2,107.5   $ 2,071.0   $ 2,083.8  

Property, plant and equipment, net of depreciation

    976.5     955.7     940.2     951.0     974.3     951.1  

Long-term debt(f)

    773.6     693.8     597.0     688.6     593.0     800.0  

Total partners'/members' capital

    820.5     867.1     977.4     930.2     969.2     862.3  

Other Financial Data (unaudited):

                                     

Adjusted EBITDA

  $ 148.0   $ 156.7   $ 162.1   $ 113.1   $ 145.0   $ 145.7  

Maintenance capital expenditures(g)

    0.3     1.7     1.4     1.0     0.8     0.8  

Expansion capital expenditures(g)

    27.4     35.8     17.6     16.5     46.0     45.7  

Operating Data (unaudited):

                                     

Effective working gas capacity (Bcf)(h)

    144.2     155.3     163.7     163.7     185.5     185.5  

Capacity added during period (Bcf)

        11.1     8.4     8.4     21.8     21.8  

Percent of total capacity contracted to third parties

    91.3 %   84.9 %   85.1 %   85.1 %   75.9 %   75.9 %

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

(b)
Optimization revenues are presented net of cost of goods sold.

(c)
Net optimization revenues include unrealized risk management gains/losses and write-downs of inventory. We had an unrealized risk management loss of $45.3 million for the nine months ended December 31, 2009 and an unrealized risk management gain of $93.8 million for the nine months ended December 31, 2008. We had a write-down of inventory of $50.1 million for the nine months ended December 31, 2008, compared to zero for the nine months ended December 31, 2009. Excluding these non-cash items, which do not affect Adjusted EBITDA, our realized optimization revenues were

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$73.2 million for the nine months ended December 31, 2009 compared with $49.3 million for the nine months ending December 31, 2008.

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

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

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

(g)
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, or other capital expenditures that are incurred in maintaining existing operating capacity of our assets. 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.

(h)
Represents operated and NGPL capacity.

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.

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

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

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

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

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

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

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

 
   
   
   
   
   
  Niska Gas
Storage
Partners
LLC
 
 
  Niska Predecessor   Pro Forma  
 
  Period from
May 12,
2006 to
March 31,

   
   
  Nine Months Ended
December 31,
   
 
 
  Year Ended March 31,   Nine Months
Ended
December 31,
2009
 
 
  2007(a)   2008   2009   2008   2009  
 
   
   
   
  (unaudited)
   
  (unaudited)
 
 
  (dollars in millions)
 

Reconciliation/(loss) of Adjusted EBITDA to net income:

                                     

Net earnings/(loss)

  $ 53.5   $ 48.3   $ 108.8   $ 100.8   $ 3.2   $ (27.3 )

Add/(deduct):

                                     
 

Interest expense

    60.2     73.9     53.5     43.5     20.1     62.2  
 

Income tax expense/(benefit)

    (12.1 )   (3.4 )   (11.9 )   (15.4 )   51.8     40.9  
 

Depreciation and amortization

    46.6     42.5     54.8     43.4     32.9     32.9  
 

Unrealized risk management losses/(gains)

    2.8     (1.5 )   (82.8 )   (93.8 )   45.3     45.3  
 

Foreign exchange losses/(gains)

    (2.6 )   (7.2 )   (25.8 )   (16.0 )   (8.2 )   (8.2 )
 

Loss/(gain) on sale of assets

        2.3         0.7          
 

Impairment of assets

        2.5     24.1              
 

Other income

    (0.4 )   (0.7 )   (20.8 )   (0.4 )   (0.1 )   (0.1 )
 

Unrealized inventory impairment writedown

            62.3     50.1          
                           

Adjusted EBITDA

  $ 148.0   $ 156.7   $ 162.1   $ 113.1   $ 145.0   $ 145.7  
                           

(a)
Data includes Wild Goose from November 16, 2006 to March 31, 2007.

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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 $0.35 per unit, or $1.40 per unit per year, which will require cash of approximately $24.1 million per quarter, or $96.6 million per year, based on the number of common and subordinated units 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 that are influenced by, among other things, weather and the seasonality and volatility of natural gas demand and supply:

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

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

    technical and operating performance at our facilities;

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

    nonpayment or other nonperformance by our customers.

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

    the level of capital expenditures we make;

    the cost of acquisitions that we make, if any;

    our debt service requirements;

    fluctuations in interest rates and currency exchange rates;

    fluctuations in our working capital needs;

    our ability to borrow funds and access capital markets;

    restrictions on distributions contained in debt agreements;

    the amount of cash reserves established by our board;

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    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;

    increased competition for storage in the markets we serve; and

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

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        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 demand periods or ability for significant demand to quickly switch to alternative fuels at peak times would represent alternatives to gas storage.

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

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

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

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

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

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

    unanticipated equipment failures at our facilities;

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

    damage from construction and farm equipment or other surface uses;

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

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

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

    operator error; and

    environmental pollution or release of toxic substances.

        These risks could result in substantial losses due to breaches of our contractual commitments, personal injury or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our operations. In addition, operational interruptions or disturbances, mechanical malfunctions, faulty measurements or other acts, omissions, or errors may result in significant costs or lost revenues. Gas that moves outside

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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.

        On March 5, 2010 Niska US and Niska Canada closed a non-public offering of $800.0 million principal amount of units, consisting of the 8.875% senior notes due 2018 of Niska US and Niska Canada. In connection with the offering of units, we entered into a new credit agreement providing for senior secured asset-based revolving credit facilities with a maximum borrowing capacity of up to $400.0 million that will be available for general purposes, including working capital, economically hedged inventory purchases and capital expenditures. In addition, we have the ability to incur additional debt, subject to limitations in our $400.0 million credit agreement and the indenture governing our senior notes. As of April 26, 2010 we had no drawings under our revolving credit facilities and had $3.5 million in letters of credit issued. 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 facilities will depend on market interest rates because the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or terminating distributions and reducing or delaying our business activities, acquisitions, investments or capital expenditures. In addition, we may take actions such as selling assets, restructuring or refinancing our debt or seeking additional equity capital although we may not be able

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to effect any of these actions on satisfactory terms, or at all. Our inability to obtain additional financing on terms favorable to us or our inability to service our debt could have a material adverse effect on our business, results of operations, financial condition and ability to pay distributions. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

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

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

    make distributions;

    incur additional indebtedness or guarantee other indebtedness;

    grant liens or make certain negative pledges;

    make certain loans or investments;

    engage in transactions with affiliates;

    make any material change to the nature of our business;

    make a disposition of assets; or

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

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

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

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

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

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

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. 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 revolving credit facilities 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.

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.

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        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 this determination, for instance as a result of a complaint, we could be limited to charging rates based on our cost of providing service plus a reasonable rate of return, which could have an adverse impact on our revenues associated with providing storage services. 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 Federal Energy Regulatory Commission, or FERC, regulations and policies

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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 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

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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 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.

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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 currently controls, and after this offering will continue to control, 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 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;

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    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 $50.0 million from capital sources, including on the incentive distribution rights, without treating such distribution as a distribution from capital;

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

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

        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

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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;

    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

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    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 $17.84 in our pro forma tangible net book value per common unit.

        The estimated initial public offering price of $21.00 per unit exceeds our pro forma net tangible book value of $3.16 per unit. Based on the estimated initial public offering price of $21.00 per unit, you will incur immediate and substantial dilution of $17.84 per common unit. 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 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.

