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

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

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

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

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

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

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

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.

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

As of September 30, 2015, the aggregate market value of the registrant's common units held by non-affiliates was $54,425,619 based on a unit price of $3.11. This calculation of such market value should not be construed as an admission or conclusion by the registrant that any person is in fact an affiliate of the registrant.

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


Basin		A geological province on land or offshore where hydrocarbons are generated and trapped.
Bcf		One billion cubic feet of natural gas. A standard volume measure of natural gas products.
British Thermal Unit ("BTU")		British thermal unit, a traditional unit of heat measurement equal to the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit at one atmosphere pressure.
Cap-and-Trade		A market-based approach used to control pollution by providing economic incentives for achieving reductions in the emissions of pollutants. A central authority (usually a governmental body) sets a limit or cap on the amount of a pollutant that may be emitted. The limit or cap is allocated or sold to firms in the form of emissions permits which represent the right to emit or discharge a specific volume of the specified pollutant.
CPUC		California Public Utilities Commission. A regulatory agency that monitors privately owned public utilities in the state of California, including natural gas companies.
Cushion		A quantity of hydrocarbons held within the confines of the natural gas storage facility used for pressure support and to maintain a minimum field pressure. May consist of injected cushion gas, native cushion gas or oil.
Cycle		A complete withdrawal and injection of working gas.
Dekatherm ("Dth")		Equivalent to one million Btus or one MMBtu. One therm equals one hundred thousand Btus.
Effective Working Gas Capacity		The maximum volume of natural gas that can be cost-effectively injected into a storage reservoir and extracted during the normal operation of the storage facility. Effective working gas capacity excludes cushion.
GAAP		Generally accepted accounting principles in the United States of America.
Gas storage capacity		See Effective Working Gas Capacity.
Holdco		Niska Sponsor Holdings Coöperatief U.A.
Hub		Geographic location of a natural gas storage facility and multiple pipeline interconnections.
Independent Storage		Natural gas storage facilities owned and operated independently from the pipeline and distribution facilities to which they are interconnected.


Inventory		An amount of Working Gas held within the natural gas storage facility. It may relate to third-party customer volumes or to owner/operator volumes of working gas.
Injection Rate		The rate at which a customer is permitted to inject natural gas into a natural gas storage facility.
Manager		Niska Gas Storage Management LLC. Also referred to as "our manager."
Mcf		Thousand cubic feet of natural gas.
Mega Dekatherm ("MDth")		Equivalent to one million Dekatherms.
MMbtu		Million British thermal units. A standard measure of natural gas for pricing purposes, particularly in the U.S.
MMcf		Million cubic feet of natural gas.
Natural Gas		Several hydrocarbons that occur naturally underground in a gaseous state. Natural gas is normally mostly methane, but other components also include ethane, propane, and butane.
Natural Gas Act		Federal law enacted in 1938 that established the Federal Energy Regulatory Commission's authority to regulate interstate pipelines.
NGPL		Natural Gas Pipeline Company of America.
Niska Holdings		Niska Holdings L.P.
Optimization		The purchase, storage and sale of natural gas by the storage owner for its own account in order to utilize storage capacity that is (1) not contracted to customers, (2) contracted to customers but underutilized by them or (3) available only on a short term basis.
Reservoir		A naturally occurring underground formation that originally contained crude oil or natural gas, or both.
Withdrawal Capacity		The amount of gas that is or can be removed from a natural gas storage facility. Usually stated in MMcf per day, Bcf per day or Mcf per day. Typically stated as maximum or peak daily withdrawal capacity.
Withdrawal Rate		The rate at which a customer is permitted to withdraw gas from a natural gas storage facility.
Working Gas		Natural gas in a storage facility in excess of Cushion.
Working Gas Capacity		See Effective Working Gas Capacity.

Certain statements and information in this Annual Report on Form 10-K may constitute "forward-looking statements." Forward-looking statements are based on management's current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties, some of which are beyond our control. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this document. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Known material factors that could cause our actual results to differ from those forward-looking statements are those described in Part I, Item 1A, "Risk Factors."

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

We are a Delaware limited liability company who was formed in 2006 to own and operate natural gas storage assets. We own or contract for approximately 243.9 billion cubic feet, or Bcf, of total natural 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 natural 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 natural gas. Since our inception in 2006, we have added 106.3 Bcf of new storage capacity through low cost organic expansions, an increase of approximately 74%.

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 natural 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 natural 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.

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

On June 14, 2015, Niska Gas Storage Partners LLC ("Niska Partners" or the "Company"), the Manager, Holdco and certain of their affiliates entered into an Agreement and Plan of Merger and Membership Interest Transfer Agreement (the "Merger Agreement") with certain affiliates of Brookfield Infrastructure Partners L.P. and its institutional partners ("Brookfield"). Under the terms of the Merger Agreement, Brookfield will acquire all of the Company's outstanding common units for $4.225 per common unit in cash and will acquire all of the ownership interests in the Manager and all of the Incentive Distribution Rights ("IDRs") in the Company (the "Transaction") prior to June 14, 2017. A period provided for in the Merger Agreement for unsolicited consideration of alternative acquisition proposals expired on July 29, 2015.

The Merger Agreement, which includes a commitment by the Company not to make cash distributions until the earlier of the date of closing or termination of the Transaction, was approved by the Company's Board of Directors ("the Company Board") and the Conflicts Committee of its Board of Directors (the "Conflicts Committee"). Holdco, as the holder of approximately 53.93% of the issued and outstanding Common Units at the time of the Merger Agreement, delivered a written consent approving the Transaction. No additional unitholder action is required to approve the Transaction.

On February 29, 2016, the Company completed an amendment and extension of its Revolving Credit Facilities (defined below), which included the approval of a change of control associated with the Transaction. The amended and restated Revolving Credit Facilities extends the term of the original agreement from June 29, 2016 to September 30, 2016 and allows for an additional term extension to December 31, 2016 provided that the Transaction has closed. The maximum capacity of the amended and restated Revolving Credit Facilities was reduced to $320.0 million effective February 29, 2016. The

other substantive terms and conditions of the facilities were unchanged, other than with regards to the pricing and certain security interests.

The closing of the Transaction is dependent on the satisfaction of certain conditions related to regulatory requirements, including the approval of the CPUC. On June 9, 2016, the CPUC issued a decision which approved the transfer of control of the Wild Goose facility to Brookfield. The decision is effective immediately. The Company expects that the merger transaction will proceed in accordance with the terms of the Merger Agreement and that it will close on or prior to July 31, 2016.

The following diagram depicts our simplified organizational and ownership structure as at March 31, 2016:

Refer to the Schedule 14C Information Statement filed on January 4, 2016 for additional details pertaining to the Transaction.

Niska Sponsor Holdings Coöperatief U.A. ("Holdco") owns our manager, approximately 53.93% of our outstanding common units and all of our IDRs.

Over 95% of the equity in Holdco is owned by the Carlyle/Riverstone Funds and affiliated entities 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 conducts buyout and growth capital investments in the midstream, exploration and production, oilfield services, power and renewable sectors of the energy industry. Riverstone's management has substantial experience in identifying, evaluating, negotiating and financing acquisitions and investments.

Niska Gas Storage Management LLC, or "our manager," has a 1.80% managing member interest in us. Our manager has sole responsibility for conducting our business and for managing our operations. Pursuant to our Operating Agreement, our manager has delegated the power to conduct our business and manage our operations to our board of directors, all of the members of which are appointed by our manager. References to our board refer to the board of directors of Niska Gas Storage Partners LLC as long as the delegation is in effect (or to the board of directors of our manager if such delegation is not in effect). Our board directs the management of our business and presently

consists of eight members. Our manager appoints all members to our board, and three of our directors are independent as defined under the independence standards established by the NYSE.

We store natural gas for a broad range of customers, including financial institutions, marketers, pipelines, power generators, utilities and producers of natural gas. Fee-based revenue consists of longer term contracts for storage fees that are generated when we provide storage services on a monthly basis and shorter term fees associated with park and loan activities.

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

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

Reservation fees comprise over 90% of the revenue received from LTF storage customers, and represent a steady and predictable baseline cash flow stream.

We also provide short-term storage services for customers under short-term firm, or STF contracts. STF contracts typically have terms of less than one year; however can extend up to two years. 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 a fixed fee to withdraw on a specified future date or dates. The fee stipulated in the contract for each performance obligation (injection and withdrawal) is recognized when the service occurs. An STF contract differs from an LTF contract in that the customer is obligated to inject and withdraw specified quantities of natural gas on specified dates rather than entitled to utilize injection and withdrawal capacity at its option.

We purchase, store and sell natural gas for our own account in order to utilize, or optimize, storage capacity and injection and withdrawal capacity that is: (1) not contracted to customers;

(2) contracted to customers, but underutilized by them; or (3) available only on a short-term basis. We have a stringent risk policy that limits, among other things, our exposure to commodity price fluctuations by requiring us to promptly enter into a forward sale contract or other hedging transaction whenever we enter into a proprietary purchase contract. Therefore, inventory purchases are matched with forward sales or are otherwise economically hedged so that a margin is effectively locked in promptly after we enter into the purchase. As a result, there are no speculative positions beyond the minimal operational tolerances specified in our risk policy. We purchase natural gas for our own account, inject it and subsequently withdraw and sell the gas. The flexibility arising from purchasing and selling natural gas for our own account allows us to generate incremental value through our proprietary optimization strategy by capturing spot and inter-period opportunities. Unlike fee-based storage transactions, proprietary optimization requires us to fund the carrying cost of the inventory with our own working capital.

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

Our gas storage customers include a broad mix of natural gas market participants, including financial institutions, producers, marketers, power generators, pipelines and municipalities. Approximately 67% of the counterparties under our active natural gas storage contracts and proprietary storage optimization transactions either (1) have an investment grade credit rating, (2) provide us with another form of financial assurance, such as a letter of credit or other collateral, or (3) are governmental entities. Our fully secured and investment grade counterparties account for approximately 88% of our credit exposures as of March 31, 2016.

During certain reporting periods a large portion of our credit exposure can be attributed to one or two counterparties. These exposures reflect the full commodity value of natural gas sales under our optimization strategy.

We analyze the financial condition of our counterparties prior to entering into an agreement. Our exposure to the volume of business transacted with a natural gas clearing and settlement facility is mitigated by the facility's requirement to post margin deposits to reduce the risk of default. In the event of any default, the exchange would absorb losses by other clearing members. Because every member posts an initial margin, the exchange can protect the exchange members if or when a clearing member defaults.

Our owned and operated natural gas storage facilities consist of AECO Hub™ (comprised of two facilities in Alberta, Canada), our Wild Goose storage facility in California and our Salt Plains storage facility in Oklahoma. Our natural 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. 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 1.9 Bcf of natural gas storage capacity from Natural Gas Pipeline Company of America LLC, or NGPL, on its pipeline system in the mid-continent (Texas and Oklahoma) at cost-of-service based rates. The following table highlights certain important design information about our assets:

	AECO Hub™

	AECO Hub™								NGPL
	Suffield		Countess		Wild Goose		Salt Plains		NGPL
	Suffield		Countess		Wild Goose		Salt Plains		Midcon/ Texok
Name Location	Alberta		Alberta		California		Oklahoma		Midcon/ Texok		Total
Gas Storage Capacity (Bcf)		83.5		70.5		75		13		2.9		244.9
Peak Withdrawal (MMcf per day)		1,800		1,250		950		150		40		4,190
Peak Injection (MMcf per day)		1,600		1,150		525		115		20		3,410
Reservoirs		5		2		3		1		N/A		11
Storage Wells		60		29		17		30		N/A		136
Compression (horsepower)		36,000		34,500		27,900		10,000		N/A		108,400
In Service Date		1988		2003		1999		1995		N/A		1988 - 2003

On May 1, 2016, 1.0 Bcf of the 2.9 Bcf leased on NGPL capacity expired, thereby reducing our total capacity to 243.9 Bcf.

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

AECO Hub™ is located in the Western Canadian Sedimentary Basin, or the WCSB, which is the major hydrocarbon basin in Canada and one of the most prolific natural gas producing regions in North America. The WCSB accounts for a majority of annual Canadian natural gas production and a significant amount of annual North American natural gas production according to the Canadian National Energy Board, or NEB. Natural gas production grew in the WCSB in fiscal 2016 compared to fiscal 2015. Further, we expect that Canadian natural gas production will grow in future years to support expected LNG exports to serve Asian markets. New production to support these projects will be provided by large new shale and tight gas plays in northeast British Columbia and western Alberta, along with a large remaining conventional natural gas resource base.

AECO Hub™ is connected to the extensive Alberta System. Most of the natural gas produced in Alberta flows into the Alberta System, which transports that natural gas from the well or gas plant to industrial consumers and gas utilities in Alberta and to export pipelines at the Alberta border.

AECO Hub™ has been a central part of the Alberta System since the early 1990s, when the Suffield facility began providing title transfers as a hub service before that service was available on the pipeline. Many transactions were being transacted by storage customers and others at the Suffield facility and a new price index, known as the "AECO Hub™ Price Index," was developed to facilitate

price discovery. AECO Hub™ is the most commonly referenced pricing point for Canadian natural gas, and the price of natural gas in Alberta is often referred to as the "AECO Price."

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

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

Suffield Storage Facility. AECO Suffield is located in southeastern Alberta. It is near the Alberta System's "eastern gate," the largest natural gas delivery point in Canada, where gas is delivered into TransCanada's mainline pipeline system (transporting natural gas to eastern Canada and the northeastern U.S.) and the Foothills/Northern Border pipeline system (transporting natural gas to Chicago and the Midwestern U.S.). AECO Suffield consists of 60 storage wells and five storage reservoirs with aggregate effective working capacity of approximately 83.5 Bcf. The storage reservoirs are connected to a central processing and compression facility by a system of five pipelines. Compression is provided by natural gas powered engines that have a total of more than 36,000 horsepower.

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

Countess Storage Facility. AECO Countess is located in south central Alberta, approximately 60 miles east of Calgary. Countess is connected to a large diameter pipe of the Alberta System. This modern natural gas storage project consists of 29 storage wells and two high performance gas storage reservoirs that are connected to a central processing and compression facility. The two storage reservoirs each have their own gathering pipeline system. Compression is electrically powered and totals approximately 34,500 horsepower. The two reservoirs have total effective working capacity of approximately 70.5 Bcf.

AECO Hub™'s customers consist of a mix of natural gas market participants, including financial institutions, producers, marketers, power generators, and pipelines, resulting in a portfolio of customers with diverse usage patterns and varying contract expiration dates. This allows more opportunity for AECO Hub™ to optimize underutilized capacity.

Most of AECO's LTF contracts have capacity of 1.0 Bcf or greater. LTF contract terms have been selected so that a manageable amount of contracts expire each year, avoiding exposure to a large

contract turnover volume. The weighted average contract life of our LTF storage contracts at AECO Hub™ on March 31, 2016 was 2.9 years. Excluding our largest volumetric customer, TransCanada Gas Storage Partnership, or TransCanada, the weighted average contract life is 2.3 years with a weighted average volume of 2.7 Bcf.

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

Both AECO Hub™ facilities are subject to federal and provincial environmental laws and regulations, including oversight by Alberta's Department of Environment and Sustainable Resource Development and the AER. We are not aware of any material environmental liabilities relating to the AECO Hub™ facilities.

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

Wild Goose is strategically located in a highly liquid market and is one of four independent operating storage facilities in northern California. Wild Goose provides natural gas receipt and delivery services at Pacific Gas & Electric Company (PG&E), or PG&E Citygate, a liquid trading point where natural gas supply from multiple upstream basins is bought and sold to various wholesale, end use and retail market participants. This provides an opportunity for storage to balance supply and demand. This location provides customers with the opportunity to take advantage of PG&E Citygate pricing, liquidity and arbitrage opportunities.

Wild Goose operates 17 natural gas storage wells that are completed in three depleted natural gas reservoirs with an effective working capacity of 75.0 Bcf and a gas generated compression of 27,900 horsepower. The Wild Goose reservoirs are located in high quality rock formations. In addition, the reservoirs have a strong water drive mechanism, which helps maintain reservoir pressure and well deliverability. Rights to use the reservoirs at Wild Goose for natural gas storage are held pursuant to a series of natural gas storage leases with the surface owners of the lands where the reservoirs are situated as well as mineral owner agreements and similar instruments entered into with the holders of subsurface mineral interests in such lands. Rights for the lands used for the pipelines are derived from right-of-ways, easements, leases, and other similar land-use agreements.

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

Wild Goose has contracts for terms of one year or longer. As at March 31, 2016, the weighted average contract life of our LTF storage contracts at Wild Goose is 2.0 years.