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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 74.1% of our outstanding common and subordinated units. Accordingly, our public unitholders are currently unable to remove our manager without Holdco's 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 the holders of the subordinated units or their affiliates are voted in favor of that removal, all subordinated units held by our manager and its affiliates will automatically be converted into common units. If no units held by any holder of subordinated units or its affiliates are voted in favor of that removal, all subordinated units will convert automatically into common units and any existing arrearages on the common units will be extinguished. A removal of our manager under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met the tests specified in our Operating Agreement. Cause is narrowly defined in our Operating Agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our manager liable for actual fraud or willful misconduct in its capacity as our manager. Cause does not include most cases of poor management of the business.

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

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

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

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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 48.2% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than for the conversion of the subordinated units into common units), our manager and its affiliates will own approximately 74.1% 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;

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    future sales of our common units; and

    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 33,804,745 common units and 33,804,745 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 16,304,745 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 Goldman, Sachs & Co. and Morgan Stanley & Co. Incorporated. 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 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.

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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 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, 2011 (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 "Business—Taxation," "Material U.S. Tax Consequences to Unitholders" and "Material Canadian Federal Income Tax Consequences to Unitholders" 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

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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 our common units. For additional discussion regarding the importance of our treatment as a partnership, see "Business—Taxation—U.S. Taxation" and "Material U.S. Tax Consequences to Unitholders—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 "Business—Taxation" and "Material Canadian Federal Income Tax Consequences to Unitholders—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 to Unitholders—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."

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

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

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

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

        The present tax treatment of publicly-traded partnerships, companies with multinational operations, or an investment in such entities as Niska Gas Storage Partners LLC is complex and may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the 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 with respect to our treatment as a partnership for U.S. federal income tax purposes. We have sought, but have not yet received, an Advance Tax Ruling from the Dutch tax authority regarding the taxation of our Dutch subsidiary. 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, Medicare 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.

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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 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 to Unitholders—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 to Unitholders—Non-U.S. Investors" and "Material U.S. Tax Consequences to Unitholders—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 to Unitholders—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

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existing Treasury Regulations. Recently, however, the Department of the Treasury issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although existing publicly-traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Moreover, our method of proration differs from the proposed Treasury Regulations with respect to allocations of certain items of income and loss. Our counsel has not rendered an opinion regarding the validity of our proration method. See "Material U.S. Tax Consequences to Unitholders—Disposition of Common Units—Allocations Between Transferors and Transferees."

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

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

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

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

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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 to Unitholders—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, Oklahoma and Texas. Each of California and Oklahoma currently imposes a personal income tax on individuals. Many states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is 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 $339.6 million after deducting approximately $23.9 million of underwriting discounts and structuring fees and $4.0 million in expenses. We intend to use approximately $279.6 million of the net proceeds of this offering to fully repay all borrowings under our revolving credit facilities, and the remainder for general company purposes, including to fund a portion of the cost of our expansion projects.

        We currently have no borrowings outstanding under our revolving credit facilities. We expect that the amount outstanding under our revolving credit facilities immediately prior to the closing of this offering will be $279.6 million. All such borrowings under our revolving credit facilities will be used to fund a distribution to Holdco as partial consideration for Niska Holdings' contribution of Niska US and Niska Canada to us and for working capital. Our revolving credit facilities have a maturity date of March 5, 2014. Affiliates of the underwriters participating in this offering are lenders under our revolving credit facilities 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 $21.00 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 estimated underwriting discounts, structuring fees and expenses to increase or decrease by $16.4 million. If the proceeds increase due to a higher initial public offering price, we will increase the amount of the borrowings in order to increase the distribution to Holdco and repay such increased borrowings with the additional proceeds. 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 the non-public offering of our senior notes and the application of the net proceeds therefrom, the concurrent termination of our previous credit facilities and interest rate swaps relating to our previous term loans 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 issuance of common units in this offering and 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."

 
  As of December 31, 2009  
 
  Historical   As Adjusted   As Further
Adjusted
 
 
  (in thousands)
 

Cash and cash equivalents

  $ 37,964   $ 26,389   $ 59,389  
               

Previous revolving credit facilities(1)

   
190,000
   
   
 
 

Overdraft

    473          

New revolving credit facilities(2)

        115,000     115,000  

Long-term debt:

                   
 

Term loan(1)

    592,526          
 

8.875% senior notes due 2018

        800,000     800,000  
               
   

Total debt

  $ 782,999   $ 915,000   $ 915,000  
               

Equity:

                   
 

Limited Partner Interests of Niska Predecessor

  $ 969,232   $ 829,291   $  
 

Niska Gas Storage Partners LLC:

                   
   

Common units—Public

  $   $   $ 339,613  
   

Common units—Holdco

            165,351  
   

Subordinated units—Holdco

            343,314  
   

Managing member interest—Manager

            14,013  
               
 

Total members' capital

            862,291  
               
   

Total capitalization

  $ 1,752,231   $ 1,744,291   $ 1,777,291  
               

(1)
Outstanding borrowings under our previous credit facilities were reduced to $75 million with cash from operations subsequent to December 31, 2009 and the remaining balance of borrowings under our previous credit facilities and term loan were fully repaid with the proceeds of the non-public offering of our senior notes.

(2)
The $115 million shown as outstanding under our new credit facilities represents the amount that would have been drawn to repay the drawings under the previous revolving credit facilities that

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    would have been outstanding had the transactions occurred on December 31, 2009. As of April 26, 2010, we had no borrowings outstanding under our revolving credit facilities and $3.5 million in letters of credit issued. We anticipate borrowing $279.6 million under our revolving credit facilities to fund a distribution to Holdco prior to the closing of this offering. We intend to use a portion of the net proceeds of this offering to fully repay all such borrowings under our revolving credit facilities, such that no borrowings will be outstanding post-offering. Because such pre-closing borrowing and subsequent repayment offset one another, no adjustment is reflected in the table above.

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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 $21.00 per common unit, on a pro forma basis as of December 31, 2009 our net tangible book value was negative $121.5 million, or negative $2.36 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:

Assumed initial public offering price per common unit

        $ 21.00  
 

Pro forma net tangible book value per unit before the offering(1)

  $ (2.36 )      
 

Increase in pro forma net tangible book value per unit attributable to purchasers in the offering

    5.52        
             

Less: Pro forma net tangible book value per unit after the offering(2)

          3.16  
             

Immediate dilution in pro forma net tangible book value per unit attributable to purchasers in the offering(3)

        $ 17.84  
             

(1)
Determined by dividing the number of units (16,304,745 common units, 33,804,745 subordinated units and the 2% managing member interest, which has a dilutive effect equivalent to 1,379,786 units) to be issued to Holdco and its affiliates for their contribution of assets and liabilities to us into the pro forma net tangible book value of the contributed assets and liabilities. The number of units notionally 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)
Determined by dividing the total number of units to be outstanding after the offering (33,804,745 common units, 33,804,745 subordinated units and the 2% managing member interest, which has a dilutive effect equivalent to 1,379,786 units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering. The number of units notionally 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.

(3)
If the initial public offering price were to increase or decrease by $1.00 per unit, dilution in pro forma net tangible book value per unit would increase by $0.24 per unit or decrease by $0.24 per unit, respectively.