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

We are not aware of any material environmental liabilities relating to the Wild Goose facility.

In constructing and expanding the Wild Goose facility, we have experienced no significant environmental-related delays or unexpected costs by initially bringing forward development plans that mitigate any environmental impacts to the satisfaction of all responsible agencies and stakeholders.

Our Salt Plains storage facility is located 110 miles north of Oklahoma City, Oklahoma. Salt Plains provides intrastate services in Oklahoma through its connection to pipelines operated by ONEOK Gas Transportation Pipelines, L.L.C., or ONEOK, and intrastate and interstate services through its interconnect with pipelines operated by Southern Star Central Gas Pipeline, Inc., or Southern Star.

Salt Plains is in a strategic mid-continent location with interconnects to pipelines owned by Southern Star and ONEOK, which serve both regional and mid-continent natural gas markets. This provides customers the benefits of liquidity, supply, and arbitrage opportunities. In addition, natural gas produced in the Rocky Mountains that is delivered to the mid-continent region gets redistributed to various pipelines such as Southern Star that have access to Salt Plains.

Salt Plains operates 30 gas storage wells and a gas generated compression of 10,000 horsepower. The reservoir is a depleted natural gas storage reservoir characterized by high quality rock. The wells are connected to a central plant facility by seven miles of pipeline. Rights to use the reservoir at Salt Plains for natural gas storage are held pursuant to a series of gas storage agreements with the mineral rights owners of the lands where the reservoir is situated. Rights for the lands used for the pipelines are derived under these gas storage agreements as well as from right-of-way grants from other land owners.

Over the years, Salt Plains' customers include a mix of natural gas market participants, including financial institutions, producers, and marketers. As of March 31, 2016, the weighted average contract life of our LTF storage contracts at Salt Plains was 2.3 years.

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

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

From 2001 to March 31, 2015, one of our subsidiaries had a contract for 8.5 Bcf of gas storage capacity on the MidCon section and the TexOk section of the NGPL pipeline system in the mid-continent. On April 1, 2015 and May 1, 2016, 5.6 Bcf and 1.0 Bcf, respectively, of the original 8.5 Bcf expired, thereby reducing our leased capacity to 1.9 Bcf. The NGPL system connects and balances Gulf Coast and mid-continent supply basins with Chicago and other Midwestern U.S. end-use markets. NGPL has a number of different storage facilities on its pipeline system and manages its storage capacity as pools on separate legs of the pipeline. Under NGPL's FERC-approved tariff, NGPL is limited to charging cost-of-service rates for its transportation and storage services. We have a tariff-based right of first refusal to renew the remaining contracts, effectively making this capacity a long-term asset without any invested capital.

As a customer of the NGPL capacity, and not the operator, we use our optimization strategy to generate revenue from our use of the capacity, and we do not remarket storage services.

We have a natural gas marketing business in Eastern Canada, British Columbia and Alberta serving commercial and industrial customers. In British Columbia, we also serve residential customers. This is a margin business where supply is contracted to serve customers at committed prices. In Eastern Canada, we also provide agency services to natural gas end-users. The retail marketing business is an extension of our proprietary optimization activities.

Our operations are subject to extensive laws and regulations that have the potential to have a significant impact on our business. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. We are subject to regulatory oversight by federal, state, provincial and local regulatory agencies, many of which implement rules and regulations that are binding on the natural gas storage and pipeline industry, related businesses and individual participants.

The failure to comply with such laws and regulations can result in substantial penalties. The cost of regulatory compliance on our operations increases our costs of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors.

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

Our natural gas storage operations are subject to stringent and complex federal, state, provincial and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges, and solid waste management. Such laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits and other approvals. These laws and regulations impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct certain activities under statutes such as the Clean Water Act, the Clean Air Act, or CAA, the Safe Drinking Water Act and comparable legislation in Canada, limiting or preventing the release of materials from our facilities, managing wastes generated by our operations, the installation of pollution control equipment, responding to releases of process materials or wastes from our operations, and the risk of substantial liabilities for pollution resulting from our operations. The Occupational Safety and Health Act, or OSHA, comparable state statutes that regulate the protection of the health and safety of workers, as well as the Occupational Health and Safety Act in the Province of Alberta, and comparable federal legislation in Canada also apply to our operations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil, and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. We believe that we are in substantial compliance with existing environmental laws and regulations and that such laws and regulations will not have a material adverse effect on our business, financial position or results of operations.

Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. These rules may require a number of modifications to our operations including the installation of new equipment to control emissions. Because much of the regulation is still being finalized, we cannot currently assess the potential impact of proposed regulations on our operations.

Several potential pieces of regulation that may affect our business are as follows:

In August 2015, the U.S. Environmental Protection Agency (the "EPA") issued its final Clean Power Plan rules that establish carbon pollution standards for power plants, called CO₂ emission performance rates. The EPA expects each state to develop implementation plans for power plants to meet the individual state targets established in the Clean Power Plan. The EPA has also given states the option to develop compliance plans for annual rate-based reduction limits (pounds per megawatt hour or mass-based tonnage) for CO₂.

Judicial challenges have been filed. On February 9, 2016, the U.S. Supreme Court granted a stay of the implementation of the CPP before the United States Court of Appeals for the District of Columbia ("Circuit Court") even issued a decision. By its terms, this stay will remain in effect

throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted. The stay suspends the rule, including the requirement that states submit their initial plans by September 2016. The Supreme Court's stay applies only to EPA's regulations for CO₂ emissions from existing power plants and will not affect EPA's standards for new power plants. It is not yet clear how either the Circuit Court or the Supreme Court will rule on the legality of the CPP. We are currently assessing the impact that the Clean Power Plan would have on the Company if the rules were upheld at the conclusion of this appellate process and were implemented in their current form.

In May 2015, the EPA issued a final rule that sets forth changes to its definition of "waters of the United States" ("Rule") under the Clean Water Act ("CWA"). Judicial challenges to this Rule have been filed in district courts across the country and the Sixth Circuit issued a nationwide stay on the Rule in October 2015. The Sixth Circuit also issued a decision in February 2016 that challenges to the Rule are properly heard in front of appellate courts, rather than district courts. The fate of lawsuits in the various district courts is therefore uncertain. Several district courts have already dismissed challenges following the Sixth Circuit's jurisdictional ruling and EPA is currently seeking to dismiss challenges in other district courts on the same grounds. It is possible, however, that the district courts could find that the Sixth Circuit's ruling is not binding. In addition, both the Tenth and Eleventh Circuits are also considering whether challenges to the Rule are properly heard at the district or appellate level in light of the Sixth Circuit's recent jurisdictional ruling. It remains to be seen how the various proceedings will affect the substance of the Rule and its implementation. If the Rule survives the appeals process, any expansion to CWA jurisdiction could impose additional permitting obligations on our operations, which may adversely affect any development or expansion we may plan to undertake.

On October 1, 2015, the EPA finalized both the 8-hour primary and secondary air quality standards for ground level ozone, reducing the acceptable level of ground level ozone to 70 parts per billion from 75 parts per billion. The EPA will now evaluate the states' attainment status and the states must determine whether additional control measures are needed in order to meet this standard. If states where we operate are not in attainment with this new standard, the EPA may enact additional regulations beyond those currently contemplated to further control emissions of volatile organic compounds and nitrogen oxides from certain sources, which could apply to our operations and could result in increased compliance costs. Niska Partners cannot predict the financial impact of the revised ozone standards at this time.

British Columbia imposes a carbon tax of C$30 per ton of carbon dioxide equivalent emissions. In November 2015, Alberta unveiled plans to institute an economy-wide carbon tax beginning in 2017. The C$20 per ton price on carbon emissions will cover approximately 90% of the economy, including natural gas, and will increase to C$30 per ton in 2018. These taxes could reduce demand for natural gas, have an adverse effect on our cost of doing business, and reduce demand for the natural gas storage services we provide, although we would not be impacted to any greater degree than other similarly-situated natural gas storage companies.

Following a major natural gas leak near Porter Ranch, California, the California Department of Conservation announced in February 2016 emergency regulations requiring enhanced testing, inspection and monitoring of oil and gas storage in California. Requirements include daily inspection of gas storage well heads, ongoing verification of the mechanical integrity of gas storage wells, ongoing

measurement of annular gas pressure or annular gas flow within wells, regular testing of all safety valves used in wells, compliance with minimum and maximum pressure limits, and establishment of a comprehensive risk management plan for each facility. The regulations will remain in effect for six months, but can be extended if necessary. The Department intends to develop permanent regulations after a public comment period. These regulations are likely to have an adverse effect on our costs of doing business, although we should not be impacted to any greater degree than other similarly situated natural gas storage companies.

In addition to these emergency regulations, it is possible that the Porter Ranch natural gas leak may lead to legislation or other regulations that would impose further regulatory requirements on natural gas storage. For instance, Senate Bill 887 introduced earlier this year would have imposed more rigorous inspection requirements on wells, required the adoption of more stringent standards for well design, installation and siting and the phase-out of non-complying wells over time. At this stage, it is impossible to say whether this proposed legislation or other legislation that may be proposed to further regulate natural gas storage will be enacted in California. If any such requirements are enacted into law in California and apply to our operations, complying with these more stringent standards could increase our costs of operations and restrict the scope of our operations. These requirements would apply to our competitors as well and we do not foresee that our operations or business would be impacted to any greater degree than other similarly situated natural gas storage companies.

As a result of these and similar developments, there can be no assurance of the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts that we currently anticipate. Moreover, these or similar developments could affect the demand for natural gas, have an adverse effect on our cost of doing business, and reduce demand for the natural gas storage services we provide.

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

There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases (GHGs). The Paris Agreement, which was announced by the Parties to the United Nations Framework Convention on Climate Change in December 2015, established a global goal of keeping temperatures well below 2 ºC above preindustrial levels. The Agreement is not legally binding on the parties, however. In the United States, future regulation of GHGs could occur pursuant to future U.S. treaty commitments. Under the Paris Agreement, the United States has pledged to reduce its emissions by 26 to 28% in 2025 relative to a 2005 baseline. While the U.S. will likely not need to take Congressional action to meet these initial commitments, further reductions would likely require domestic legislation beyond the Clean Power Plan, such as a carbon emissions tax or a cap-and-trade program.

While a new federal or international program seems unlikely in the near future, we may have to comply with state or regional programs to limit GHG emissions. State and regional programs that may impact our operations include the Western Climate Initiative (WCI) and the Regional Greenhouse Gas

Initiative (RGGI). The future status of RGGI, and agreement between the states in the Northeastern U.S. is uncertain. We do not believe that RGGI will impact our business because we do not currently have operations in RGGI member states. The WCI is an agreement that was originally between the states of California, Oregon, Washington, New Mexico, Arizona, Utah and Montana, and the Canadian provinces of British Columbia, Manitoba, Ontario, and Quebec to create a regional cap-and-trade scheme for GHG emissions. However, in 2011, all states except California withdrew from the WCI. Still, it is likely that regional efforts to curb GHG emissions will continue. Depending on the scope of any regional programs that we must comply with, we could be required to obtain and surrender allowances for GHG emissions statutorily attributed to our operations (e.g., emissions from compressor stations or the injection and withdrawal of natural gas).

In 2006, California adopted AB 32, the Global Warming Solutions Act of 2006, with a goal of reaching (i) 1990 GHG emissions levels by the year 2020, (ii) 80% of 1990 levels by 2050, and (iii) establishing a mandatory emissions reporting program. AB 32 directed the California Air Resources Board, or CARB, to begin developing discrete early actions to reduce GHGs while also preparing a scoping plan to identify how best to reach the 2020 limit. Since the passage of AB 32, the CARB approved in December 2010 a GHG cap-and-trade program, which was scheduled to take effect in 2012. Compliance obligations for some entities began in 2013. However, various legal challenges threaten to further delay California's cap-and-trade program. No final determination has been made with regard to the potential applicability of the AB 32 cap-and-trade program to our operations. We are therefore not in a position to quantify any potential costs associated with compliance under the program as proposed. However, any limitation a finalized program places on GHG emissions from our equipment and operations could require us to incur costs to reduce the GHG emissions associated with our operations.

Even in the absence of new federal legislation the EPA has begun to regulate GHG emissions using its authority under the CAA as articulated by the April 2007 United States Supreme Court ruling in Massachusetts, et al. v. EPA that the EPA has authority to regulate carbon dioxide emissions. The GHG regulations that the EPA has issued following Massachusetts , et al. v. EPA include: (1) the December 2009 "endangerment finding" determining that air pollution from six GHGs endangers public health and welfare, and that mobile sources cause or contribute to that air pollution; (2) the May 2010 "Tailpipe Rule," issued jointly with the National Highway Traffic Safety Administration setting GHG emission and fuel economy standards for new light-duty vehicles; (3) the April 2010 "Timing Rule," concluding that stationary source regulation under Titles I and V of the CAA (involving Prevention of Significant Deterioration regulations and operating permits, respectively) must regulate GHG emissions beginning when such emissions are subject to controls under the mobile source provisions of the Act; (4) the June 2010 "Tailoring Rule," exempting small stationary sources from PSD and Title V requirements through regulations modifying the Act's emissions thresholds; (5) the December 2010 "SIP Call" rule, finding thirteen state Implementation Plans ("SIPs") inadequate because they did not regulate GHGs from stationary sources, and directing those states to correct the inadequacies or face federalization of their permitting programs; and (6) the August 2015 Clean Power Plan (CPP), which establishes carbon pollution standards for power plants. For more information, see the "Adoption of the Clean Power Plan Regulations" section above.

If the CPP survives legal challenges, the rule could result in increased demand for natural gas. However, any expansion to the proposed program, or the adoption of similar legislative or regulatory programs in the future, that sought to reduce greenhouse gas emissions associated with the use of natural gas could reduce demand for natural gas, have an adverse effect on our cost of doing business, and reduce demand for the natural gas storage services we provide, although we would not be impacted to any greater degree than other similarly-situated natural gas storage companies. EPA's actions are subject to further procedural delays and legal challenges, however, and it is not yet clear how either the D.C. Circuit Court or the Supreme Court will rule on the legality of the CPP.

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

British Columbia has been in the process of implementing a cap-and-trade system consistent with the requirements of the WCI. The province has created a Climate Action Secretariat that is responsible for developing cap-and-trade rules. Ontario, another province participating in the WCI, committed to a phase out of coal fired power by 2014. Ontario closed its last coal-fired generating plant in April 2014. The current Ontario government brought forward Bill 138, Ending Coal for Cleaner Air Act, 2013. Subject to certain exceptions, the bill amends the Environmental Protection Act (Ontario) by adding a new part which prohibits the use of coal at generation facilities after December 31, 2014. The Ending Coal for Cleaner Air Act, 2013 is through its first reading and is still proposed legislation.

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

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

cost-of-service based rates and our ability to buy, sell and store natural gas for our own account enables us to optimize our working gas capacity. In addition, we are permitted to consolidate management, marketing, and administrative functions for efficiencies in matters that some competing operators are prohibited from due to affiliate rules to which they are subject.

As of March 31, 2016, we had 121 employees. Our executive officers are currently employed by Niska Gas Transport Inc., Niska Partners Management ULC and subsidiaries of Niska Gas Storage Partners LLC.

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

Our cash expenditures related to our optimization activities are typically highest during summer months, and our cash receipts from our optimization activities are typically highest during winter months. Consequently, our results of operations for the summer are generally lower than for the winter.

We make available, free of charge on our website (www.niskapartners.com), our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file the material with, or furnish it to, the Securities and Exchange Commission ("SEC").

The public may also read and copy any materials we have filed with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains a website that contains our reports, proxy and information statements and our other SEC filings. The address of that website is www.sec.gov.

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

There may be substantial disruption to our business and distraction of its management and employees as a result of the Transaction.

There may be substantial disruption to our business and distraction of our management and employees from day-to-day operations because matters related to the Transaction may require substantial commitments of time and resources which could otherwise have been devoted to other opportunities that could have been beneficial to us.

We may have difficulty attracting, motivating and retaining executives and other employees in light of the Transaction.

Our success depends in part upon our ability to retain our key employees. Some of those key employees may depart because of issues and uncertainty related to the Transaction or a desire not to remain following the Transaction. Accordingly, no assurance can be given that we will be able to retain key employees to the same extent as in the past.

The Transaction is subject to conditions, including certain conditions that may not be satisfied on a timely basis, if at all. Failure to complete the Transaction, or significant delays in completing the Transaction, could negatively affect the trading prices of our common units and our future business and financial results.

The completion of the Transaction is subject to a number of conditions. The completion of the Transaction is not assured and is subject to risks, including the risk that certain closing conditions are not satisfied. If the Transaction is not completed, or if there are significant delays in completing the Transaction, the trading prices of our common units and our future business and financial results could be negatively affected, and will be subject to several risks, including the following:

Our level of exposure to the market value of natural gas storage services could adversely affect our revenues.

As portions of our third-party natural 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:

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 and results of operations 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 competitive. The principal elements of competition among storage facilities are rates, terms of service, types of service, deliverability, supply and market access, flexibility and reliability of service. Our operations compete primarily with other storage facilities in the same markets in the storage of natural gas. The CPUC has adopted policies that favor the development of new storage projects and there are numerous projects, including expansions of existing facilities and greenfield construction projects, at various stages of development in the market where our Wild Goose facility operates. These projects, if developed and placed into service, may compete with our storage operations.

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

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

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

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

We depend upon third-party pipelines that provide delivery options to and from our storage facilities for our benefit and the benefit of our customers. Because we do not own these pipelines, their continuing operation is not within our control. These pipelines may become unavailable for a number of reasons, including testing, maintenance, line repair, reduced operating pressure, lack of operating capacity or curtailments of receipt or deliveries due to insufficient capacity. In addition, these third-party pipelines may become unavailable to us and our customers because of the failure of the interconnects that transport natural 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 natural gas into the third-party pipelines. If the costs to us or our 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 and results of operations.

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:

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. Natural gas that moves outside of the effective drainage area through migration could be permanently lost and will need to be replaced to maintain design storage performance.

Information technology systems present potential targets for cyber security attacks.

We are reliant on technology to improve efficiency in our business. Information technology systems are critical to our operations. These systems could be a potential target for a cyber security attack as they are used to store and process sensitive information regarding our operations, financial position, and information pertaining to our customers and vendors. While we take the utmost precautions, we cannot guarantee safety from all threats and attacks. Any successful breach of security could result in the spread of inaccurate or confidential information, disruption of operations, environmental harm, endangerment of employees, damage to our assets, and increased costs to respond. Any of these instances could have a negative impact on cash flows, litigation status and/or our reputation, which could have a material adverse affect on our business, financial conditions, and operations. There is no guarantee that adequate insurance to cover the effects of a cyber security attack will be available at rates we believe are reasonable in the near future or that the cost of responding to a breach will be covered by insurance or recoverable in rates.

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 and results of operations.

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.

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 and results of operations.

To the extent any one or more of these customers becomes financially distressed or commences bankruptcy proceedings, the contracts governing these customer relationships could be renegotiated at

lower rates or rejected under applicable provisions of the United States Bankruptcy Code. Any such renegotiation or rejection could have a material adverse effect on our revenue and cash flows and our ability to make cash distributions to our unitholders.

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

We have $575.0 million principal amount outstanding of the 6.50% senior notes due 2019. In addition, we have credit facilities that provide us up to $370.0 million in borrowing capacity. Our level of debt could have important consequences to us, including the following:

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 delaying our business activities, acquisitions, investments or capital expenditures. In addition, we may take actions such as selling assets, restructuring or refinancing our debt or seeking additional equity capital although we may not be able to effect any of these actions on satisfactory terms, or at all. Our inability to obtain additional financing on terms favorable to us or our inability to service our debt could have a material adverse effect on our business, results of operations and financial condition. 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 are 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 (defined below), 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 6.50% Senior Notes restrict or limit our ability to:

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 6.50% Senior Notes, the lenders or the note holders, 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 unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.

The indenture governing our 6.50% Senior Notes prohibits us from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, both the indenture and our Credit Agreement contain covenants limiting our ability to pay distributions to unitholders. The covenants apply differently depending on our fixed charge coverage ratio (defined substantively the same in the indenture and the Credit Agreement). If the fixed charge coverage ratio is greater than 1.75 to 1.0, we will be permitted to make restricted payments, including distributions to our unitholders, if the aggregate restricted payments since the date of our IPO, excluding certain types of permitted payments, are less than the sum of a number of items including, most importantly, operating surplus (defined similarly to the definition in our Operating Agreement) calculated as of the end of our preceding fiscal quarter and the aggregate net cash proceeds received by us as a capital contribution or from the issuance of equity interests, including the net proceeds received from our IPO. The indenture governing our 6.50% Senior Notes contains an additional general basket of $75.0 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 $320 Million Credit Agreement" and "Our 6.50% Senior Notes Due 2019." Any subsequent replacement of our Credit Agreement, our 6.50% 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 future 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. 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 to our unitholders in the future.

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 expand 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 may be unable to successfully complete accretive expansion or development projects or acquisitions for any of the following reasons:

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

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

may cause us to report significant non-monetary foreign currency exchange gains and losses in certain periods.

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

Our natural gas storage activities are subject to stringent and complex federal, state, provincial and local environmental and worker safety laws and regulations. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct certain activities, increases in operating expenses or curtailment of certain operations to limit or prevent releases of materials from our facilities, the incurrence of capital expenditures associated with the installation of pollution control equipment, and the imposition of substantial liabilities for pollution resulting from our operations. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. 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. In 2015, the U.S. pledged to reduce its greenhouse gases by 26 - 28% by 2025 under the recent Paris Agreement and the U.S. EPA finalized the Clean Power Plan, which will establish carbon pollution standards for power plants if it survives legal challenge. Future legislative and regulatory efforts could include cap-and-trade programs, carbon taxes and greenhouse gas reporting and tracking programs. Although it is not possible at this time to predict how legislation or regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased demand for natural gas. However, if such future laws and regulations are expansive enough to restrict greenhouse gas emissions associated with the use of natural gas, they could reduce the demand for natural gas and/or result in additional compliance costs or operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. In addition, some scientists have concluded that increasing concentrations of greenhouse gas in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets and operations. 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 AER has jurisdiction to regulate the technical aspects of construction, development, and operation of storage facilities. If approved to do so by the Alberta Government, the AUC, may also set prices for natural gas stored in Alberta. It is not currently Alberta Government policy to disturb market-based prices of independent natural gas storage facilities. If, however, the AUC was authorized to regulate the rates we charge, it could materially adversely affect our business. In addition, a connected pipeline tolling structure is available to our customers at AECO Hub™, allowing them to inject and withdraw natural gas without incremental transportation costs. There has been a decision to include the previously provincially-regulated Alberta System under the jurisdiction of the Federal National Energy Board, or NEB, and it is possible that the NEB could assume federal jurisdiction over, and set rates for, connected storage

facilities, including AECO Hub™, or invoke transportation toll design changes that negatively impact AECO Hub™.

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

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

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

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 EPA Act 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 EPA Act 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 natural gas storage rights underlying our storage facilities. In addition, title to some of our real property assets may have title defects which have not historically materially affected the ownership or operation of our assets. In either case, to recover our lost rights or to remove the title defects, we would be required to utilize significant time and resources. In addition, we might be required to exercise our power of condemnation to the extent available. Condemnation proceedings are adversarial proceedings, the outcomes of which are inherently difficult to predict, and the compensation we might be required to pay to the parties whose rights we condemn could be significant and could materially adversely affect our business, financial condition and results of operations.

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 and results of operations. See "Quantitative and Qualitative Disclosures About Market Risks—Risk Management Policy and Practices."

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

We use over-the-counter (OTC) derivative products to hedge commodity risks and, to a lesser extent, our currency risks. On July 21, 2010 new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us, that participate in that market. The Dodd-Frank Act requires the U.S. Commodity Futures Trading Commission ("CFTC"), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act and CFTC rules also may require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, the CFTC and certain banking regulators have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user

exception to the clearing, trade execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of our derivatives. In addition, if any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute derivatives to reduce risk and protect cash flows. As a result it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects.

The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

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

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

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

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

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.

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

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

Holdco owns and controls our manager. Our manager appoints all of the members of our board, which manages and operates us. Some of our directors and executive officers are directors or officers of our manager or its affiliates, including Holdco. Although our board has a contractual 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:

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

Our Operating Agreement among us, Holdco and others does not prohibit affiliates of our manager, including Holdco and the Carlyle/Riverstone Funds, from owning assets or engaging in businesses that compete directly or indirectly with us. 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 and results of operations.

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

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

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

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

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

Our Operating Agreement limits our manager's and directors' 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 replace 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 or directors to make a number of decisions in their individual capacities, as opposed to their capacities as our manager or directors, free of fiduciary duties to us and our unitholders. This entitles our manager and/or directors to consider only the interests and factors that they desire and relieves them of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our members. Examples of decisions that our manager and/ or directors may make in their individual capacities include:

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

Unitholders have little ability to remove our manager. The vote of the holders of at least 66²/3% of all outstanding common units and Notional Subordinated Units voting together as a single class is required to remove our manager. Holdco owns 53.93% of our outstanding common units and all of our Notional Subordinated Units. Accordingly, our public unitholders are currently unable to remove our manager without Holdco's consent because Holdco owns sufficient units to be able to prevent the manager's removal.

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

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

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

If at any time our manager and its affiliates own more than 80% of the common units, our manager will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price, as calculated pursuant to the terms of our Operating Agreement. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our manager is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our Operating Agreement that prevents our manager from issuing additional common units and exercising its call right. If our manager exercised its call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Our manager and its affiliates own approximately 53.93% of our outstanding common units.

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

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

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

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

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

We have 37,988,724 common units outstanding. 20,488,525 of the common units are owned by Holdco. Sales by Holdco or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we provided registration rights to Holdco. Under our Operating Agreement, our manager and its affiliates have additional registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.

Our tax treatment depends on our status as a partnership for federal tax purposes, as well as our not being subject to a material amount of entity-level taxation. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to you could be substantially reduced.

The anticipated after-tax benefit of an investment in our units depends on our being treated as a partnership for U.S. federal income tax purposes.

Despite the fact that we are organized as a limited liability company under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, the IRS has made no determinations regarding our treatment as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely be liable for state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because taxes would be imposed upon us as a corporation, our cash available for distribution to our unitholders could be substantially reduced. Therefore, our treatment as a corporation would result in a reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a reduction in the value of the units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a similar tax upon us as an entity, the cash available for distribution to you would be reduced and the value of our common units could be negatively impacted.

Our Operating Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to a material amount of entity-level taxation for U.S. federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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

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

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

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.

The tax treatment of publicly traded partnerships, companies with multinational operations, or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, companies with multinational operations, or an investment in entities such as Niska Gas Storage Partners LLC may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider such substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. If successful, the

Obama administration's proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

Further, on May 5, 2015, the Treasury Department and the Internal Revenue Service issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code (the "Proposed Regulations"). We do not believe the Proposed Regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.

Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

If a tax authority contests the positions we take, the market for our common units may be adversely impacted and the cost of any such contest will reduce our cash available for distribution to unitholders. In addition, recently enacted U.S. legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce cash available for distribution to you.

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

Recently enacted U.S. legislation applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1 to our members with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to you may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.

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

Unitholders are required to pay any U.S. federal income taxes, Medicare taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

In response to current market conditions, we may engage in transactions to deliver and manage our liquidity that may result in income and gain to our unitholders without a corresponding cash distribution. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, taking advantage of opportunities to reduce our existing debt, such as debt

exchanges, debt repurchases, or modifications of our existing debt could result in "cancellation of indebtedness income" (also referred to as "COD income") being allocated to our unitholders as taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect of any such allocations will depend on the unitholder's individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of COD income.

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

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

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

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

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

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis 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 generally 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 on the basis of the date a particular unit is transferred. The use of this proration

method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. However, such final regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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 the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of units) may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner 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, 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 as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

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

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

treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby a publicly traded partnership that has technically terminated may be permitted to provide only a single Schedule K-1 to unitholders for the two tax years within the fiscal year in which the termination occurs.

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

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

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

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

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

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

As of June 9, 2016 we had outstanding 37,988,724 common units, a 1.80% managing member interest and incentive distribution rights, or IDRs. The common units represent all of our limited partner interests and 98.20% of our total ownership interests excluding our IDRs. As discussed below under "Our Cash Distribution Policy—Incentive Distribution Rights," the IDRs represent the right to receive 48% of any quarterly cash distribution after our common unitholders have received the full quarterly distribution for each quarter plus any arrearages from prior quarters (of which there are currently none). Holdco currently owns approximately 53.93% of our outstanding common units and all of our IDRs.

Our common units, which represent limited liability company interests in us, are listed on the NYSE under the symbol "NKA." The following table sets forth for the indicated periods the high and low sales prices per unit for our common units on the NYSE:

On June 9, 2016, the closing market price for our common units was $4.16 per unit.

We have gathered tax information from our known unitholders and from brokers/nominees and, based on the information collected, we have approximately 12,029 beneficial unitholders at March 31, 2016.

No cash distributions were paid during the year ended March 31, 2016. Cash distributions paid to common unitholders for the year ended March 31, 2015 were as follows:

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

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

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

As of June 9, 2016, there were thirteen holders of record of our common units. The number of record holders does not include holders of units in "street names" or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

Our Operating Agreement contains a policy pursuant to which we pay regular quarterly cash distributions in an aggregate amount equal to substantially all of our cash available for distribution, after 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 previously suspended the quarterly distribution to common unitholders for the third and fourth quarters of fiscal 2015, and in June 2015 the Company entered into a definitive agreement to be acquired by Brookfield including a commitment by the Company not to make cash distributions until the earlier of the date of closing or termination of the Transaction. As a result, no cash distributions were made during the year ended March 31, 2016.

Our manager is entitled to 1.80% of all distributions that we make prior to our liquidation. Our manager has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current managing member interest if we issue additional membership interests in the future. The manager's 1.80% interest in distributions will be reduced if we issue additional membership interests in the future and our manager does not contribute a proportionate amount of capital to us to maintain its 1.80% managing member interest.

The IDRs entitle the Carlyle/Riverstone Funds to receive 48% of any quarterly cash distributions after our common unitholders have received the full minimum quarterly distribution ($0.35 per unit) for each quarter plus any arrearages from prior quarters. To date, the Company has not made any payments with respect to the IDRs.

There is no guarantee that unitholders will receive quarterly cash distributions from us, and the Company has committed under the definitive agreement to be acquired by Brookfield not to make any cash distributions until the earlier of the date of closing or the termination of the Transaction. If the Transaction is terminated under the terms of the agreement, our distribution policy is subject to other certain restrictions, including:

The following table shows selected historical consolidated financial and operating data of Niska Gas Storage Partners LLC for each fiscal year in the five-year period ended March 31, 2016.

The historical consolidated financial data presented for each fiscal year in the five-year period ended March 31, 2016 is derived from the audited financial statements for those respective periods, and should be read together with and are qualified in their entirety by reference to, the historical audited consolidated financial statements of Niska Gas Storage Partners LLC and the accompanying notes included in Item 8.

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

	Years Ended March 31,

	2016			2015			2014			2013			2012
	(dollars in thousands, except per unit amounts)
Consolidated Statement of Earnings Data:
Revenues(1)	$	54,345		$	98,319		$	207,396		$	140,695		$	268,581
Depreciation and amortization		57,435			117,323			41,286			50,409			46,132
Interest		52,301			51,336			66,315			67,010			74,630
Earnings (loss) before income taxes		(115,105	)		(382,312	)		(19,213	)		(62,543	)		(185,459	)
Net earnings (loss)		(103,331	)		(350,656	)		(8,957	)		(43,601	)		(165,772	)
Earnings (loss) per unit(2)		(2.67	)		(9.34	)		(0.25	)		(0.63	)		(2.39	)
Balance Sheet and Other Financial Data (at period end):
Total current assets	$	153,665		$	253,405		$	297,137		$	247,775		$	439,427
Total assets		991,897			1,160,959			1,539,191			1,524,392			1,803,358
Total debt(3)		730,673			779,426			706,725			722,274			807,179
Members' equity		80,639			185,671			554,140			597,377			690,390
Cash distributions declared (per unit):
Common units	$	—		$	1.05		$	1.40		$	1.40		$	1.40
Subordinated units(4)		—			—			—			—			0.70
Operational Data (unaudited):
Effective working gas capacity (Bcf)(5)		244.9			250.5			250.5			225.5			221.5
Capacity added during the period (Bcf)		—			—			25.0			4.0			17.0
Percent of operated capacity leased to third parties(6)		78.5	%		68.6	%		76.1	%		74.8	%		62.4	%

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

The historical financial statements included elsewhere in this document reflect the consolidated assets, liabilities and operations of Niska Gas Storage Partners LLC ("Niska Partners" or the "Company") as at March 31, 2016 and 2015, and for the years ended March 31, 2016, 2015 and 2014. The following discussion of the historical consolidated financial condition and results of operations should be read in conjunction with the historical financial statements and accompanying notes of the Company included elsewhere in this document. In addition, this discussion includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from statements we make. See "Forward-Looking Statements." Factors that could cause actual results to differ include those risks and uncertainties that are discussed in "Risk Factors."