        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):

 
  Units Acquired   Total Consideration  
 
  Number   %   Amount   %  

Holdco and its affiliates(1)(2)

    51,489,276     75 % $ 522,678,400     61 %

New investors

    17,500,000     25 % $ 339,612,500     39 %
                   

Total

    68,989,276     100 % $ 862,290,900     100 %
                   

(1)
Upon completion of the transactions contemplated by this prospectus, Holdco and its affiliates (including our manager) will own 16,304,745 common units, 33,804,745 subordinated units and the 2% managing member interest, which has a dilutive effect equivalent to 1,379,786 units. The number of units represented by the 2% managing member interest is determined by multiplying

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    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 as of December 31, 2009, as adjusted for all prior distributions to Holdco and its affiliates, a capital contribution by Holdco and its affiliates and other related formation transactions.

Net investment as of December 31, 2009

  $ 969,232,000  

Less distributions:

       
 

Cash distribution paid with proceeds from non-public offering of senior notes

    (107,065,100 )
 

Cash distribution paid April 16, 2010

    (25,000,000 )
 

Cash distribution expected to be paid prior to closing

    (20,000,000 )
 

Cash distribution expected to be paid from borrowings under our revolving credit facilities

    (279,612,500 )
       
   

Total distributions

  $ (431,677,600 )

Plus capital contribution:

       
 

Capital contribution on January 25, 2010

  $ 18,000,000  

Other pro forma adjustments

       
 

Elimination of Starks and Coastal Bend

    (25,526,212 )
 

Elimination of deferred charges associated with prior credit facilities

    (7,250,000 )
 

Other

    (99,788 )
       
   

Total of other pro forma adjustments

  $ (32,876,000 )

Total consideration to us

 
$

522,678,400
 

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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 capital expenditures, operating expenditures and debt service) 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. We expect to retain a portion of the proceeds from this offering to fund a portion of the cost of our expansion projects and may in the future establish cash reserves to fund the purchase of inventory for our proprietary optimization activities. 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 our $400.0 million credit agreement and by the indenture relating to our senior notes as well as by restrictions in future debt agreements that we enter into. Specifically, our credit agreement and indenture contain financial tests and covenants, commensurate with companies of our credit quality, that we must satisfy. Should we be unable to satisfy these restrictions under our $400.0 million credit agreement or indenture or if we are otherwise in default under our $400.0 million credit agreement or indenture, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our 8.875% Senior Notes Due 2018" and "—Our $400.0 Million Credit Agreement."

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    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), and the establishment of (or any increase in) those reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate.

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

    Because we have no history operating with a policy of distributing substantial amounts of cash and have grown rapidly through expansion of our facilities, we have a limited historical basis upon which to rely in our determination as to whether we will have sufficient available cash to pay the minimum quarterly distribution.

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

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

    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 $0.35 per unit per complete quarter, or $1.40 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 $24.1 million per quarter or $96.6 million per year, in each case based on the number of common units and subordinated units and the 2% managing member interest 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

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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.

        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 $0.35 per unit per quarter (or $1.40 per unit on an annualized basis).

 
   
  Distributions  
 
  Number of Units   One Quarter   Four Quarters  

Publicly held common units

    17,500,000   $ 6,125,000   $ 24,500,000  

Common units held by Holdco(1)

    16,304,745     5,706,661     22,826,643  

Subordinated units held by Holdco

    33,804,745     11,831,661     47,326,643  

Managing member 2% interest(2)

    1,379,786     482,925     1,931,700  
               

Total

    68,989,276   $ 24,146,247   $ 96,584,986  
               

(1)
Assumes the underwriters do not exercise their option to purchase 2,625,000 additional common units and that the 2,625,000 common units will be issued to Holdco upon the expiration of the underwriters' 30-day option period. Irrespective of whether the underwriters exercise their option to purchase additional common units, the total number of common units we have outstanding upon the completion of this offering and the expiration of the option period will not be impacted.

(2)
The number of unit equivalents the managing member interest represents 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 manager's 2% managing member interest.

        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 15th 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.

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        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 $0.35 per unit each quarter for the four quarters of the fiscal year 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 fiscal year ended March 31, 2009 and the twelve months ended 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 fiscal year ending March 31, 2011.

Unaudited Pro Forma Cash Available for Distribution

        The following table illustrates, on a pro forma basis for the fiscal year ended March 31, 2009 and the twelve months ended December 31, 2009, cash available to pay distributions, assuming that the following transactions had occurred as of April 1, 2008:

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

    the refinancing of our previous credit facilities; and

    the Formation Transactions, including the issuance of common units in this offering and the application of the net proceeds therefrom.

        If we had completed the transactions contemplated in this prospectus on April 1, 2008 our unaudited pro forma cash available for distribution for the fiscal year ended March 31, 2009 and the twelve months ended December 31, 2009 would have been approximately $97.8 million and $128.1 million, respectively. This amount would have been sufficient to make the minimum quarterly distribution of $0.35 per unit per quarter (or $1.40 per unit on an annualized basis) on all of our common and subordinated units for the fiscal year ended March 31, 2009 and the twelve months ended December 31, 2009.

        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 April 1, 2008. 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

 
  Fiscal
Year Ended
March 31, 2009
  Twelve Months Ended
December 31, 2009
 
 
  (in millions, except per unit
data and ratios)

 

Pro Forma Net Income

  $ 94.8   $ (24.3 )

Add/(deduct):

             
 

Interest and debt expense(2)

    80.0     82.1  
 

Income tax expense/(benefit)

    (22.3 )   41.7  
 

Unrealized risk management losses/(gains)

    (82.8 )   56.2  
 

Inventory impairment

    62.3     12.2  
 

Gain on sale of assets

    (0.0 )   (0.7 )
 

Other income

    (20.8 )   (20.5 )
 

Impairment of assets

    22.0     22.0  
 

Foreign exchange losses/(gains)

    (25.8 )   (18.1 )
 

Depreciation and amortization

    54.8     44.2  
           

Pro Forma Adjusted EBITDA(1)

  $ 162.1   $ 194.7  
           

Less:

             
 

Cash interest expense, net(2)

    80.4     82.9  
 

Cash taxes

    0.3     0.3  
 

Expansion capital expenditures

    17.6     46.8  
 

Maintenance capital expenditures(3)

    1.4     1.3  
 

Other income

    (20.8 )   (20.5 )
 

Estimated incremental general and administrative expense of being a public company(4)

    3.4     3.4  

Add:

             
 

Cash contributions to fund expansion capital expenditures

        15.0  
 

Borrowings to finance expansion capital expenditures(5)

    18.0     32.6  
           

Unaudited Pro Forma Cash Available for Distribution

  $ 97.8   $ 128.1  
           

Pro Forma Cash Distributions

             
 

Minimum distribution per unit (based on a minimum quarterly distribution of $0.35 per unit)

  $ 1.40   $ 1.40  
 

Annual distributions to:

             
 

Public common unitholders

    24.5     24.5  
 

Holdco:

             
   

Common units

    22.8     22.8  
   

Subordinated units

    47.3     47.3  
   

Managing member interest

    1.9     1.9  
           
     

Total minimum period distributions

  $ 96.6   $ 96.6  
           

Excess

  $ 1.2   $ 31.5  
           

Fixed charge coverage ratio(6)

    2.0 x   2.3 x

(1)
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

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    impairments and other income. See "Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure."

(2)
Interest and debt expense represents the interest expense and fees related to our borrowings, assuming that Niska US and Niska Canada had completed their non-public offering of senior notes (with an interest rate of 8.875%) on April 1, 2008 and that our new revolving credit facilities had been put in place at April 1, 2008. We have calculated interest expense using actual revolver drawings incurred during the applicable periods (an annualized average of $67.3 million in the fiscal year ended March 31, 2009 and $118.4 million in the twelve months ended December 31, 2009) plus assumed borrowings to fund expansion capital expenditures and using a rate of 5.0% (assumes LIBOR plus 350 basis points, where LIBOR is approximately 1.50%), which is the rate currently available under our new credit facilities. In addition, we have included an additional commitment fee in the amount of 0.75% of the undrawn amount (assuming a maximum borrowing capacity of $400.0 million) during the applicable periods. Interest and debt expense and cash interest expense, net, included in the table also reflects the amortization of deferred financing fees related to our new revolving credit facilities.

(3)
For the fiscal year ended March 31, 2009 and the twelve months ended December 31, 2009, our capital expenditures were $19.0 million and $48.1 million, respectively. The capital expenditures are assumed to have occurred evenly throughout each period. For these periods, recurring maintenance capital expenditures amounted to $1.4 million and $1.3 million, respectively, and expansion capital expenditures amounted to $17.6 million and $46.8 million, respectively.

(4)
Reflects an adjustment to our Adjusted EBITDA for estimated cash expenses associated with being publicly-traded, such as expenses 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 to recur and that they initially will be approximately $3.4 million per year.

(5)
In October 2009, our equity holders contributed $15.0 million to us specifically to fund expansion capital expenditures. Accordingly, our pro forma presentation for the twelve months ended December 31, 2009 reflects the application of the entire $15.0 million of capital contributions from our equity holders to fund expansion capital expenditures. Because we expect that in the future, expansion capital expenditures will primarily be funded through borrowings or the sale of debt or equity securities, we have included borrowings under our revolving credit facilities to offset our estimated expansion capital expenditures as well as incremental interest expense on these borrowings at an assumed interest rate of 5.0% (assumes LIBOR plus 350 basis points, where LIBOR is approximately 1.50%) for purposes of calculating our pro forma cash available for distribution. Accordingly, our pro forma presentation for the fiscal year ended March 31, 2009 reflects the application of assumed borrowings to fund expansion capital expenditures as well as incremental interest expense of $0.4 million on these borrowings, and our pro forma presentation for the twelve months ended December 31, 2009 reflects the application of assumed borrowings to fund expansion capital expenditures as well as incremental interest expense of $0.8 million on these borrowings.

(6)
Our $400.0 million credit agreement prohibits us from making distributions to unitholders if any default or event of default (as defined in the credit agreement) exists. Our new revolving credit facilities contain a covenant requiring us, when excess availability under both revolving credit facilities is less than 15% of the aggregate amount of availability under both revolving credit facilities, to maintain, as of the last day of each fiscal quarter, a fixed charge coverage ratio (the ratio of our Consolidated Adjusted EBITDA to our fixed charges, each as defined in our credit

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    facilities and measured for the preceding four quarters) of not less than of 1.1 to 1.0. On a pro forma basis, excess availability under both revolving credit facilities would have been more than 15% of the aggregate amount of availability under both revolving credit facilities for the fiscal year ended March 31, 2009 and the twelve months ended December 31, 2009 and our fixed charge coverage ratio would have been greater than 1.1 to 1.0 during such periods.


The indenture governing our senior notes prohibits us from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, after the closing of this offering, both the indenture and our $400 million credit agreement will contain covenants limiting our ability to pay distributions to unitholders. The covenants will apply differently depending on our fixed charge coverage ratio (defined substantively the same in the indenture and the credit agreement). If the fixed charge coverage ratio is not less than 1.75 to 1.0, we will be permitted to make restricted payments, including distributions to our unitholders, if the aggregate restricted payments since the date of closing of this offering, excluding certain types of permitted payments, are less than the sum of a number of items including, most importantly, operating surplus (defined similarly to the definition in our Operating Agreement) calculated as of the end of our preceding fiscal quarter and the aggregate net cash proceeds received by us as a capital contribution or from the issuance of equity interests, including the net proceeds received in this offering. The indenture governing our senior notes contains an additional general basket of $75 million not contained in our credit agreement. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our 8.875% Senior Notes Due 2018" and "—Our $400 Million Credit Agreement."


We estimate that our credit agreement and indenture would have permitted us to distribute approximately $208 million and $283 million, respectively, as of March 31, 2009 and approximately $279 million and $354 million, respectively, as of December 31, 2009. These estimates are based on our assumption that operating surplus generated during the fiscal year ended March 31, 2009 and the nine months ended December 31, 2009 would have been approximately equal to the Unaudited Pro Forma Cash Available for Distribution in respect of such periods, and include the $50 million basket contained in the definition of operating surplus and the $60 million of net proceeds from this offering that we expect to retain for general company purposes, including to fund a portion of the cost of our expansion projects. The estimates of amounts permitted to be distributed under the indenture are $75 million higher than the estimates of those permitted to be distributed under our credit agreement due to the additional $75 million general permitted payment basket contained in the indenture. Similar to the calculation of operating surplus contained in our Operating Agreement, the credit agreement and indenture provide that operating surplus will be calculated from the closing date of this offering, such that we will not be permitted to include any operating surplus that would have been generated prior to the closing of this offering. See "Provisions of our Operating Agreement Relating to Cash Distributions—Operating Surplus and Capital Surplus." Immediately after the closing of this offering, our operating surplus will initially be equal to the $50 million basket contained in the definition of operating surplus and our credit agreement and indenture will permit us to distribute $110 million and $185 million, respectively.

Estimated Cash Available for Distribution

        We estimate we will generate Adjusted EBITDA of $204.1 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.

        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

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common units and subordinated units and our manager interest under the applicable covenants contained in our $400.0 million credit agreement and the indenture governing our senior notes.

        When considering our ability to generate Adjusted EBITDA of $204.1 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 completion of this offering. 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

 
  Fiscal Year
Ending
March 31, 2011
 
 
  (in millions, except
per unit data)

 

Net revenues

  $ 240.9  

Operating expenses:

       
 

Operation and maintenance

    52.5  
 

General and administrative

    34.2  
 

Depreciation and amortization

    44.9  
 

Taxes other than income taxes

    11.7  
   

Total operating expenses

    143.3  

Operating income

    97.6  
 

Other income

     
 

Interest and debt expense, net

    76.7  

Net income

    20.9  

Adjustments to reconcile net income to Adjusted EBITDA:

       

Add/deduct:

       
 

Unrealized risk management losses/(gains)

    49.9  
 

Depreciation and amortization expense

    44.9  
 

Interest and debt expense, net

    76.7  
 

Cash taxes

    11.7  

Adjusted EBITDA(1)

    204.1  

Less:

       
 

Cash interest expense, net

    76.7  
 

Cash taxes

    11.7  
 

Expansion capital expenditures

    73.9  
 

Maintenance capital expenditures

    1.7  
 

Cash reserve

    19.1  
       

Add:

       
 

Borrowings to finance expansion capital expenditures and incremental interest expense

    75.6  

Minimum estimated cash available for distribution

  $ 96.6  
       

Minimum distribution per unit (based on a minimum quarterly distribution of $0.35 per unit)

  $ 1.40  

Annual distributions to:

       
 

Public common unitholders

  $ 24.5  

Holdco:

       
 

Common units

    22.8  
 

Subordinated units

    47.3  
 

Managing member interest

    1.9  
       
   

Total distributions to Holdco

    72.1  
       

Total distributions to our unitholders and manager (based on a minimum quarterly distribution of $1.40 per unit per year)

  $ 96.6  
       

Fixed charge coverage ratio

    2.7 x

(1)
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. See "Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure."