We operate the AECO Hub^TM, which consists of the Countess and Suffield gas storage facilities in Alberta, Canada, and the Wild Goose and Salt Plains gas storage facilities in California and Oklahoma, respectively. Niska Partners markets gas storage services of working gas capacity in addition to optimizing storage capacity with its own proprietary gas purchases at each of these facilities. We also operate a natural gas marketing business which is an extension of our propriety optimization activities in Canada. The Company has a total of 243.9 Bcf of working gas capacity among its facilities, including 1.9 Bcf leased from a third-party pipeline company.

We earn revenues by providing natural gas storage services on a long-term firm ("LTF") contract basis for which we receive monthly reservation fees for fixed amounts of storage, providing storage services on a short-term firm ("STF") contract basis, where a customer pays a fixed fee to inject a specified quantity of natural gas on a specified date or dates and a fixed fee to withdraw on a specified future date or dates, and optimization, where we purchase and sell gas on an economically hedged basis in order to improve facility utilization at margins that can be higher than those from third-party contracts. Proprietary optimization activities occur when the Company purchases and sells natural gas for its own account. Our revenues related to our marketing business are included in proprietary optimization activities. We have aggregated all of our activities in one reportable operating segment for financial reporting purposes. Our consolidated financial statements are prepared in accordance with GAAP.

In June 2015, the Company, the Manager, Holdco and certain of their affiliates entered into a definitive agreement to be acquired by Brookfield. Under the terms of the Merger Agreement, Brookfield will acquire all of the Company's outstanding common units for $4.225 per common unit in cash and will acquire the Managing Member and the IDRs in the Company prior to June 14, 2017.

The closing of the Transaction is dependent on the satisfaction of certain conditions related to regulatory requirements, including the approval of the CPUC. On May 12, 2016, the CPUC issued a Proposed Decision, which if finally approved will allow the transfer of control of Wild Goose to Brookfield and also allow the Transaction to proceed to close in accordance with the Merger Agreement. The Proposed Decision can still be amended prior to being voted on by the CPUC and may or may not be approved by the CPUC.

The fiscal year ended March 31, 2016 reflected a continuation of difficult market conditions for Niska. Adjusted EBITDA for the year ended March 31, 2016 was $17.1 million, compared to $66.7 million in fiscal 2015 and $140.0 million in fiscal 2014. Included in the fiscal 2016 amounts are benefits of inventory write-downs of $45.2 million. Fiscal 2015 included a one-time contract termination settlement with our largest customer of $26.0 million and benefits from inventory write-downs of $23.1 million. Excluding these amounts, Adjusted EBITDA would have been negative $28.1 million for fiscal 2016 and positive $17.6 million for fiscal 2015. The unfavorable financial results in fiscal 2016 resulted from extraordinarily low seasonal spreads which substantially reduced the value of our storage

services, and reduced price volatility resulting from increased gas supply in the market which, in turn, reduced our ability to capture additional value based on changes in natural gas prices.

In addition, in fiscal 2016 and 2015 the Company recorded non-cash charges of additional depreciation of $24.5 million and $64.7 million respectively, associated with migration of cushion gas at its Canadian-based facilities. The combination of poor market conditions and non-cash charges resulted in a net loss for the fiscal 2016 of $103.3 million, compared to fiscal 2015 net loss of $350.7 million.

The Company's available liquidity consists of amounts available under its Revolving Credit Facilities and its Short-Term Credit Facility. In February 2016, the Company completed an amendment and extension of its Credit Agreement, which reduced the maximum capacity to $320.0 million and extends the term of the original agreement from June 29, 2016 to September 30, 2016 and allows for an additional term extension to December 31, 2016 providing that the Transaction has closed. The Company's fixed charge coverage ratio ("FCCR") has been below 1.1:1.0 since the first quarter of fiscal 2016 and as a result the Company continued to be unable to borrow the last 15% of availability under the Revolving Credit Facilities without triggering an event of default.

In connection with the entry into the Merger Agreement, Brookfield agreed to lend up to $50.0 million to the Company under a short-term credit facility to be used for working capital purposes. During fiscal 2016, reduced liquidity due to lower profitability was partially offset by the funds available under the Short-Term Credit Facility. As at March 31, 2016, the balance under the Short-term Credit Facility was $40.1 million, and the Company had $66.8 million of total available liquidity, compared to $80.1 million at March 31, 2015.

As we begin fiscal 2017, market conditions for natural gas storage are improving, with widening seasonal spreads and increasing volatility. The Company estimates that, based on expected revenues, of which over 80% have already been transacted across all revenue strategies, and expected costs, the Company will generate sufficient cash flow to fund its operations for the next twelve months, except for the repayment of the outstanding balances of the Revolving Credit Facilities and the Short-Term Credit Facility on their respective maturity dates. Failure to repay the Revolving Credit Facilities when due would also constitute an event of default under the terms of the 6.50% Senior Notes.

See also "How We Evaluate Our Operations—Capitalization, Leverage and Liquidity" and "Liquidity and Capital Resources."

A summary of financial and operating data for the years ended March 31, 2016, 2015 and 2014:

	Year Ended March 31,

	2016			2015			2014
	(dollars in thousands)
Consolidated Statement of Earnings (Loss) and Comprehensive Income (Loss) Data:
Revenues
Fee-based revenue	$	54,734		$	92,340		$	135,356
Optimization, net(1)		(389	)		5,979			72,040

		54,345			98,319			207,396
Expenses (Income):
Operating		29,806			39,230			40,834
General and administrative		29,993			26,833			39,937
Depreciation and amortization		57,435			117,323			41,286
Interest		52,301			51,336			66,315
Loss on extinguishment of debt(2)		—			—			36,697
Impairment of goodwill(3)		—			245,604			—
Losses (gains) on disposals of assets		268			(64	)		—
Foreign exchange (gains) losses		(349	)		380			1,182
Other (income) expense		(4	)		(11	)		358

Earnings (loss) before income taxes		(115,105	)		(382,312	)		(19,213	)
Income tax expense (benefit):
Current		2,536			2,595			82
Deferred		(14,310	)		(34,251	)		(10,338	)

		(11,774	)		(31,656	)		(10,256	)

Net earnings (loss) and comprehensive income (loss)	$	(103,331	)	$	(350,656	)	$	(8,957	)



Reconciliation of Adjusted EBITDA to net (loss) earnings:
Net earnings (loss)	$	(103,331	)	$	(350,656	)	$	(8,957	)
Add (deduct):
Interest expense		52,301			51,336			66,315
Income tax benefit		(11,774	)		(31,656	)		(10,256	)
Depreciation and amortization		57,435			117,323			41,286
Non-cash compensation expense		1,653			2,305			—
Impairment of goodwill		—			245,604			—
Unrealized risk management losses (gains)		16,566			(31,694	)		8,732
Loss on extinguishment of debt		—			—			36,697
Foreign exchange (gains) losses		(349	)		380			1,182
Losses (gains) on disposals of assets		268			(64	)		—
Other (income) expense		(4	)		(11	)		358
Write-downs of inventory		4,300			63,800			4,600

Adjusted EBITDA(4)		17,065			66,667			139,957
Add (deduct):
Cash interest expense, net		(48,225	)		(47,684	)		(62,961	)
Income taxes paid		(1,958	)		(50	)		(73	)
Maintenance capital expenditures		(2,926	)		(4,844	)		(1,575	)
Other income (expense)		4			11			(358	)

Cash Available for Distribution(4)	$	(36,040	)	$	14,100		$	74,990

	Year Ended March 31,

	2016			2015			2014
	(dollars in thousands)
Balance Sheet Data (at period end):
Total assets		991,897			1,160,959			1,539,191
Property, plant and equipment, net of accumulated depreciation		772,023			820,467			908,274
Long-term debt(5)		583,206			584,587			585,926
Total members' equity		80,639			185,671			554,140
Operating Data (unaudited):
Effective working gas capacity (Bcf)(6)		244.9			250.5			250.5
Capacity added during period (Bcf)		—			—			25.0
Percent of operated capacity contracted to third parties(7)		78.5	%		68.6	%		76.1	%

(1): Optimization revenue is presented net of cost of goods sold. Net optimization revenues include unrealized risk management gains/losses and write-downs of inventory. We had unrealized risk management losses of $16.6 million for the year ended March 31, 2016, unrealized risk management gains of $31.7 million for the year ended March 31, 2015, and unrealized risk management losses of $8.7 million for the year ended March 31, 2014. We had write-downs of inventory of $4.3 million, $63.8 million and $4.6 million for the years ended March 31, 2016, 2015 and 2014, respectively. Excluding these non-cash items, which do not affect Adjusted EBITDA, our realized optimization revenues were $20.5 million, $38.1 million and $85.4 million for the years ended March 31, 2016, 2015 and 2014, respectively.
(2): Loss on extinguishment of debt in the year ended March 31, 2014 relates to the redemption of our 8.875% Senior Notes due 2018 in March 2014. The loss consisted of a call premium of $28.6 million along with the write-off of unamortized deferred financing costs associated with the issuance of the 8.875% Senior Notes in 2010.
(3): Goodwill impairment in the fiscal year ended March 31, 2015 relates to goodwill in two subsidiaries that was determined to be fully impaired and, therefore, an impairment charge of $245.6 million was recorded.
(4): Adjusted EBITDA and Cash Available for Distribution in fiscal 2016 include the benefits of inventory write-downs related to inventory impairments of $45.2 million (fiscal 2015—$23.1 million; fiscal 2014—$2.4 million). Excluding these benefits, Adjusted EBITDA would have been negative $28.1 million for fiscal 2016 (fiscal 2015—$43.6 million; fiscal 2014—$137.6 million) and Cash Available for Distribution would have been negative $81.2 million for fiscal 2016 (fiscal 2015—negative $9.0 million; fiscal 2014—$72.6 million).
(5): Long-term debt includes long-term obligations under capital lease, but excludes credit facility drawings which are recorded in current liabilities.
(6): Represents operated and NGPL-leased capacity. Effective working gas capacity data is as at March 31 of each year. In April 2015, 5.6 Bcf of leased capacity from NGPL expired, bringing our total NGPL-leased capacity down to 2.9 Bcf.
(7): Excludes NGPL-leased capacity of 2.9 Bcf in fiscal 2016, and 8.5 Bcf in fiscal years prior.

The following table sets forth average volume utilized by, and revenue and fees/margins derived from LTF contracts, STF contracts and proprietary optimization transactions for each of the years in the three-year period ended March 31, 2016:

	Year Ended March 31,

	2016			2015			2014
Storage Capacity (Bcf) utilized by:
LTF Contracts		98.1			90.7			109.5
STF Contracts		91.9			75.4			74.7
Proprietary optimization transactions		54.9			84.4			66.3

Total		244.9			250.5			250.5



Revenue (in thousands)
Fee-based contracts:
LTF Contracts	$	36,263		$	80,781		$	83,940
STF Contracts		18,471			11,559			51,416

		54,734			92,340			135,356
Optimization:
Realized proprietary optimization transactions		20,477			38,085			85,372
Unrealized risk management (losses) gains		(16,566	)		31,694			(8,732	)
Write-downs of inventory		(4,300	)		(63,800	)		(4,600	)

		(389	)		5,979			72,040

Total	$	54,345		$	98,319		$	207,396



Fees/Margins ($/Mcf)
LTF Contracts(1)	$	0.37		$	0.89		$	0.77
STF Contracts		0.20			0.15			0.69
Realized proprietary optimization transactions		0.37			0.45			1.29

We use the non-GAAP financial measures Adjusted EBITDA and Cash Available for Distribution in this report. A reconciliation of Adjusted EBITDA and Cash Available for Distribution to net earnings (loss), the most directly comparable financial measure as calculated and presented in accordance with GAAP, is shown above.

We define Adjusted EBITDA as net earnings (loss) before interest, income taxes, depreciation and amortization, unrealized risk management gains and losses, loss on extinguishment of debt, foreign exchange gains and losses, write-downs of inventory, gains and losses on asset dispositions, non-cash compensation, asset impairments and other income. We believe the adjustments for other income are similar in nature to the traditional adjustments to net earnings used to calculate Adjusted EBITDA and adjustment for these items results in an appropriate representation of this financial measure. Cash Available for Distribution is defined as Adjusted EBITDA reduced by interest expense (excluding amortization of deferred financing costs), income taxes paid, maintenance capital expenditures and other income. Adjusted EBITDA and Cash Available for Distribution are used as supplemental

financial measures by our management and by external users of our financial statements, such as commercial banks and ratings agencies, to assess:

The GAAP measure most directly comparable to Adjusted EBITDA and Cash Available for Distribution is net earnings. The non-GAAP financial measures of Adjusted EBITDA and Cash Available for Distribution should not be considered as alternatives to net earnings (loss). Adjusted EBITDA and Cash Available for Distribution are not presentations made in accordance with GAAP and have important limitations as analytical tools. Neither Adjusted EBITDA nor Cash Available for Distribution should be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and Cash Available for Distribution exclude some, but not all, items that affect net earnings (loss) and are defined differently by different companies, our definition of Adjusted EBITDA and Cash Available for Distribution may not be comparable to similarly titled measures of other companies.

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

Similarly, Cash Available for Distribution has certain limitations because it accounts for some, but not all, of the above limitations.

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:

We provide fee-based natural gas storage services to our customers under long-term firm (LTF) and short-term firm (STF) contracts. When a customer enters into a LTF contract, the customer is obligated to pay us monthly reservation fees for a fixed amount of storage which is usable by the customer at their option subject to contractual limits. These fees are fixed regardless of the actual use by the customer, and we also collect a variable fee when the services are actually used in order to allow us to recover our variable operating costs. The volume-weighted average life of our LTF contracts at March 31, 2016 was 2.6 years. Reservation fees comprise over 90% of the revenue generated under LTF contracts and provide a baseline of revenue to support our operating and general and administrative costs.

We also provide fee-based services under short-term firm (STF) contracts, where a customer pays a fixed fee to inject a specified quantity of gas on a specified date or dates and to withdraw on a specified future date or dates.

We monitor both the volume and price of our LTF and STF contracts in order to evaluate the effectiveness of our marketing efforts as well as the relative attractiveness of each of these types of contracts compared to each other as well as in comparison to our optimization strategy. During periods when market values for storage capacity are higher, we typically use more of our capacity under LTF contracts. The fees we are able to generate from our LTF and STF contracts reflect market conditions, including interest rates. The capacity used for STF contracts depends, among other things, on available capacity not reserved under LTF contracts as well as market demand and contract rates available for these services.

When market conditions warrant, we enter into economically hedged transactions with available capacity. This can achieve higher margins than can be obtained from third-party contracts. Because we economically hedge our transactions, we are able to determine in advance the minimum margins that will be realized and add incremental margins by re-hedging as market conditions change.

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

When evaluating the performance of our optimization business, we focus on our realized optimization margins, excluding the impact of unrealized hedging gains and losses and inventory write-downs. For accounting purposes, our realized optimization revenues include the impact of unrealized economic hedging gains and losses and inventory write-downs, which cause our reported revenues to fluctuate from period to period. However, because substantially all inventory is economically hedged, any inventory write-downs are offset by hedging gains and any unrealized hedging losses are offset by gains when the inventory is sold. These offsetting gains and losses may occur in different periods.

Our most significant variable operating expenses are fuel and electricity costs. These operating expenses vary significantly based upon the amount of natural 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 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.

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

We regularly monitor our credit metrics. Our most important credit metric is our fixed charge coverage ratio, or FCCR, which is contained in the Indenture to our 6.50% Senior Notes and our Credit Agreement. The FCCR measures our Adjusted EBITDA divided by fixed charges, both of which are defined in the Indenture and Credit Agreement. As discussed below, when our FCCR is below 2.0 times, we are restricted in our ability to issue new debt. When our FCCR is below 1.75 times, we are restricted in our ability to pay distributions. When our FCCR is below 1.1 times, we are unable to borrow the last 15% of availability without triggering an event of default. We also monitor our ratio of long-term and total debt to Adjusted EBITDA and our ratio of debt to debt plus equity. While these metrics are not included in our Indenture or Credit Agreement, they are common metrics used to measure the credit-worthiness of companies, including those similar to us.

As of March 31, 2016, we had a FCCR of 0.3 to 1.0, a ratio of total debt to Adjusted EBITDA of 42.8 times, a ratio of long-term debt to Adjusted EBITDA of 34.2 times and a ratio of long-term debt to long-term debt plus equity of 87.9%.

Funding the purchase of proprietary optimization inventory can consume a significant portion of our available working capital. Accordingly, we closely monitor the utilization and remaining available capacity under our credit facilities and actively pursue additional short-term firm contracts when we determine it is appropriate to maintain liquidity.