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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 March 29, 2010 we have entered into transactions amounting to revenues of $145.2 million, representing over 60% of our total forecasted revenues for the fiscal year ending March 31, 2011 ($195.1 million, or 67%, on a realized basis before unrealized marked to market gains and losses and inventory writedowns).

    We assume that Canadian dollars are converted into dollars at an average rate of $0.9786, which was the average forward rate as of March 29, 2010, for the forecast period.

    Revenue

    Volume Assumptions.  We estimate we will contract 84% of our operated capacity to third parties for the fiscal year ending March 31, 2011, compared with 79% for the twelve months ended December 31, 2009. We expect 104.3 Bcf will be contracted as LTF contracts and 56.7 Bcf as STF contracts compared to 103.9 Bcf and 36.8 Bcf, respectively, for the fiscal year ended March 31, 2010. We estimate using the remaining 16% of our operated capacity (31.0 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 average fees of $1.12 per Mcf for the fiscal year ending March 31, 2011, as compared to an average of $0.99 for the three fiscal years ended March 31, 2009. We estimate that we will receive average fees of $1.43 per Mcf for STF contracts and an average margin of $1.10 per Mcf ($2.36 per Mcf on a realized basis before unrealized marked to market gains and losses and inventory writedowns) for proprietary optimization activities for the fiscal 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 fiscal 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 associated with LTF contracts will be $116.7 million for the fiscal year ending March 31, 2011 as compared to $106.6 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 $81.0 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 $197.6 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 $43.3 million ($93.2 million on a realized basis before unrealized marked to market gains and losses and inventory writedowns) in revenue from optimization for the fiscal year ending March 31, 2011, compared to $24.4 million ($92.8 million on a realized basis before unrealized marked to market gains and losses and inventory writedowns) for the twelve months ended December 31, 2009.

    Operation and Maintenance Expenses

    We estimate that total operating and maintenance expenses for the fiscal year ending March 31, 2011 will be $52.5 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

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      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 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 fiscal year ending 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 $3.88 per Mcf for the fiscal year ending March 31, 2011 (based on forward curves as of March 29, 2010), compared to $3.93 per Mcf for the twelve months ended December 31, 2009 due to a decline in the price of natural gas.

    General and Administrative Expenses

    We estimate that general and administrative expenses will be $34.2 million for the fiscal year ending March 31, 2011, compared to $24.6 million for the twelve months ended December 31, 2009. Our general and administrative expenses include one-time costs associated with the refinancing of our previous 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 fiscal year ending March 31, 2011 of $44.9 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 or will be put into effective use in 2010.

    We assume that financing costs of $24.8 million associated with our senior notes will be amortized on a straight line basis over 8 years.

    Capital Expenditures

    We estimate total capital expenditures of $75.6 million for the fiscal year ending March 31, 2011, compared to $48.1 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 $73.9 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 ending 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 $8.3 million and $7.0 million, respectively. We would also be required to decrease our cash reserve by no more than $7.0 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 $13.9 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 will incur interest expense of $71.0 million for the fiscal year ending March 31, 2011 associated with our senior notes, which bear interest at a rate of 8.875%.

    For purposes of the forecast, we assume that we will finance all of our expansion capital expenditures during the forecast period with assumed borrowings under our revolving credit facilities.

    We have assumed net annual average revolver borrowings to fund expansion capital expenditures of $37.1 million with a net interest expense of $2.0 million.

    We expect to utilize an annual average of $125.3 million to fund the purchase of inventory for our proprietary optimization activities. We expect to begin the year with an inventory of 15.6 Bcf and to purchase 24.0 Bcf of gas evenly over the seven month summer injection season and then sell 27.7 Bcf ratably over the five month winter withdrawal season. Using prudent cash management (using cash from operations generated during the forecast period until distributions are made, and cash reserves accumulated during the forecast period) the net annual average revolver borrowings to fund inventory purchases are expected to be $24.6 million with a net interest expense of $1.2 million, plus undrawn commitment fees of $2.5 million for total cost of $3.7 million.

    We will remain in compliance with the financial and other covenants in our credit agreement and the indenture governing our senior notes.

    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 fiscal year 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 ended March 31, 2010 or the fiscal year ending March 31, 2011.

    We assume that industry and insurance conditions will not change substantially during the three months ended March 31, 2010 or the fiscal year 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 fiscal year 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 fiscal year ending March 31, 2011 are estimated to be $96.6 million in the aggregate, assuming we distribute the $0.35 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 $0.35 per unit, or $1.40 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 included in our $400.0 million credit agreement and the indenture governing our senior notes 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 $0.4025 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 prior to the stated maturity of derivative contracts hedging our commodity, interest rate, basis or currency risk with an original term of more than one year (provided that cash receipts from such termination shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such derivative 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 after this offering (including incremental distributions on incentive distribution rights) to finance all or a portion of expansion capital expenditures 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 after this offering (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 expansion capital expenditures referred to above; less

    our operating expenditures (as described below) after the closing of this offering; less

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

        Working capital borrowings are borrowings, used solely for working capital purposes, including the purchase of inventory and other current assets or to fund current liabilities, and specifically excluding any borrowings for the purchase of property, plant and equipment, capital improvements, or to pay distributions to members, made in the ordinary course of business pursuant to a credit facility, commercial paper facility or similar financing arrangement; provided that when incurred it is 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

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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 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 derivative contracts hedging our commodity, interest rate, basis or currency risk (provided that (1) with respect to amounts paid in connection with the initial purchase of such a derivative contract with an original term of more than one year, such amounts will be amortized over the life of the applicable derivative contract and (2) payments made in connection with the termination of any such derivative contracts with an original term 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 derivative 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, other than repurchases to satisfy obligations under employee benefit plans.

        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 assets, to maintain the long-term operating capacity of our assets or other capital expenditures that are incurred in maintaining long-term operating capacity of our assets or our operating income. 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. Examples of maintenance capital expenditures are 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 operating income 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 or our operating income. 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

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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.

        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 operating income.

        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. Cash losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash gains 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 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 to Unitholders—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 $0.35 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 determination set forth in the third bullet point above, operating surplus shall not include working capital borrowings made in a period but not used to fund operating expenditures or distributions 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.

    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

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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 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 or other property.

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

    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;

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

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

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

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

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

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

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.

 
   
  Marginal Percentage
Interest in Cash Distributions
 
 
  Total Quarterly
Distribution per Unit
Target Amount
  Unitholders   Manager   Incentive
Distribution
Right Holders
 

Minimum Quarterly Distribution

  $0.35     98 %   2 %    

First Target Distribution

  above $0.35 up to $0.4025     98 %   2 %    

Second Target Distribution

  above $0.4025 up to $0.4375     85 %   2 %   13 %

Third Target Distribution

  above $0.4375 up to $0.5250     75 %   2 %   23 %

Thereafter

  above $0.5250     50 %   2 %   48 %

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;

    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

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    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;

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

    the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution on the common units.