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

During the first half of fiscal 2016, the difference between summer and winter prices in the natural gas futures market, referred to as the seasonal spread, remained extremely narrow. This condition

resulted from numerous factors, including, but not limited to: (i) production curtailments in Alberta due to prolonged compressor outages on the TransCanada Alberta System and high cash prices at PG&A Citygate during injection season; (ii) lower levels of natural gas in storage which led to increased demand in the cash market; (iii) real or perceived changes in overall supply and demand fundamentals; (iv) the development of new pipeline infrastructure connecting new supply to markets; (v) the weather during the first part of winter being milder than normal; and (vi) a material year-over-year increase in natural gas production in the United States as well as in Western Canada during the winter withdrawal season. These market conditions have negatively impacted our revenues during the year ended March 31, 2016 by eroding the prices we can charge for long and short-term firm contracting services, as well as reducing the profitability of our optimization activities, where we make economically hedged natural gas purchases for our own account.

The combination of reductions in natural gas prices, collateral required to support our retail marketing operations, costs associated with the requirements for temporary reservoir pressure support and unfavorable market conditions which have prevented us from realizing additional revenues and earnings have reduced the liquidity available under our credit facilities. Continued reduction in amounts available under our credit facilities may continue to restrict our ability to pursue optimization strategies. The inability to pursue such revenue strategies may have a material adverse effect on the Company's revenues and profitability.

Market conditions for natural gas storage can change rapidly as a result of a number of factors, including weather patterns, overall storage levels across North America in the markets we serve, current and anticipated levels of natural gas supply and demand, and constraints on pipeline infrastructure capacity. Accordingly, current market conditions may not be a reliable predictor of future market conditions. Longer term, we believe several factors may contribute to meaningful growth in North American natural gas demand, including: (i) exports of North American Liquefied Natural Gas; (ii) fuel switching for power generation from coal to natural gas; (iii) construction of new gas-fired power plants; (iv) growing exports to Mexico; and (v) growth in base-load industrial demand, all of which could bolster the demand for, and the commercial value of, natural gas storage. We are unable to predict the timing or magnitude of such events nor can we predict the ultimate impact they may have on our results of operations.

Changes in working gas capacity are expected to impact the level of our revenue. For the fiscal year ended March 31, 2016, our contract for 5.6 Bcf of the 8.5 Bcf leased capacity on NGPL expired thereby reducing our gas storage capacity to approximately 244.9 Bcf . On May 1, 2016, 1.0 Bcf of the remaining 2.9 Bcf leased capacity on NGPL expired, thereby reducing our gas storage capacity to approximately 243.9 Bcf. We do not expect these changes will cause a significant reduction to future earnings.

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 reduce operating costs and add incremental margin and economic value, independent of the period in which that revenue is earned. This may result in the deferral of realized earnings and cash flow from one fiscal year to the next. This was evident during the year ended March 31, 2015, when increased gas supply in the United States resulted in a reduction in the demand for natural gas in storage and resulted in an overall decline in near-term natural gas prices. Due to the contango position of the forward market, we deferred the withdrawal of proprietary optimization inventory until fiscal 2016. As a result, proprietary optimization inventory at March 31, 2015 was relatively high at approximately 48 MDth, as compared to March 31, 2016 proprietary inventory levels of 26 MDth. The year over year decrease in proprietary

optimization was driven by a reduction in capacity allocated to the strategy in the current period, offset by an increased allocation to fee-based transactions.

Cushion migration occurs when hydrocarbons move to an area of the storage reservoir where effective support in cycling a facility's working gas is no longer provided. During the years ended March 31, 2016, 2015 and 2014, we recorded charges to depreciation expense of $24.5 million, $64.7 million and $nil, respectively, related to 2.4 Bcf, 6.2 Bcf and nil Bcf of proprietary cushion estimated to have migrated at our Canadian facilities. We currently estimate that ongoing cushion migration could require an annual expenditure of approximately $4.0 million to $6.0 million to replace the cushion gas that has migrated. These estimates include assumptions about storage levels and cycling requirements which can vary significantly depending on operating conditions.

In addition, our storage facilities may require additional natural gas to provide temporary pressure support during periods of high activity to meet cycling requirements and performance demands related to our gas in storage. These volumes fluctuate from year to year along with our cycling requirements. These cycling requirements are managed through a combination of strategies which are adapted to changes in natural gas market conditions. Typically, the use of gas to provide temporary pressure support results in net revenue gains because the cost to acquire natural gas in the nearer term is lower than the price of natural gas for future delivery.

Backwardation, a condition where the price of natural gas in the near term is higher than the price for future delivery, occurred in the winter of fiscal 2014 and spring of fiscal 2015. This increased our costs to manage our cycling requirements, which include the purchase or lease of natural gas used for temporary pressure support. The cost of temporary pressure support gas was approximately $2.2 million in fiscal 2016 (fiscal 2015—$40.0 million). Over the upcoming four years, the expected cumulative cost of temporary pressure support gas is $5.5 million which relates to our commitments to lease certain volumes of natural gas to address our future temporary pressure support needs. In the event that natural gas storage market conditions become more favorable, the cost of managing our operational requirements could be reduced. However, if the conditions deteriorate, the cost of managing our operational requirements will increase.

In May 2014, we entered into a new contract with TransCanada, our largest volumetric customer. This new contract replaced a previous storage agreement which provided TransCanada with approximately 40 Bcf of storage capacity at our AECO facilities and had a term that extended to 2030. Under the previous storage agreement both parties had the option to terminate at the end of defined five-year intervals, including April 1, 2015. TransCanada elected to terminate this agreement and entered into a new agreement with us which extends until 2020. The new agreement provides TransCanada with an initial storage capacity of approximately 40 Bcf which will be reduced to approximately 20 Bcf on April 1, 2017. By exercising its early termination rights, TransCanada was obligated to make an early termination payment to us of $26.0 million. This payment was recognized in long-term firm revenue in fiscal 2015. The new rate under the renegotiated contract is lower than the rate previously in effect in prior fiscal periods, resulting in a decrease to LTF revenues in fiscal 2016.

The variable operating costs of our facilities are primarily comprised of costs associated with natural gas and electricity for compressor operations. Our operating costs are affected by the amount and price of energy used to inject and withdraw natural gas from our facilities and by the number and timing of gas injections and withdrawals. For example, if we experience large injections of natural gas

in the early summer (instead of a steady rate of injections throughout the summer), we would have higher costs in our first quarter and lower than expected costs in the second quarter. A mild winter could lead to less withdrawals in total, and therefore lower overall fuel and power costs because less injections would occur in filling our storage facilities. These cost variances could be partially offset by similar variances in long-term contract revenues. During the year ended March 31, 2016, operating expenses were lower than the year ended March 31, 2015, principally due to lower facility utilization, and lower average fuel and electricity prices.

Our cost of capital and the amount of our available working capital impacts the amount of capacity utilized for proprietary optimization as compared to STF contracts. Proprietary optimization requires us to purchase inventory, which is financed by cash on hand and our credit facilities. A higher cost of capital relative to that of our customers will generally lead to lower volume used for proprietary optimization transactions. In general, higher carrying costs for us or our customers result in lower margins for us. During the 2016 fiscal year, the combination of reductions in natural gas prices, margin amounts required to support our retail marketing operations, unfavorable market conditions and a reduction in our net credit facility availability has prevented us from realizing additional revenues and earnings. Continued reduction in amounts available under the credit facilities may restrict our ability to pursue optimization strategies. The inability to pursue such revenue strategies may have a material adverse effect on our revenues and profitability.

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.

During the past several years, North America has experienced a dramatic increase in the supply of natural gas, principally from the development of unconventional natural gas sources, including shale gas. These increases in supply have been coupled with build-outs of natural gas pipeline capacity in certain areas of the United States, which generally have the effect of increasing deliverability of natural gas to more North American markets and dampening the price differentials for natural gas between geographic markets, including those served by us. We are unable to determine or predict the direct impact on our business from these developments. However, we believe that the market will return to a more balanced level because gas demand is expected to increase in the medium term due to (1) a forecasted increase in base load industrial demand, (2) construction of new gas fired power plants and coal to gas switching (3) increased exports to Mexico, and (4) exports of LNG.

Our functional currency is the U.S. dollar. We generate revenues from our Canadian operations in Canadian dollars. Cash inflows from revenues are offset, in part, by natural gas inventory purchases, operating, general and administrative and capital costs that are also transacted in Canadian dollars. The majority of our hedges are transacted in U.S. dollars on the New York Mercantile Exchange (NYMEX). Our financial instruments, principally our Common Units, Senior Notes and credit facilities, are predominantly denominated in U.S. dollars. We hedge our net exposure to the Canadian dollar by entering into currency hedges for the substantial majority of net exposure for our transactions. We do not hedge our net Canadian dollar exposure for potential future transactions, as the timing and amount of those transactions, which include proprietary optimization purchases and sales, are difficult to predict. During fiscal 2016, the decline in the value of the Canadian dollar did not materially impact

our results of operations because its impact on revenues has been offset by lower expenses and hedging gains realized during the period.

Inflation has been relatively low in recent years and did not have a material impact on our results of operations for the years ended March 31, 2016, 2015 and 2014. Although the impact of inflation has been insignificant in recent years, it remains a factor in the current economy.

Our process for the identification of reportable segments involves examining the nature of services offered, the types of customer contracts entered into and the nature of the economic and regulatory environment. Since our inception, we have operated along functional lines in our commercial, engineering and operations teams for operations in Alberta, northern California and the U.S. midcontinent. All functional lines and facilities offer the same services: fee-based revenue and optimization. All services are delivered using reservoir storage. All facilities have the same types of customers: major companies in the energy industry, industrial, commercial, and local distribution companies and municipal energy consumers. We also have a marketing business which is an extension of our proprietary optimization activities. Proprietary optimization activities occur when we purchase, store and sell natural gas for our own account in order to utilize or optimize storage capacity that is not contracted or available to third party customers. We measure profitability consistently along all functional lines based on revenues and earnings before interest, taxes, depreciation and amortization, and unrealized risk management gains and losses. We have aggregated our functional lines and facilities into one reportable segment as at and for the fiscal years ended March 31, 2016, 2015 and 2014.

Information pertaining to our fee-based and proprietary optimization revenues is presented in the consolidated statements of earnings (loss) and comprehensive income (loss).

Fiscal Year Ended March 31, 2016 Compared to Fiscal Year Ended March 31, 2015

	Year Ended March 31,

	2016			2015			2014
	(in thousands)
Long-term contract revenue	$	36,263		$	80,781		$	83,940
Short-term contract revenue		18,471			11,559			51,416

Total fee-based revenue		54,734			92,340			135,356

Realized optimization, net		20,477			38,085			85,372
Unrealized risk management (losses) gains		(16,566	)		31,694			(8,732	)
Write-downs of inventory		(4,300	)		(63,800	)		(4,600	)

Total optimization revenue		(389	)		5,979			72,040

Total revenue	$	54,345		$	98,319		$	207,396

Fiscal Year Ended March 31, 2015 Compared to Fiscal Year Ended March 31, 2014

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

We purchase natural gas and build inventories in the summer months. We position sales in the winter months, which results in the peak borrowing under our $320 million Credit Agreement being highest in the middle of our third fiscal quarter, while our peak accounts receivable collections typically occur in our fourth fiscal quarter. During fiscal 2016, we experienced an unusual storage season when we recognized revenue more evenly throughout the year.

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

	Year Ended March 31, 2016

	Qtr 1			Qtr 2			Qtr 3			Qtr 4			Total
	(in thousands)
Fee-based revenue:
LTF revenue	$	9,645		$	8,928		$	8,754		$	8,936		$	36,263
STF revenue		4,617			3,724			4,473			5,657			18,471

		14,262			12,652			13,227			14,593			54,734
Realized optimization:
Realized optimization, net		5,314			5,065			6,686			3,412			20,477

Total realized revenue		19,576			17,717			19,913			18,005			75,211
Realized quarterly revenue as a percentage of total realized annual revenue		26.0	%		23.6	%		26.5	%		23.9	%		100.0	%

	Year Ended March 31, 2015

	Qtr 1			Qtr 2			Qtr 3			Qtr 4			Total
	(in thousands)
Fee-based revenue:
LTF revenue(1)	$	40,482		$	14,101		$	13,373		$	12,825		$	80,781
STF revenue		2,272			1,532			2,255			5,500			11,559

		42,754			15,633			15,628			18,325			92,340
Realized optimization:
Realized optimization, net		13,774			4,458			7,013			12,840			38,085

Total realized revenue		56,528			20,091			22,641			31,165			130,425
Realized quarterly revenue as a percentage of total realized annual revenue		43.3	%		15.4	%		17.4	%		23.9	%		100.0	%

The Company's available liquidity consists of amounts available under its Revolving Credit Facilities and its Short-Term Credit Facility. In February 2016, the Company completed an amendment and extension of its Credit Agreement, which reduced the maximum capacity to $320.0 million and extends the term of the original agreement from June 29, 2016 to September 30, 2016, and allows for an additional term extension to December 31, 2016 provided that the Transaction has closed. However, the Company's FCCR has been below 1.1:1.0 since the first quarter of fiscal 2016 and, as a result, the Company has been unable to utilize the last 15% of availability under the Revolving Credit Facilities without triggering an event of default.

In connection with the entry into the Merger Agreement, Brookfield agreed to lend up to $50.0 million to the Company under a short-term credit facility to be used for working capital purposes. During fiscal 2016, reduced liquidity resulting from lower profitability, and the absence of the last 15% of availability under the Revolving Credit Facilities was partially offset by the funds available under the Short-Term Credit Facility from Brookfield, as well as the liquidation of optimization inventories, and the return of a portion of posted margin deposits associated with the Company's marketing business.

As at March 31, 2016, available liquidity totaled $66.8 million, consisting of $56.9 million available under the Revolving Credit Facilities and $9.9 million available under the Short-Term Credit Facility

from Brookfield. At June 6, 2016, available liquidity was $89.2 million, consisting of $79.3 million available under the Revolving Credit Facilities and $9.9 million available under the Short-Term Credit Facility from Brookfield.

As we begin fiscal 2017, market conditions for natural gas storage are improving, with widening seasonal spreads. The Company estimates that, based on expected revenues, of which over 80% have already been transacted across all revenue strategies, and expected costs, the Company will generate sufficient cash flow to fund its operations for the next twelve months, except for the repayment of the outstanding balances of the Revolving Credit facilities and the Short-Term Credit Facility on their respective maturity dates. Failure to repay the Revolving Credit Facilities when due would also constitute an event of default under the terms of the 6.50% Senior Notes.

See also "How We Evaluate Our Operations—Capitalization, Leverage and Liquidity."

In addition to the underlying profitability of our business, our cash flows are significantly influenced by our level of natural gas inventory, margin deposits and related forward purchase and 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 natural 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 natural gas, store it, and then sell it in a later period. In addition, we have margin requirements on our economically hedged positions. As the cash deposits we make to satisfy our margin requirements increase and decrease with our volume of derivative positions and changes in commodity prices, our cash flows from operating activities may fluctuate significantly from period to period.

The following table summarizes our sources and uses of cash for the fiscal years ended March 31, 2016, 2015 and 2014:

	Year Ended March 31,

	2016			2015			2014
	(in thousands)
Operating Activities
Net earnings (loss)	$	(103,331	)	$	(350,656	)	$	(8,957	)
Adjustments to reconcile net earnings to net cash provided by (used in) operating activities:
Unrealized foreign exchange (gains) losses		(206	)		372			1,500
Deferred income tax benefit		(14,310	)		(34,251	)		(10,338	)
Unrealized risk management losses (gains)		16,566			(31,694	)		8,732
Depreciation and amortization		57,435			117,323			41,286
Amortization of deferred financing costs		4,076			3,652			3,354
Loss on extinguishment of debt		—			—			36,697
Losses (gains) on disposals of assets		268			(64	)		—
Impairment of goodwill		—			245,604			—
Non-cash compensation expense		1,653			2,305			—
Write-downs of inventory		4,300			63,800			4,600
Changes in non-cash working capital		90,854			(55,835	)		15,033

Net cash provided by (used in) operating activities	$	57,305		$	(39,444	)	$	91,907



Net cash used in investing activities	$	(3,133	)	$	(7,573	)	$	(5,166	)



Net cash (used in) provided by financing activities	$	(55,807	)	$	51,726		$	(89,244	)



Other information:
Proprietary inventory (at year-end)	$	41,268		$	136,295		$	75,140

Operating Activities. The variability in net cash provided by operating activities is primarily due to (1) changes in market conditions that exist during any given fiscal period, which impacts the margins earned under each of our fee-based 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. When we purchase and store natural gas, we borrow under our credit facilities to pay for it, which negatively impacts operating cash flow. Cash flow from operating activities increases when we collect the cash from the sale of inventories.

Cash provided by operating activities for the year ended March 31, 2016 was $57.3 million compared to cash used in operating activities of $39.4 million during the year ended March 31, 2015. The increase in cash provided by operating activities principally reflects the decision to hold on to a significant volume of inventory at the end of fiscal 2015 and sell that inventory during fiscal 2016. Positive cash flows from operating activities were offset by the lower profitability after non-cash gains, losses and expenses were excluded.

During fiscal 2015, the reduction in cash provided by operating activities was principally related to lower profitability and higher margining requirements associated with our retail business, combined with our decision to hold proprietary inventories over the end of fiscal 2015 in order to sell them in fiscal 2016.

	Year Ended March 31,

	2016			2015			2014
	(in thousands)
Changes in non-cash working capital:
Margin deposits	$	52		$	19,342		$	(14,137	)
Trade receivables		(256	)		3,114			(3,383	)
Accrued receivables		8,629			110,484			(44,459	)
Natural gas inventory		90,727			(124,955	)		3,676
Prepaid expenses and other assets		(6,421	)		542			358
Deferred revenue		(6,212	)		596			5,468
Accrued liabilities		4,609			(63,709	)		68,106
Other		(274	)		(1,249	)		(596	)

Net changes in non-cash working capital	$	90,854		$	(55,835	)	$	15,033

Working Capital. Working capital is defined as the amount by which current assets exceed current liabilities. Our working capital is affected by the relationship between unrealized risk management hedges which are marked-to-market on a monthly basis, the margin deposits required by our brokers for such gains and losses, proprietary inventory which is stored in our facilities and cash used to fund inventory purchases.

As of March 31, 2016 we had a net working capital deficiency of $79.5 million (working capital ratio of 0.7 to 1.0, which is calculated by dividing current assets by current liabilities), compared to a net working capital deficiency of $24.6 million (working capital ratio of 0.9 to 1.0) as at March 31, 2015. The increase in cash flows from changes in working capital principally reflects the decision to hold on to a significant volume of inventory at the end of fiscal 2015 and sell that inventory during fiscal 2016.

Investing Activities. Most of the investing activities during the fiscal year ended March 31, 2016 and 2015 were attributed to maintenance activities. 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. A significant drawdown of natural gas inventory in the fourth quarter of fiscal 2014 resulted in significant operational burdens on our facilities and therefore, required additional maintenance capital expenditures during fiscal 2016 and 2015.

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

Our capital expenditures for the years ended March 31, 2016, 2015 and 2014 were as follows:

Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives.

Expansion capital expenditures are investments that serve to increase operating income over the long term through greater capacity or improved efficiency in Niska's operations, whether through construction or acquisition.

Under our current plan, we expect to spend approximately $11.0 million to $13.0 million in fiscal 2017 for maintenance capital expenditures to maintain the integrity of our storage facilities and ensure the reliable injection, storage and withdrawal of natural gas for our customers. Included in our estimated maintenance capital expenditures for fiscal 2017 is $6.0 million related to expected cushion gas purchases. Expansion capital for fiscal 2017 is expected to be less than $1.0 million.

We have senior unsecured notes due 2019 (the "6.50% Senior Notes" or "Notes") for which interest is payable semi-annually on October 1 and April 1 at a rate of 6.50% per year, and will mature on April 1, 2019. See Note 8 "—Senior Notes due 2019" in our Consolidated Financial Statements for more information.

We are in compliance with all covenant requirements under the 6.50% Senior Notes.

We have senior secured asset-based revolving credit facilities, consisting of a U.S. and a Canadian revolving credit facility (the "Revolving Credit Facilities", or the "Credit Agreement"). These credit facilities in aggregate provide a maximum borrowing capacity of $320.0 million, and can be drawn on up to the lesser of the borrowing base asset or the maximum borrowing capacity. See Note 8 "—Revolving Credit Facilities" in our Consolidated Financial Statements for more information.

Our most recently calculated borrowing base as of June 6, 2016 was $233.4 million. We also had $100.0 million in borrowings outstanding under our Revolving Credit Facilities and had $19.1 million in letters of credit issued. We are in compliance with all covenant requirements under our Credit Agreement.

We have an agreement with Brookfield for a $50.0 million short term credit facility (the "Short-term Credit Facility"), for which borrowings bear interest at an annual rate of 10%. Interest is payable in cash on a quarterly basis, unless the Company elects to pay such interest in-kind by capitalizing accrued interest into the principal amount. See Note 8 "—Short-term Credit Facility" in our Consolidated Financial Statements for more information.

As of June 6, 2016, we had $41.1 million in borrowings outstanding under our Short-term Credit Facility and were in compliance with all covenant requirements.

The following table summarizes by period the payments due for our estimated contractual obligations as of March 31, 2016:

	Payment due by period

	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years
	(in thousands)
Long term debt obligations	$	575,000	$	—	$	575,000	$	—	$	—
Interest on long term debt obligations		112,125		37,375		74,750		—		—
Operating lease obligations		14,738		6,166		7,162		1,410		—
Capital lease obligations		10,545		1,657		3,314		3,314		2,260
Leased storage contracts		917		917		—		—		—
Mineral and surface leases		192,592		3,892		7,768		7,885		173,047
Asset retirement obligations		60,565		—		—		—		60,565
Post-retirement obligation		2,500		—		—		—		2,500
Deferred income tax		908		744		164		—		—
Withholding taxes (including interest and penalties)		4,751		4,751		—		—		—
Purchase obligations(1)		1,018,000		629,022		377,890		11,088		—

Total	$	1,992,641	$	684,524	$	1,046,048	$	23,697	$	238,372

In the future we may use off-balance sheet arrangements such as undrawn credit facility commitments, including letters of credit, to finance portions of our capital and operating needs. See "—Contractual Obligations" for more information.

On January 1, 2010, we entered into an operating lease for compression and other equipment related to the development of an expansion project at Wild Goose. See "Note 20—Commitments and Contingencies" for more information.

The historical financial statements included in this document have been prepared in accordance with GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires our judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. Our judgments and estimates are based on what we believe are the best and most relevant information available to us at the time our financial statements are prepared.

The following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the application of GAAP. These estimates affect, among other items, revenue recognition and expense accruals, migration of cushion, assessing income tax expense including the requirement for a valuation allowance against deferred income tax assets, calculating unit-based compensation, valuing of risk management assets and liabilities, inventory and identified intangible assets.

Description		Judgments and Uncertainties

*Revenue Recognition*
See Note 2, Significant Accounting Policies, of our Consolidated Financial Statements for a complete discussion of our revenue recognition policies. Revenues are recognized when collectability is reasonably assured. Collectibility is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers' financial position (e.g. cash position and credit rating) and their ability to pay. If collectability is not considered reasonably assured at the outset of an arrangement in accordance with our credit review process, revenue is recognized when the fee is collected.		Our revenue recognition accounting process contains uncertainties because it requires us to make a judgment on the collectability of revenue at the outset of an arrangement. In addition, our revenue also includes unrealized risk management gains and losses which require us to estimate fair value of our risk management contracts.

Description		Judgments and Uncertainties

*Fair Value of Risk Management Assets and Liabilities*
We use natural gas derivatives and other financial instruments to manage our exposure to changes in natural gas prices and foreign exchange rates. These financial assets and liabilities, which are recorded at fair value on a recurring basis, are included into one of three categories based on a fair value hierarchy. The fair value of our derivative contracts are recorded as risk management assets and liabilities, which are classified as either current assets, non-current assets, or liabilities based upon the anticipated settlement date of the contracts. The determination of the fair value of these derivative contracts reflects the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.		There are uncertainties in our methodology in the determination of fair value since it requires us to consider various factors, including over-the-counter quotations, location differentials and closing foreign exchange rates underlying the contracts. Although the fair value of our risk management assets and liabilities may fluctuate, such fluctuations are offset by equivalent changes in the value of our physical inventory. Our policy is for our inventory and purchases to be economically hedged, within small tolerances permitted under our risk management policy, so we are not exposed economically to the risk of fluctuating commodity prices.
*Inventory*
Our inventory is natural gas injected into storage and held for resale. Inventory is valued at the lower of average cost or market. Adjustments to write down the costs of inventory to market are recorded as an offset to optimization revenues while costs to store the gas are recognized as operating expenses in the period the costs are incurred.		At the end of each reporting period we determine whether a write-down is required to reduce inventory to the lower of cost or market value. This determination has built-in uncertainties since it requires judgment in estimating fair market values in the periods to which our inventory is economically hedged and the level of a normal margin compared to selling price in those periods.
*Cushion Effectiveness*
Certain volumes of cushion are required for maintaining a minimum field pressure. Cushion is considered a component of the facility and as such is not depreciated. Cushion is monitored to ensure that it provides effective pressure support. In the event that natural gas moves to another area of the reservoir where it does not provide effective pressure support, charges against cushion are included in depreciation in an amount equal to the cost of estimated volumes that have migrated.		Cushion requirements and its effectiveness are estimated using pressure and volumetric data accumulated over many years of storage operation. The data is added into a complex reservoir model which accounts for different dynamic phenomena occurring within the reservoir. The information incorporated into the model includes pressure gradients within the reservoir, water encroachment due to an active aquifer, tight reservoir components which slowly capture and release back some of the gas stored and a cushion migration component. These phenomena influence one another and the level of uncertainty of the estimate of cushion present in a reservoir.

Description		Judgments and Uncertainties

*Impairment of Intangible Assets*
See Note 2, Significant Accounting Policies, on our Consolidated Financial Statements for a complete discussion of our policy regarding Intangible assets. Intangible assets are reviewed for impairment as impairment indicators arise. When such events or circumstances are present, the recoverability of intangible assets is assessed by determining whether the carrying value will be recovered through the expected undiscounted future cash flows. In the event that the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset's carrying value over its fair value is recorded.		These types of analyses contain uncertainties because they require management to make assumptions and apply judgment to estimate future cash flows, the profitability of future business strategies, industry conditions and other economic factors.
*Income taxes*
We are not a taxable entity in the United States. Income taxes are the responsibility of the individual partners and have accordingly not been recorded in the consolidated financial statements. We have corporate subsidiaries, which are taxable corporations subject to Canadian federal and provincial income taxes, which are included in the consolidated financial statements. See Note 2, Significant Accounting Policies, of our Consolidated Financial Statements for a complete discussion of policy in accounting for income taxes.		Our accounting for income taxes has inherent uncertainties since it requires us to estimate the timing of the realization of our tax assets and liabilities, including the allocation of income among different entities and tax jurisdiction, and also requires us to make assumptions on the estimated probabilities of utilization of deferred tax assets and on the determination of tax exposures associated with our tax filing positions.

Description		Judgments and Uncertainties

*Unit-based compensation*
See Note 2, Significant Accounting Policies, on our Consolidated Financial Statements for a complete discussion of policy in accounting for unit-based compensation. The fair value of unit-based awards that are expected to be settled in cash is determined on the date of grant and is re-measured at each reporting period until the settlement date. The fair value at each re-measurement date is equal to the settlement expected to be incurred based on the anticipated number of units vested adjusted for (1) the passage of time and (2) the payout threshold associated with the performance targets which we expect to achieve compared to our established peers. Compensation expense is calculated as the re-measured expected payout less previously-recognized compensation expense.		There are uncertainties in our calculation of unit-based compensation since it requires us to make assumptions and judgments on the estimated probabilities of meeting our performance measures, forfeiture rate and unit price at settlement date.
The fair value of unit-based awards that are expected to be settled in units is determined on the date of grant and is amortized into equity using the straight-line method over the vesting period.

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

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

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

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

At March 31, 2016, we have 25.5 MDth of natural gas inventory of which 25.3 MDth or 99.2% was economically hedged. Because inventory is recorded at the lower of cost or market, not fair value, if the price of natural gas increased by $1.00 per MMBtu the value of that inventory would increase by $25.5 million, but the fair value or mark-to-market value of our hedges would decrease by $25.3 million, because 0.8% (0.2 MDth) of that inventory that was not economically hedged. Conversely, if the price of natural gas declined by $1.00 per MMBtu, the value of that inventory would decrease by $25.5 million while the fair value of our hedges would increase by only $25.3 million, due to the non-economically hedged position. Fuel gas included in the volumes above that is used for operating our facilities is not offset. Total volume of our fuel gas was 0.3 MDth and 0.0 MDth as of March 31, 2016 and 2015, respectively.

In addition to the volumes mentioned above, as at March 31, 2016, we have entered into forward purchase contracts for 1.5 MDth of natural gas representing 42% of our estimated cushion purchases in fiscal 2017. As a result of the unhedged portion of expected cushion gas purchases, a $1.00 per MMBtu increase or decrease would have a corresponding increase or decrease to the net cost of our cushion gas purchase by approximately $2.1 million.

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

One of Niska Partners' operating facilities, the Wild Goose storage facility, is located in California. In 2006, California adopted AB 32, the Global Warming Solutions Act of 2006, with a goal of reaching: (i) 1990 greenhouse gases ("GHG") emissions levels by the year 2020; (ii) 80% of 1990 levels by 2050; and (iii) a mandatory emission reporting program. AB 32 required the California Air Resources Board ("ARB") to develop a scoping plan describing the approach California will take to reduce GHGs to achieve the goal of reducing emissions to 1990 levels by 2020 (the "2020 Goal"). The scoping plan was first approved by the ARB in 2008 which identifies a cap-and-trade program as one of the strategies California will employ to meet the 2020 Goal. In 2010, ARB approved that cap and trade program and it came into effect on January 1, 2013.

Entities are subject to compliance obligations if they exceed certain ARB-defined emission thresholds. During each year of the program, the ARB issues emission allowances (i.e., the rights to

emit GHGs) equal to the amount of GHG emissions allowed for that year. Emitters can obtain allowances from the ARB at quarterly auctions, from third parties or exchanges. Emitters may also satisfy a portion of their compliance obligation through the purchase of offset credits; e.g., credits for GHG reductions achieved by third parties (such as landowners, livestock owners, and farmers) that occur outside the industry sectors covered under the cap through ARB-qualified offset projects such as reforestation or biomass projects. During fiscal 2016, the Company determined that it had exceeded its allowed emissions threshold and became subject to compliance obligations whereby it must purchase allowances or offset credits. As of March 31, 2016, the Company had $0.8 million of accrued emission allowances and offset credits, and the Company was exposed to risks associated with changes in the price of credits for GHG reductions.

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

Canadian dollar cash inflows from revenues are offset, in part, by natural gas inventory purchases, operating, general and administrative and capital costs that are also transacted in Canadian dollars. We hedge the substantial majority of our remaining net exposure to the Canadian dollar by entering into currency hedges for existing transactions to minimize the risks of changes in the exchange rate. These instruments are primarily swaps transacted to purchase or sell U.S. dollars, as required. As a result of our hedging program, we do not believe that a change in the Canadian exchange rate would have a significant impact on the results of our operations.

At March 31, 2016, we had forward currency exchange contracts for a notional value of $38.3 million. The value of the forward currency contracts were in a net liability position of $0.1 million as of March 31, 2016 (2015—net asset of $3.2 million), and were recorded in derivative assets and derivative liabilities accounts on the consolidated balance sheets. These contracts expire on various dates between April 2016 and February 2017 and were for the exchange of $49.9 million Canadian dollars into $38.3 million U.S. dollars.

We are exposed to interest rate risk due to variable interest rates under our Revolving Credit Facilities. All such borrowings under the Credit Agreement bear interest at different rates. As of March 31, 2016, we had $115.6 million in borrowings and letters of credit issued under the Revolving Credit Facilities, and it currently provides an interest rate on borrowings between 4.19% and 6.75%, depending on whether a fixed term or floating rate option is chosen. In the future, we may borrow under fixed rate and variable rate debt instruments that also give rise to interest rate risk. Changes in economic conditions could result in higher interest rates, thereby increasing our interest expense and reducing our funds available for capital investment, operations or distributions to our unitholders. A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by approximately $1.9 million for the fiscal year ended March 31, 2016.

Counterparty credit risk is the risk of financial loss if a customer fails to perform its contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. Credit risk associated with trade and accrued receivables is mitigated by the high

percentage of investment grade customers, collateral support of receivables and our ability to take ownership of customer-owned natural gas stored in its facilities in the event of non-payment.