        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 as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our manager 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 manager's estimate of our additional aggregate liability for the quarter for such income and withholdings taxes payable by reason of such change in law or interpretation) and the denominator of which is the sum of (1) available cash for that quarter, plus (2) our manager's estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation thereof. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in distributions with respect to subsequent quarters.

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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, 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;

    second, 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;

    third, 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;

    fourth, 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;

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    fifth, 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 first bullet point above and all of the second 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, to all unitholders and the manager in proportion to the positive balances in their adjusted capital accounts.

        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.

    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. 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 Niska GS Holdings I, L.P. and Niska GS Holdings II, L.P. 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 Niska GS Holdings I, L.P. and Niska GS Holdings II, L.P. In connection with the closing of this offering, Niska Holdings will contribute Niska Predecessor to us. 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.

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

        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 non-public offering of our senior notes, this offering and the transactions to be effected in connection with 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.

 
   
   
   
   
   
  Niska Gas
Storage
Partners
LLC
 
 
  Niska Predecessor   Pro Forma  
 
  Period from
May 12,
2006 to
March 31,

   
   
  Nine Months Ended
December 31,
   
 
 
  Year Ended March 31,   Nine Months
Ended
December 31,
2009
 
 
  2007(a)   2008   2009   2008   2009  
 
   
   
   
  (unaudited)
   
  (unaudited)
 
 
   
  (dollars in millions)
 

Combined Statement of Earnings and Comprehensive Income Data:

                                     

Revenues:

                                     
 

Long-term contract revenue

  $ 104.5   $ 121.4   $ 110.7   $ 85.9   $ 81.9   $ 81.9  
 

Short-term contract revenue

    32.1     35.5     52.0     32.8     39.9     39.9  
 

Optimization revenue, net(b)

    57.2     76.0     89.4     92.9 (c)   27.9 (c)   27.9 (c)
                           

  $ 193.8   $ 232.9   $ 252.2   $ 211.6   $ 149.7   $ 149.7  

Expenses (Income):

                                     
 

Operating expenses

  $ 28.8   $ 44.6   $ 45.4   $ 34.5   $ 28.4   $ 28.4  
 

General and administrative expenses

    19.9     30.1     24.2     20.4     21.5     20.9  
 

Depreciation and amortization

    46.6     42.5     54.8     43.4     32.9     32.9  
 

Interest expense

    60.2     73.9     53.5     43.5     20.1     62.2  
 

Impairment of assets

        2.5     24.1 (d)            
 

Loss/(gain) on sale of assets

        2.3         0.7          
 

Other income

    (0.4 )   (0.7 )   (20.8) (e)   (0.4 )   (0.1 )   (0.1 )
 

Foreign exchange losses/(gains)

    (2.6 )   (7.2 )   (25.8 )   (16.0 )   (8.2 )   (8.2 )
                           
 

Earnings before income taxes

  $ 41.4   $ 45.0   $ 96.9   $ 85.4   $ 55.0   $ 13.6  

Income tax expense/(benefit):

                                     
 

Current

        0.3     0.3     0.3     0.2     0.2  
 

Deferred

    (12.1 )   (3.7 )   (12.2 )   (15.7 )   51.6     40.7  
                           

    (12.1 )   (3.4 )   (11.9 )   (15.4 )   51.8     40.9  
                           

Net earnings/(loss) and comprehensive income for the period ended

 
$

53.5
 
$

48.3
 
$

108.8
 
$

100.8
 
$

3.2
 
$

(27.3

)
                           

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  Niska Gas
Storage
Partners
LLC
 
 
  Niska Predecessor   Pro Forma  
 
  Period from
May 12,
2006 to
March 31,

   
   
  Nine Months Ended
December 31,
   
 
 
  Year Ended March 31,   Nine Months
Ended
December 31,
2009
 
 
  2007(a)   2008   2009   2008   2009  
 
   
   
   
  (unaudited)
   
  (unaudited)
 
 
   
  (dollars in millions)
 

Balance Sheet Data (at period end):

                                     

Total assets

  $ 1,931.1   $ 1,905.2   $ 2,002.9   $ 2,107.5   $ 2,071.0   $ 2,083.8  

Property, plant and equipment, net of depreciation

    976.5     955.7     940.2     951.0     974.3     951.1  

Long-term debt(f)

    773.6     693.8     597.0     688.6     593.0     800.0  

Total partners'/members' capital

    820.5     867.1     977.4     930.2     969.2     862.3  

Other Financial Data (unaudited):

                                     

Adjusted EBITDA

  $ 148.0   $ 156.7   $ 162.1   $ 113.1   $ 145.0   $ 145.7  

Maintenance capital expenditures(g)

    0.3     1.7     1.4     1.0     0.8     0.8  

Expansion capital expenditures(g)

    27.4     35.8     17.6     16.5     46.0     45.7  

Operating Data (unaudited):

                                     

Effective working gas capacity (Bcf)(h)

    144.2     155.3     163.7     163.7     185.5     185.5  

Capacity added during period (Bcf)

        11.1     8.4     8.4     21.8     21.8  

Percent of total capacity contracted to third parties

    91.3 %   84.9 %   85.1 %   85.1 %   75.9 %   75.9 %

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

(b)
Optimization revenues are presented net of cost of goods sold.

(c)
Net optimization revenues include unrealized risk management gains/losses and write-downs of inventory. We had an unrealized risk management loss of $45.3 million for the nine months ended December 31, 2009 and an unrealized risk management gain of $93.8 million for the nine months ended December 31, 2008. We had a write-down of inventory of $50.1 million for the nine months ended December 31, 2008, compared to zero for the nine months ended December 31, 2009. Excluding these non-cash items, which do not affect Adjusted EBITDA, our realized optimization revenues were $73.2 million for the nine months ended December 31, 2009 compared with $49.3 million for the nine months ending December 31, 2008.

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

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

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

(g)
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, or other capital expenditures that are incurred in maintaining existing operating capacity of our assets. 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.

(h)
Represents operated and NGPL capacity.

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

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

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

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

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

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

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

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

 
   
   
   
   
   
  Niska Gas
Storage
Partners
LLC
 
 
  Niska Predecessor Historical   Pro Forma  
 
  Period from
May 12,
2006 to
March 31,

   
   
  Nine Months Ended
December 31,
   
 
 
  Year Ended March 31,   Nine Months
Ended
December 31,
2009
 
 
  2007(a)   2008   2009   2008   2009  
 
   
   
   
  (unaudited)
   
  (unaudited)
 
 
  (dollars in millions)
 

Reconciliation of Adjusted EBITDA to net income:

                                     

Net earnings/(loss)

  $ 53.5   $ 48.3   $ 108.8   $ 100.8   $ 3.2   $ (27.3 )

Add/(deduct):

                                     
 

Interest expense

    60.2     73.9     53.5     43.5     20.1     62.2  
 

Income tax expense/(benefit)

    (12.1 )   (3.4 )   (11.9 )   (15.4 )   51.8     40.9  
 

Depreciation and amortization

    46.6     42.5     54.8     43.4     32.9     32.9  
 

Unrealized risk management losses/(gains)

    2.8     (1.5 )   (82.8 )   (93.8 )   45.3     45.3  
 

Foreign exchange losses/(gains)

    (2.6 )   (7.2 )   (25.8 )   (16.0 )   (8.2 )   (8.2 )
 

Loss/(gain) on sale of assets

        2.3         0.7          
 

Impairment of assets

        2.5     24.1              
 

Other income

    (0.4 )   (0.7 )   (20.8 )   (0.4 )   (0.1 )   (0.1 )
 

Unrealized inventory impairment writedown

            62.3     50.1          
                           

Adjusted EBITDA

  $ 148.0   $ 156.7   $ 162.1   $ 113.1   $ 145.0   $ 145.7  
                           

(a)
Data includes Wild Goose from November 16, 2006 to March 31, 2007.