Margin deposits, or letters of credit in lieu of deposits, are required on derivative instruments utilized to manage our counterparty credit risk. As commodity prices increase or decrease, the fair value of our derivative instruments changes thereby increasing or decreasing our margin deposit requirements. Rising commodity prices or an expectation of rising prices could increase the cash needed to manage our commodity price exposure and thereby increase our liquidity requirements, limit amounts available to us through borrowing and reduce the volume of natural gas we may purchase. Exchange traded futures and options have minimal credit exposure as the exchanges guarantee every contract will be margined on a daily basis. In the event of any default, our account on the exchange would be absorbed by other clearing members. Because every member posts an initial margin, the exchange can protect the exchange members if or when a clearing member defaults.

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

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

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

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

Optimization activities can only be executed by employees authorized to transact under the risk policy. All commercial personnel are annually required to read and certify that they will adhere to the

principles purported within the policy. Each person authorized to make transactions is subject to internal volume limits. Counterparties are subject to credit limits as approved by our credit department.

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

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

The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth on pages F-4 through F-49 of this Annual Report on Form 10-K and are incorporated herein by reference.

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

Our principal executive officer (CEO) and principal financial officer (CFO) undertook an evaluation of our disclosure controls and procedures as of the end of the period covered by this report. The CEO and CFO have concluded that our controls and procedures were effective as of March 31, 2016. For purposes of this section, the term "disclosure controls and procedures" means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

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

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

There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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

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

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

Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal by the member of our manager. Our executive officers serve at the discretion of our board. There are no family relationships among any of the directors or executive officers. The following table shows information as of June 9, 2016, regarding our current directors and executive officers.

Name		Position

William H. Shea, Jr.	61	Chairman, President, Chief Executive Officer and Director
Vance E. Powers	59	Chief Financial Officer
Mark D. Casaday	55	Chief Operating Officer
Rick J. Staples	53	Executive Vice President and Chief Commercial Officer
Robert B. Wallace	55	Vice President, Finance and Corporate Development
Jason A. Dubchak	43	Vice President, General Counsel and Corporate Secretary
Bruce D. Davis, Jr.(1)	59	Former Vice President and Chief Administrative Officer
Ralph Alexander	61	Director
Michael Hennigan	56	Director
James G. Jackson	52	Director
E. Bartow Jones	40	Director
Stephen C. Muther	67	Director
Andrew W. Ward	49	Director
Olivia C. Wassenaar	36	Director

William H. Shea, Jr.—Mr. Shea is our Chairman, President and Chief Executive Officer and a member of our board and the board of directors of our manager and also serves on the compensation committee. Mr. Shea served as a director of PVR GP, LLC, the general partner of PVR Partners L.P. and Chief Executive Officer of Penn Virginia Resource Partners, L.P. from March 2010 to March 2014, as Chief Executive Officer of PVR GP, LLC from March 2010 to June 2012 and as President and Chief Executive Officer of PVR GP, LLC since June 2012. Previously, Mr. Shea served as the Chairman of Buckeye GP LLC, the general partner of Buckeye Partners, L.P., a refined petroleum products pipeline partnership from May 2004 to July 2007, as President and Chief Executive Officer of Buckeye GP LLC from September 2000 to July 2007 and as President and Chief Operating Officer of Buckeye GP LLC from July 1998 to September 2000. From August 2006 to July 2007, Mr. Shea served as Chairman of MainLine Management LLC, the general partner of Buckeye GP Holdings, L.P., and as President and Chief Executive Officer of MainLine Management LLC from May 2004 to July 2007. Mr. Shea also serves as a director of Kayne Anderson Energy Total Return Fund, Inc. Kayne Anderson MLP Investment Company, and USA Compression Holdings LLC and as Chief Executive Officer of Mainline Energy Partners, LLC. Mr. Shea has an agreement with Riverstone, pursuant to which he has agreed to serve on the boards of Carlyle/Riverstone Funds' portfolio companies.

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

Vance E. Powers—Mr. Powers is our Chief Financial Officer. Mr. Powers has served as our Chief Financial Officer since January 1, 2011. Mr. Powers has over 25 years of experience in senior financial, accounting, and reporting positions. From April 2010 until commencing service as Niska's Chief Financial Officer, Mr. Powers served as a finance management consultant to Niska, assisting in the completion of Niska's initial public offering, its transition to a publicly-traded company and its establishment of an investor relations function. From May 2009 to March/April 2010, Mr. Powers was an individual investor. From December 2003 to May 2009, Mr. Powers served as Vice President, Finance and Controller of Buckeye GP LLC, the general partner of Buckeye Partners, L.P. (NYSE: BPL), one of the largest refined petroleum products pipeline and terminal companies in the United States, where he was a key member of the senior executive team and was principally responsible for Buckeye's accounting, financial reporting, planning and analysis and treasury functions. He also served Buckeye GP LLC as Acting Chief Financial Officer from July 2007 until November 2008, where he was additionally responsible for capital markets activities and investor relations. He held similar positions with MainLine Management LLC, the general partner of Buckeye GP Holdings L.P. (NYSE: BGH), and participated in BGH's initial public offering in August 2006. Mr. Powers holds a MBA degree from Lehigh University and a BA from Gettysburg College. He is also a Certified Public Accountant in Pennsylvania.

Mark D. Casaday—Mr. Casaday is our Chief Operating Officer. He served as an Executive Vice President of Penn Virginia Resource GP LLC at PVR Partners LP from June 2012 to March 2014 and its Chief Operating Officer—Midstream of Penn Virginia Resource GP LLC from January 2013 to March 2014. Mr. Casaday served as Chief Operating Officer, Midstream of Marcellus at Penn Virginia Resource GP LLC, the General Partner of Penn Virginia Resource Partners LP from June 2012 to January 2013. From 1998 to February 2012, Mr. Casaday served as President and Chief Executive Officer of Pentex Natural Gas Company. Mr. Casaday also serves as Chief Operating Officer of Mainline Energy Partners, LLC.

Rick J. Staples—Mr. Staples is our Executive Vice President and Chief Commercial Officer, responsible for the marketing, trading and commercial operation of our natural gas storage assets. Previously, Mr. Staples was in the role of Senior Vice President, Commercial Operations from May 2006 to April 2012. He has 30 years of experience in the energy industry, with a primary focus on the midstream sector, including natural gas storage. Prior to joining us in 2006, Mr. Staples served as Director of Gas Storage with TransCanada Pipelines Ltd. from 2001 to 2006. Mr. Staples graduated from the University of Alberta with a degree in Mechanical Engineering. Mr. Staples also graduated from the Queens Executive program (Queens School of Business) in 1997.

Robert B. Wallace—Mr. Wallace is our Vice President of Finance and Corporate Development. He served as the Chief Financial Officer and Executive Vice President of PVG GP LLC from March 2010 to March 2014. Mr. Wallace served as Chief Financial Officer and Executive Vice President of Penn Virginia Resource GP LLC, the General Partner of Penn Virginia GP Holdings LP and Penn Virginia Resource Partners LP since March 2010. He served as Senior Vice President of Finance and Chief Financial Officer of Buckeye Pipe Line Company LLC, a general partner of Buckeye Partners LP since September 1, 2004. Mr. Wallace served as Senior Vice President of Finance and Chief Financial Officer of Buckeye GP LLC, the prior general partner of Buckeye Partners LP since September 2004 and served as its Principal Accounting Officer. He served as Senior Vice President of Finance and Chief Financial Officer of MainLine Management LLC, the General Partner of Buckeye GP Holdings LP since September 1, 2004. Prior to UBS, Mr. Wallace held senior positions at Dean Witter Reynolds, and Shearson Lehman Brothers in New York. He has more than 20 years of corporate finance experience, was an Executive Director in the UBS Energy Group from September 1997 to February 2004 and a private investor and consultant to Buckeye GP LLC from February 2004 to September 2004. Mr. Wallace also serves as Chief Financial officer of Mainline Energy Partners, LLC. Mr. Wallace received a Masters of Business Administration from New York University and a Bachelor of Arts from St. Lawrence University.

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

Ralph Alexander—Mr. Alexander is a member of our board and serves on the compensation committee. He is a Partner of Riverstone Holdings LLC and joined Riverstone in September 2007. During 2007, Mr. Alexander served as a consultant to TPG Capital. For nearly 25 years, Mr. Alexander served in various positions with subsidiaries and affiliates of BP plc, one of the world's largest energy firms. From June 2004 until December 2005, he served as Chief Executive Officer of Innovene, BP's $20 billion olefins and derivatives subsidiary. From 2001 until June 2004, he served as Chief Executive Officer of BP's Gas, Power and Renewables and Solar segment and was a member of the BP group executive committee. Prior to that, Mr. Alexander served as a Group Vice President in BP's Exploration and Production segment and BP's Refinery and Marketing segment. He held responsibilities for various regions of the world, including North America, Russia, the Caspian, Africa and Latin America. Prior to these positions, Mr. Alexander held various positions in the upstream, downstream and finance groups of BP. In addition to serving on the boards of a number of Riverstone portfolio companies and their affiliates, Mr. Alexander is a director of EP Energy Corporation since September 2013 and is on the Board of the general partner of Enviva Partners, LP, which had an IPO in 2015. He previously served on the board of Stein Mart Corporation, KiOR Inc., Amyris, Inc., Foster Wheeler AG and Anglo American plc. He holds a B.S. and M.S. in nuclear engineering from Brooklyn Polytech (now NYU Polytechnic) and holds an M.S. in management science from Stanford University. He is currently Chairman of the Board of NYU Polytechnic and is a New York University Trustee. The

Company believes Mr. Alexander's extensive experience with the energy industry enables him to provide essential guidance to the board of directors.

Michael J. Hennigan—Mr. Hennigan is a member of our board and serves on both the audit committee and the compensation committee (as Chairman). Mr. Hennigan has been the Chief Executive Officer of Sunoco Partners LLC, a General Partner of Sunoco Logistics Partners L.P. since March 1, 2012 and its President since June 2010. Mr. Hennigan is responsible for all operations and business activities, including setting the direction, strategy and vision for Sunoco Logistics. He has 25 years of experience with Sunoco. He served as the President of Sunoco Partners LLC since July 1, 2010. He served as the Chief Operating Officer of Sunoco Partners LLC from July 1, 2010 to March 1, 2012 and Sunoco Logistics Partners since July 1, 2010. He served as Vice President of Business Development for Sunoco Partners LLC from May 2009 to June 2010. Prior to joining Sunoco Logistics, he served as Senior Vice President of Business Improvement at Sunoco, Inc., from October 2008 to May 15, 2009 and served as its Vice President of Business Development since May 2009. He serves as a Director of Philadelphia Energy Solutions LLC. He has been a Director of Sunoco Partners LLC, a General Partner of Sunoco Logistics Partners L.P. since April 27, 2010. He served as a Director of SunCoke Energy Inc., of Jewell Coke Company, L.P. from June 2011 to January 17, 2012. He is Chairman of the Advisory Council for the College of Engineering. Mr. Hennigan holds a BS degree in Chemical Engineering from Drexel University in 1982. The Company believes Mr. Hennigan's ongoing role at Sunoco Logistics Partners L.P. and past experience in Director roles in the energy business provides unique and valued guidance to the board of directors.

James G. Jackson—Mr. Jackson is a member of our board and serves on the audit, compensation and finance committees. Mr. Jackson has been the Chief Financial Officer of BreitBurn GP, LLC, the general partner of BreitBurn Energy Partners L.P. ("BreitBurn") since July 2006 and an Executive Vice President since October 2007. BreitBurn is a publicly traded master limited partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States. On May 15, 2016, BreitBurn and its affiliates filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York. Mr. Jackson also currently serves as the Chief Financial Officer of the general partner of Pacific Coast Energy Company L.P. ("PCEC"). PCEC, which is BreitBurn's predecessor, is a privately held limited partnership engaged in the production and development of oil and gas from properties located in California. Before joining BreitBurn, Mr. Jackson served as a Managing Director in Merrill Lynch & Co.'s Global Markets and Investment Banking Group. Mr. Jackson joined Merrill Lynch in 1992 and was elected Managing Director in 2001. Previously, Mr. Jackson was a Financial Analyst with Morgan Stanley & Co. from 1986 to 1989 and was an Associate in the Mergers and Acquisitions Group of the Long-Term Credit Bank of Japan from 1989 to 1990. Mr. Jackson obtained a B.S. in Business Administration from Georgetown University and an M.B.A. from the Stanford Graduate School of Business.

Mr. Jackson's background and experience with BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and PCEC has provided him with valuable experience and familiarity with master limited partnerships and, more specifically, the natural gas business. These skills coupled with his broad investment banking, acquisition and financing experience brings additional depth to our board's collective expertise, and therefore makes Mr. Jackson well suited to serve as a member of our board of directors.

E. Bartow Jones—Mr. Jones is a member of our board, the board of directors of our manager, the board of supervisors of Niska Holdings, which is our parent and also serves on the finance committee. Mr. Jones is currently a Partner of Riverstone Holdings LLC where he served as a Managing director from 2010 to 2014 and as a Principal from 2007 to 2010. Mr. Jones has been with Riverstone since 2001. Mr. Jones currently serves on the boards of directors of Vantage Energy, Inc, or Vantage, Targe Energy, LLC, or Targe and other private companies, and he previously served on the boards of

directors of the general partner of PVR Partners, L.P., Buckeye GP LLC, the general partner of Buckeye Partners, L.P., and MainLine Management LLC, the general partner of Buckeye GP Holdings L.P., and Foresight Reserves L.P.

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

Stephen C. Muther—Mr. Muther is a member of our board and serves on both the audit committee (as Chairman) and the compensation committee. Mr. Muther served as President of the general partner of Buckeye Partners, L.P. ("BPL") and the general partner of Buckeye GP Holdings L.P. ("BGH") from October 25, 2007 until his retirement in February 2009. BPL is a publicly-traded master limited partnership that is principally engaged in the transportation, terminalling, marketing and storage of refined petroleum products for major integrated oil companies, large refined products marketing companies and major end users of petroleum products. BGH is a publicly-traded master limited partnership that owns 100% of the general partner of BPL. From February 2007 to November 2007, Mr. Muther served as Executive Vice President, Administration and Legal Affairs of the general partners of BPL and BGH, and from May 1990 to February 2007, Mr. Muther held the position of Senior Vice President, Administration, General Counsel and Secretary of the general partner of BPL. Prior to joining Buckeye, Mr. Muther was Associate Litigation and Antitrust Counsel for General Electric Company from July 1984 to May 1990. Mr. Muther was an associate attorney with Debevoise & Plimpton in New York City from February 1975 to June 1984. Mr. Muther graduated from Princeton University in 1971 and from the University of Virginia School of Law in 1974.

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

Andrew W. Ward—Mr. Ward is a member of our board, the board of directors of our manager, the board of supervisors of Niska Holdings, which is our parent and also serves on the finance committee. Mr. Ward has served as a member of the board of supervisors of Niska Holdings since May 2006. He is currently a Partner of Riverstone Holdings LLC where he served as a Principal from March 2002 to December 2004. Mr. Ward currently serves on the board of directors of the general partner of USA Compression Partners, LP (NYSE:USAC) and various private companies and has previously served on the boards of directors of the general partner of PVR Partners, L.P., Buckeye GP LLC, the general partner of Buckeye Partners, L.P., and MainLine Management LLC, the general partner of Buckeye GP Holdings L.P., and Gibson Energy.

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

Olivia C. Wassenaar—Ms. Wassenaar is a member of our board, the board of directors of our manager and the board of supervisors of Niska Holdings, which is our parent. Ms. Wassenaar also serves on the finance committee. She is currently a Managing Director of Riverstone Holdings LLC where she served as a Vice President from 2008 to 2010, was promoted to a Principal in 2010, and has served as a Managing Director since 2014. In this capacity, she invests in and monitors investments in the midstream and exploration and production sectors of the energy industry. In addition to serving on the boards of a number of private Riverstone portfolio companies and their affiliates, Ms. Wassenaar also serves on the boards of directors of USA Compression Partners, LP (NYSE: USAC) and Northern Blizzard Resources Inc. (TSX: NBZ) Prior to joining Riverstone, Ms. Wassenaar was an Associate with Goldman, Sachs & Co. in the Global Natural Resources investment banking group. Ms. Wassenaar received her A.B., magna cum laude, from Harvard College and earned an M.B.A. from the Wharton School of the University of Pennsylvania.

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

We hold regularly scheduled meetings of our independent directors. In accordance with our Corporate Governance Guidelines, Mr. James Jackson presides as lead director over meetings of our independent directors.

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

Our board has established an audit committee to assist it in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee is comprised of Mr. Muther, Mr. Jackson and Mr. Hennigan.

The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee discussed with our independent registered accounting firm the matters required to be discussed by Auditing Standards No. 16. Our audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the audit committee. In addition, the audit committee has the authority to review our procedures for internal auditing, review the adequacy of internal controls and engage the services of any other advisors and accountants as the committee deems advisable. Based on the reviews and discussions referred to above, the Audit Committee recommended to the board of directors that the audited financial statements be included in the Annual Report on Form 10-K for the year ended March 31, 2016 for filing with the SEC.