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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 non-public offering of our senior notes and use of proceeds therefrom, our 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 our inception on May 12, 2006 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 facilities. We therefore closely monitor the utilization and remaining available capacity under our credit facilities and actively pursue additional STF contracts when we determine it is appropriate to maintain liquidity.


Factors that Impact Our Business

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

    Market Price for LTF Contracts

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

    Gas Storage Capacity Growth

        Capacity added in the prior year or added during a year 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:

 
  Niska Predecessor  
 
  Period from
May 12,
2006 to
March 31,

  Year Ended March 31,   Nine Months Ended
December 31,
 
 
  2007(a)   2008   2009   2008   2009  
 
   
   
   
  (unaudited)
   
 
 
  (dollars in millions)
 

Combined Statement of Earnings and Comprehensive Income Data:

                               

Revenues

                               
 

Long-term contract revenue

  $ 104.5   $ 121.4   $ 110.7   $ 85.9   $ 81.9  
 

Short-term contract revenue

    32.1     35.5     52.0     32.8     39.9  
 

Optimization revenue, net(b)

    57.2     76.0     89.4     92.9 (c)   27.9 (c)
                       

  $ 193.8   $ 232.9   $ 252.2   $ 211.6   $ 149.7  

Expenses (Income):

                               
 

Operating expenses

  $ 28.8   $ 44.6   $ 45.4   $ 34.5   $ 28.4  
 

General and administrative expenses

    19.9     30.1     24.2     20.4     21.5  
 

Depreciation and amortization

    46.6     42.5     54.8     43.4     32.9  
 

Interest expense

    60.2     73.9     53.5     43.5     20.1  
 

Impairment of assets

        2.5     24.1 (d)        
 

Loss/(gain) on sale of assets

        2.3         0.7      
 

Other income

    (0.4 )   (0.7 )   (20.8) (e)   (0.4 )   (0.1 )
 

Foreign exchange losses/(gains)

    (2.6 )   (7.2 )   (25.8 )   (16.0 )   (8.2 )
                       
 

Earnings before income taxes

  $ 41.4   $ 45.0   $ 96.9   $ 85.4   $ 55.0  

Income tax expense/(benefit):

                               
 

Current

        0.3     0.3     0.3     0.2  
 

Deferred

    (12.1 )   (3.7 )   (12.2 )   (15.7 )   51.6  
                       

    (12.1 )   (3.4 )   (11.9 )   (15.4 )   51.8  
                       

Net earnings and comprehensive income for the period ended

 
$

53.5
 
$

48.3
 
$

108.8
 
$

100.8
 
$

3.2
 
                       

Reconciliation of Adjusted EBITDA to net income:

                               

Net earnings

  $ 53.5   $ 48.3   $ 108.8   $ 100.8   $ 3.2  

Add/(deduct):

                               
 

Interest expense

    60.2     73.9     53.5     43.5     20.1  
 

Income tax expense/(benefit)

    (12.1 )   (3.4 )   (11.9 )   (15.4 )   51.8  
 

Depreciation and amortization

    46.6     42.5     54.8     43.4     32.9  
 

Unrealized risk management losses/(gains)

    2.8     (1.5 )   (82.8 )   (93.8 )   45.3  
 

Foreign exchange losses/(gains)

    (2.6 )   (7.2 )   (25.8 )   (16.0 )   (8.2 )
 

Loss/(gain) on sale of assets

        2.3         0.7      
 

Impairment of assets

        2.5     24.1          
 

Other income

    (0.4 )   (0.7 )   (20.8 )   (0.4 )   (0.1 )
 

Unrealized inventory impairment writedown

            62.3     50.1      
                       

Adjusted EBITDA

  $ 148.0   $ 156.7   $ 162.1   $ 113.1   $ 145.0  
                       

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  Niska Predecessor  
 
  Period from
May 12,
2006 to
March 31,

  Year Ended March 31,   Nine Months Ended
December 31,
 
 
  2007(a)   2008   2009   2008   2009  
 
   
   
   
  (unaudited)
   
 
 
  (dollars in millions)
 

Balance Sheet Data (at period end):

                               

Total assets

  $ 1,931.1   $ 1,905.2   $ 2,002.9   $ 2,107.5   $ 2,071.0  

Property, plant and equipment, net of accumulated depreciation

    976.5     955.7     940.2     951.0     974.3  

Long-term debt(f)

    773.6     693.8     597.0     688.6     593.0  

Total partners'/members' capital

    820.5     867.1     977.4     930.2     969.2  

Operating Data (unaudited):

                               

Effective working gas capacity (Bcf)(h)

    144.2     155.3     163.7     163.7     185.5  

Capacity added during period (Bcf)

        11.1     8.4     8.4     21.8  

Percent of total capacity contracted to third parties

    91.3 %   84.9 %   85.1 %   85.1 %   75.9 %

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

(b)
Optimization revenues are presented net of cost of goods sold.

(c)
Net optimization revenues include unrealized risk management gains/losses and write-downs of inventory. We had an unrealized risk management loss of $45.3 million for the nine months ended December 31, 2009 and an unrealized risk management gain of $93.8 million for the nine months ended December 31, 2008. We had a write-down of inventory of $50.1 million for the nine months ended December 31, 2008, compared to zero for the nine months ended December 31, 2009. Excluding these non-cash items, which do not affect Adjusted EBITDA, our realized optimization revenues were $73.2 million for the nine months ended December 31, 2009 compared with $49.3 million for the nine months ended December 31, 2008.

(d)
Impairment charges relate to the goodwill in a subsidiary that was written down from its carrying amount of $22.0 million to zero. The impairment charges were recorded following a year of overall negative economic conditions.

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

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

(g)
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, or other capital expenditures that are incurred in maintaining existing operation capacity of our assets. 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.

(h)
Represents operated and NGPL capacity.

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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:

 
  Niska Predecessor  
 
  Period from
May 12,
2006 –
March 31,
2007(1)
   
   
  Nine Months Ended
December 31,
 
 
  Year Ended March 31,  
 
  2008   2009   2008   2009  

Storage Capacity (Bcf) utilized by:

                               
 

LTF Contracts

    119.9     112.8     106.3     106.3     103.9  
 

STF Contracts

    11.7     19.1     32.9     32.9     36.8  
 

Proprietary optimization transactions

    12.6     23.4     24.5     24.5     44.8  
                       
 

Total

    144.2     155.3     163.7     163.7     185.5  

Revenue (in millions)

                               
 

LTF Contracts

  $ 104.5   $ 121.4   $ 110.7   $ 85.9   $ 81.9  
 

STF Contracts

    32.1     35.5     52.0     32.8     39.9  
 

Realized proprietary optimization transactions

    60.0     74.6     68.9     49.3     73.2  
 

Unrealized risk management gains (losses)

    (2.8 )   1.5     82.8     93.8     (45.3 )
 

Write-down of inventory

            (62.3 )   (50.1 )    
                       
 

Total

  $ 193.8   $ 232.9   $ 252.2   $ 211.6   $ 149.7  

Fees/Margins ($/mcf)

                               
 

LTF Contracts

  $ 0.87   $ 1.08   $ 1.04   $ 0.81   $ 0.79  
 

STF Contracts

    2.74     1.86     1.58     1.00     1.09  
 

Realized proprietary optimization transactions

    4.77     3.18     2.82     2.02     1.63  

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

        Revenues.    Revenues decreased 29.3% to $149.7 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 4.7% to $81.9 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 $27.9 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 48.4% to $73.2 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 Hub™. The provision against cushion gas is an estimate based on tests of its effectiveness. Through continued monitoring of cushion effectiveness over a

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      series of 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. We decreased the principal balance of our previous term debt in order to maintain compliance with a leverage covenant, which adjusted effective March 2009, contained in the agreements governing our previous term debt and revolving credit facilities. 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.

        Foreign Exchange Losses/(Gains).    Foreign exchange gains for the nine months ended December 31, 2009 decreased to $8.2 million from $16.0 million for the period ended December 31, 2008. The election by two of our Canadian subsidiaries to adopt the U.S. dollar as their functional currency for their Canadian tax returns during the nine months ended December 31, 2009 eliminated all material foreign currency translation gains and losses attributable to deferred income taxes.

        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 normal seasonal spread as well as LTF contract rates. 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 fiscal year ended March 31, 2008. This increase was primarily attributable to the following:

    LTF Revenues.  LTF revenues for the fiscal year ended March 31, 2009 decreased 8.8% to $110.7 million from $121.4 million for the fiscal 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 fiscal year ended March 31, 2009 from 112.8 Bcf for the fiscal year ended March 31, 2008. In addition, because high natural gas prices at the beginning of the year reduced the normal spread and the LTF contract rates, new or replacement contract rates were 22.5% lower in the fiscal year ended March 31, 2009 as compared to the fiscal year ended

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      March 31, 2008. Due to the lower rates for LTF contracts, we elected not to re-contract some of the contracts that expired in the fiscal year ended March 31, 2009. In addition, the minimum contracting covenant contained in our previous debt facilities expired during the year and we elected to alter the capacity utilization towards STF contracts that offered higher value in the then current period. By the end of the fiscal year ending March 31, 2009, gas prices stabilized at lower levels, which caused the seasonal spread and storage contract rates to return to normal, higher levels. We believe the storage spreads and low contract rates experienced at the beginning of the fiscal year ended March 31, 2009 were an anomaly and that, going forward, storage values will remain at normal or higher levels. See "Industry Overview—Fundamental Industry Trends."

    STF Revenues.  STF revenues for the fiscal year ended March 31, 2009 increased 46.5% to $52.0 million from $35.5 million for the fiscal 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 were $1.58 per MMbtu for the fiscal year ended March 31, 2009 compared to $1.86 per MMbtu for the fiscal year ended March 31, 2008.

    Optimization Revenues.  Net optimization revenue for the fiscal year ended March 31, 2009 increased 17.6% to $89.4 million from $76.0 million for the fiscal 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 fiscal year ended March 31, 2009 increased to $82.8 million from $1.5 million for the fiscal 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 gains of $0.6 million for the fiscal 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.

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

    Depreciation and 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 Hub™. 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 fiscal 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 previous 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 previous term debt and revolvers were floating and the average interest rates applied to our previous 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 fiscal year ended March 31, 2009 increased to $20.8 million from $0.7 million for the fiscal 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

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      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 fiscal year ended March 31, 2009 increased to $25.8 million from $7.2 million for the fiscal 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.

        Net Income.    Net income for the fiscal year ended March 31, 2009 increased to $108.8 million from $48.3 million for the fiscal 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 fiscal year ended March 31, 2009 increased to $11.9 million from $3.4 million for the fiscal 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 fiscal 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 fiscal 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

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      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 fiscal 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 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 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 previous credit facilities in the fiscal year ended March 31, 2008, due to increased

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      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 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 ended 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 $96.6 million. Our pro forma cash available for distribution for the fiscal year ended March 31, 2009 and 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 periods. 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 $400.0 million credit agreement and our senior notes 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 our existing and possible future credit facilities or a mix of borrowings and additional equity offerings as well as cash on hand and cash from operations. We anticipate that our primary sources of funds for our long-term liquidity needs will be from cash from operations and/or debt or equity financings. We believe that these sources of funds will be sufficient to meet our liquidity needs for the foreseeable future.

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

    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 facilities to fund these purchases, and these borrowings increase our cash flows from financing activities. Conversely, when we collect the proceeds from the sale of natural gas that we purchased and stored for our own account, the impact on our cash flows from operating activities is positive and the impact on our cash flows from financing activities is negative. Therefore, our cash flows from operating activities fluctuate significantly from period-to-period as we purchase gas, store it, and then sell it in a later period. In addition, we have margin requirements on our economically hedged positions. As the cash deposits we make to satisfy our margin requirements increase and decrease with our volume of derivative positions and changes in commodity prices, our cash flows from operating activities may fluctuate significantly from period to period.

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        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.

 
  Niska Predecessor  
 
  For the
period from
May 12, 2006
through
March 31,
2007
   
   
   
   
 
 
  Year Ended March 31,   Nine Months Ended
December 31,
 
 
  2008   2009   2008   2009  
 
   
   
   
  (unaudited)
   
 
 
  (dollars in millions)
 

Operating Activities

                               

Net earnings

  $ 53.5   $ 48.3   $ 108.8   $ 100.8   $ 3.2  

Adjustments to reconcile net earnings to net cash provided by (used in) operating activities:

                               
 

Unrealized foreign exchange (gain) loss

    (0.4 )   0.2     (37.2 )   (29.5 )   (0.2 )
 

Deferred income taxes (benefit)

    (12.1 )   (3.7 )   (12.2 )   (15.7 )   51.6  
 

Unrealized risk management losses (gains)

    5.5     6.9     (77.3 )   (87.7 )   42.4  
 

Depreciation and amortization

    46.6     42.5     54.8     43.4     32.9  
 

Deferred charges amortization

    2.7     2.9     2.9     2.2     4.1  
 

Loss (gain) on disposal of assets

        2.3     (0.0 )   0.7      
 

Impairment of goodwill

            22.0          
 

Impairment of assets

        2.5     2.1          
 

Write-down of inventory

            62.3     50.1      

Changes in non-cash working capital

    (82.7 )   84.0     (104.6 )   (138.2 )   (195.2 )

Net cash (used in) provided by operating activities

    13.2     185.9     21.5     (73.8 )   (61.3 )

Net cash used in investing activities

    (1,557.7 )   (29.9 )   (15.6 )   (14.2 )   (46.8 )

Net cash provided/(used) by financing activities

    1,580.1     (141.6 )   (30.4 )   122.2     120.2  

Other information:

                               

Proprietary inventory at cost

  $ 109.8   $ 31.5   $ 133.1   $ 155.2   $ 210.9  

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

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

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