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

As a controlled company that is listed on the NYSE, we are not required to have a compensation committee. See "—Significant Differences in Corporate Governance Standards" for a further explanation. In order to conform to best governance practices, however, our board has established a compensation committee to, among other things, oversee the compensation plans described below. The compensation committee establishes and reviews general policies related to our compensation and benefits. The compensation committee has the responsibility to determine and approve, or make recommendations to the board with respect to, the compensation and benefits of our board and executive officers.

The compensation committee is composed of Mr. Shea, Mr. Muther, Mr. Jackson, Mr. Hennigan and Mr. Alexander. Mr. Hennigan has been appointed the Chairman of the compensation committee. Mr. Muther, Mr. Jackson and Mr. Hennigan are independent directors (as that term is defined in the applicable NYSE rules and Rule 10A-3 of the Exchange Act). All members of the compensation committee are non-employee directors (as that term is defined in Rule 16b-3 of the Exchange Act) except Mr. Shea, the Chairman, President and Chief Executive Officer. None of our executive officers has served as a director or member of a compensation committee of another entity that has or has had an executive officer who served as a member of our board during 2016, 2015 or 2014.

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

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

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

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

Available on our website at www.niskapartners.com are copies of our Audit Committee Charter, our Compensation Committee Charter, our Code of Business Conduct and Ethics and our Corporate Governance Guidelines, all of which also will be provided to unitholders without charge upon their written request to Niska Gas Storage Partners LLC, 170 Radnor Chester Road, Suite 150 Radnor, PA 19087, Attention: General Counsel.

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

Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to us during fiscal 2014 and upon a review of Forms 5 and amendments thereto furnished to us with respect to fiscal 2016, or upon written representations received by us from certain reporting persons that no Forms 5 were required for those persons, we believe that no director, executive officer or greater-than-ten-percent shareholder failed to file on a timely basis the reports required by Section 16(a) of the Exchange Act during, or with respect to, fiscal 2016.

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

This section describes the objectives and elements of our compensation program for the fiscal year ended March 31, 2016 (referred to as the "2016 fiscal year") for our named executive officers. This section should be read together with the compensation tables that follow, which disclose the compensation awarded to, earned by or paid to the named executive officers with respect to the 2016 fiscal year, as well as for certain elements of compensation paid to the named executive officers for the fiscal years ending on March 31, 2014 and March 31, 2015. See the section entitled "Executive Compensation" below. The "named executive officers" for the 2016 fiscal year, along with the title that each officer held during the 2016 fiscal year, were as follows:

We believe that these objectives are best met by providing a mix of cash and equity-based compensation to our executives. We believe that this mix of compensation elements provides us with a successful compensation program because it allows us to attract and retain a quality team of executives while motivating them to provide a high level of performance to us.

While these objectives remained important to us during the 2016 fiscal year, our ability to provide certain elements of compensation to our named executive officers was impacted by the impending Transaction. The Merger Agreement generally states that following the execution of that agreement on June 14, 2015, we were restricted from granting equity-based compensation awards or other incentive compensation awards that were not already outstanding as of that date. Due to the terms of the Merger Agreement, we did not grant equity-based compensation awards to any of the named executive officers during the 2016 fiscal year. The Merger Agreement also stated that our employees, including the named executive officers, generally could not receive an increase in compensation or employee benefits following the signing date of the Merger Agreement. As we had already put our annual cash bonus program in place prior to signing the Merger Agreement, the named executive officers remained eligible to receive potential bonuses under the STIP described below. The compensation restrictions set forth in the Merger Agreement will remain in place until the Transaction is completed (or the termination of the Transaction), therefore our ability to implement our historical compensation program objectives were somewhat limited by the terms of the Merger Agreement during the 2016

fiscal year, and could continue to be limited following the 2016 fiscal year depending upon the closing date or the termination date of the Transaction, as applicable.

Our manager and our board, as its delegate, historically have managed our operations and activities and made decisions on our behalf. While our board has been delegated the authority to oversee our operations from our manager, our board has established a compensation committee to determine and set compensation practices or to make recommendations to the full board regarding compensation matters that the board has reserved final authority over, as applicable. Our Chairman, President and Chief Executive Officer is also consulted by the compensation committee and the full board regarding the compensation of the named executive officers other than himself. The compensation of each of our named executive officers for the 2016 fiscal year was originally determined and implemented solely by our compensation committee. As noted above, following our entry into the Merger Agreement, compensation decisions for the named executive officers were dictated by the terms of the Merger Agreement.

Effective July 1, 2015, certain of our named executive officers spend a portion of their professional time providing services to a related entity, Mainline Energy Partners LLC ("Mainline"), under a Management Services Agreement. Pursuant to the Management Services Agreement, Mainline is obligated to provide reimbursement to us or our subsidiaries for a portion of the compensation and benefit expenses incurred by us and our subsidiaries associated with the named executive officers' services, but Mainline does not provide any additional compensation to the applicable named executive officers and the Management Services Agreement has not impacted the compensation levels or compensation decisions that we make regarding the applicable named executive officers. The compensation disclosures contained herein, including the executive compensation tables that follow this Compensation Discussion and Analysis, reflect the full amount of compensation we provide to our named executive officers with no reduction for any amounts reimbursed by Mainline. For more information regarding the Management Services Agreement, please see "Certain Relationships and Related Party Transactions" below.

Our board and the compensation committee each holds the authority to engage an outside compensation consultant if it appears at any time that such assistance would be appropriate. Our compensation committee has formally engaged Frederic W. Cook and Co., Inc. ("FW Cook"), an outside compensation consultancy, to provide advice regarding our overall compensation structure, including short term and long term compensation. Although we did not seek any advice from FW Cook with respect to the 2016 fiscal year, the compensation of our named executive officers for fiscal 2016 remained substantially the same as the compensation provided to them for fiscal 2015, as a result of and subject to the compensation restrictions set forth in the Merger Agreement, and FW Cook did provide executive compensation advice to our compensation committee for the 2015 fiscal year. The compensation committee determined that the services provided by FW Cook to the compensation committee during the 2015 fiscal year did not give rise to any potential conflicts of interest. The compensation committee made this determination by assessing the independence of FW Cook under the six independence factors adopted by the SEC and incorporated into the New York Stock Exchange Corporate Governance Listing Standards.

Our board and compensation committee, with input from management employees, has historically compared certain aspects of our compensation program to the compensation programs in place at companies that we consider to be our peers. For 2015, FW Cook reviewed the most recent list of peer companies that we were using to determine if FW Cook agreed that the group continued to be appropriate for our use in evaluating compensation. The peer group that we and FW Cook determined to be appropriate for us with respect to compensation for the 2015 fiscal year includes companies in the United States market for which we believe we compete for executive talent in the energy sector. At

the beginning of the 2015 fiscal year, the compensation committee approved certain changes to the 2014 compensation peer group in establishing the peer group for 2015 fiscal year compensation purposes. Specifically, the compensation committee approved the addition of Crestwood Equity Partners LP and Summit Midstream Partners LP to the compensation peer group and removed Eagle Rock Energy Partners and El Paso Pipeline Partners from the compensation peer group for the 2015 fiscal year. Upon approval of these changes, the 2015 compensation peer group (the "Peer Group") included the following companies:

We have also in prior fiscal years utilized a separate peer group of companies for purposes of certain performance-based PUPP awards, which are measured based on our relative total unitholder return ("TUR") over a designated performance period. For purposes of performance-based Phantom Unit Performance Plan ("PUPP") awards granted prior to the 2015 fiscal year, the compensation committee moved from measuring TUR verses this designated performance peer group of companies to measuring TUR against the companies in the Alerian Natural Gas MLP Index for the duration of the applicable performance period.

The compensation program established by the compensation committee, in conjunction with FW Cook, for the 2016 fiscal year was implemented effective April 1, 2015. For the 2016 fiscal year, the compensation program for our named executive officers was comprised of the following key elements:

Although we did not grant equity-based incentive awards to the named executive officers during the 2016 fiscal year due to the restrictions set forth in the Merger Agreement, the named executive officers continue to hold outstanding equity-based awards that were granted in previous years under the

PUPP and the Niska Gas Storage Partners LLC 2010 Long Term Incentive Plan (the "LTIP") and pursuant to arrangements with Niska Holdings, all of which are described in greater detail below.

The compensation committee establishes base salaries for the named executive officers based on various factors, including the amounts it considers necessary to attract and retain high quality executives in our industry along with the responsibilities of the named executive officers. The compensation committee is also responsible for approving any significant changes to executive salaries. Salaries for the named executive officers are generally adjusted on an annual basis to remain competitive as compared to the market, or in connection with significant changes in duties or authorities.

For the 2016 fiscal year, the compensation committee determined that in light of the prior year's financial results and the challenging economics of the market over the past year, the annual base salaries for the named executive officers would remain at the rates that were approved for the 2015 fiscal year. The 2015 and 2016 fiscal year salaries were as follows:

The base salary amounts paid to our named executive officers for the 2016 fiscal year are set forth in the "Salary" column of the Summary Compensation Table for 2016. As the compensation restrictions set forth in the Merger Agreement have not yet lapsed, we have not made any base salary increases for any of the named executive officers following the end of the 2016 fiscal year.

A significant portion of the potential compensation our named executive officers may earn for a fiscal year is determined pursuant to our discretionary annual cash bonus program. While base salaries offer an important retention element by providing a guaranteed income stream to our employees, we hope to motivate our employees to strive for both individual and overall company success by providing a substantial portion of compensation only when performance for the year calls for an additional compensatory award. Our industry has historically relied heavily on cash bonuses to compensate executive officers for performance, and we intend to compensate our executives in line with our industry trends and practices.

The annual cash bonus award targets for the 2016 fiscal year were communicated to our named executive officers pursuant to our Short Term Incentive Plan ("STIP"). While the ultimate amount of any cash bonus paid to our named executive officers under the STIP is determined at the discretion of

our compensation committee, the STIP awards are tied to the achievement of company financial and non-financial performance targets and a target bonus amount for each officer. The company performance targets and each officer's target bonus amount are established by the compensation committee each year and act as guidelines for determining the amount of the bonus that may be paid to the named executive officer for that year.

We communicate the target bonus amount to our named executive officers as a certain percentage of their base salary, clearly noting that company performance on certain financial and non-financial performance targets may significantly impact what percentage of the target bonus amount is actually paid. For the 2016 fiscal year, the target bonus amounts for the named executive officers were set as follows:

The company performance metrics for the 2016 fiscal year STIP were a combination of financial (weighted at ninety percent (90%)) and non-financial measures (weighted at ten percent (10%)). The target goals for each company performance metric are based on internal company target goals and may be adjusted throughout the year by the compensation committee as determined appropriate upon the advice of the management team. The compensation committee has broad discretion to vary or modify any particular performance goals, which may vary between performance goals and participants.

Financial Measure. For the 2016 fiscal year, the company financial performance metric was net earnings before interest, income taxes, depreciation and amortization, unrealized risk management gains and losses, foreign exchange gains and losses, unrealized inventory impairment write downs, gains and losses on asset disposition, asset impairments and other income, or "Adjusted EBITDA." We believe that paying a bonus tied to our Adjusted EBITDA aligns the interests of our executives with those of our unitholders and motivates them to provide a high level of performance for us. Generally, in order for there to be any payout under the STIP for the 2016 fiscal year (including any payout with respect to the non-financial measures component of the STIP described below), we must first meet a minimum performance threshold of eighty-seven percent (87%) of the Adjusted EBITDA target set for the year (the "Threshold"). If we achieve the Adjusted EBITDA Threshold for the year, the payout for this component of the STIP is expected to equal fifty percent (50%) of the officer's target bonus amount attributable to the company financial measure component; if we achieve one hundred percent (100%) of the Adjusted EBITDA target set for the year, the payout for this component of the STIP is expected to equal one hundred percent (100%) of the officer's target bonus amount attributable to the company financial measure component; and if we achieve one hundred thirteen percent (113%) of the Adjusted EBITDA target set for the year, the payout for this component of the STIP is expected to equal two hundred percent (200%) of the officer's target bonus amount attributable to the company financial measure component. The achievement of the company financial performance goal between these levels will be determined using straight line interpolation.

Non-Financial Measures. For the 2016 fiscal year, the company non-financial performance metrics were:

Metric	Description

Total Recordable Incident Rate ("TRIR")	Work related injuries or illnesses that must be recorded as per OSHA definition	2.5	%
Environmental Incidents	Reportable incidents that include spills, non-operational gas releases, public environmental complaints, and public odor complaints	2.5	%
Operational Availability	Measurement of the number of days our facilities are available for service, calculated as 365 days less the sum of planned or unplanned outages, divided by 365 days	2.5	%
Risk Violations	Violations assessed on "impact value," with any violation whose impact is greater than $50,000 (in U.S. dollars) included. The categories to which violations are assigned are credits, procedural, product, term, volume and open position	2.5	%

Like the financial measure component described above, the compensation committee establishes threshold, target and maximum achievement levels for each non-financial performance measure for the fiscal year. If we achieve the threshold target for the year, the payout for each non-financial metric component of the STIP is expected to equal fifty percent (50%) of the officer's target bonus amount attributable to that non-financial metric; if we achieve one hundred percent (100%) of the target for the year, the payout for each non-financial metric component of the STIP is expected to equal one hundred percent (100%) of the officer's target bonus amount attributable to that non-financial metric; and if we achieve the maximum target for the year, the payout for each non-financial metric component of the STIP is expected to equal two hundred percent (200%) of the officer's target bonus amount attributable to that non-financial metric. The achievement of the company non-financial performance goals between these levels will be determined using straight line interpolation.

Based on our actual results for the fiscal year, the compensation committee then determines the amounts to be paid to each of the named executive officers. In doing so, it reviews each officer's individual performance and also takes into account advice from FW Cook as well as from the Chairman, President and Chief Executive Officer (with respect to the other named executive officers). While the achievement of the company financial and non-financial performance targets as described above serves as a guideline for determining the annual bonus amounts for the named executive officers, the ultimate amount paid to the named executive officers under the STIP is determined at the discretion of the compensation committee, and the compensation committee may award a greater or lesser amount without regard to the achievement of the company performance targets. In exercising this discretion, the compensation committee takes into account such subjective and qualitative factors that it deems appropriate. Such factors may include, but are not limited to, extenuating market or other circumstances, individual performance, overall business performance, and the equity of STIP awards and other compensation.

Following the end of the 2016 fiscal year, the compensation committee determined that we had not achieved the Adjusted EBITDA Threshold for the 2016 fiscal year. As a result, even though we met the target level of achievement for each of the four non-financial measures, no payout under the STIP was earned with respect to the company performance metrics for the 2016 fiscal year. The compensation committee then considered the totality of the circumstances and determined that there were no compelling reasons to exercise its discretion to adjust the percentage of the respective target bonus amounts that each named executive officer would receive based on our company's performance on the financial and non-financial measures for the 2016 fiscal year. Therefore, the total payout to each named executive officer under the STIP for the 2016 fiscal year was 0% of the officer's respective target bonus amount, and no payments were made to the named executive officers with respect to annual cash bonus awards under the STIP for the 2016 fiscal year.

Pursuant to the restrictions set forth in the Merger Agreement, we did not grant equity-based incentive awards to the named executive officers during the 2016 fiscal year. However, the named executive officers currently hold outstanding equity-based awards that were granted in previous years under the PUPP and the Niska Gas Storage Partners LLC 2010 Long Term Incentive Plan (the "LTIP") and pursuant to arrangements with Niska Holdings. The description provided below is intended to provide background information solely for awards granted prior to the 2016 fiscal year.

Phantom Unit Performance Plan ("PUPP"). We adopted the PUPP on March 24, 2011, and the PUPP plan document is filed as Exhibit 10.1 to our Form 8-K filed with the SEC on March 30, 2011. The PUPP is a long-term phantom unit plan for our employees and certain directors. A principal purpose of the PUPP is to further align the interests of participants, including our named executive officers, with the interests of our unitholders by providing for the grant of phantom unit awards. A phantom unit is a notional unit granted under the PUPP that represents the right to receive an amount equal to the value of a common unit of the Company (a "Unit"), following the satisfaction of certain time- and/or performance-based criteria. On June 7, 2012, the board approved an amendment to the PUPP to waive the minimum quarterly distribution requirement for PUPP awards.

The PUPP is primarily administered by our compensation committee under the overall direction of our board. The compensation committee determines all of the terms and conditions of each award pursuant to the PUPP, subject to the terms and conditions required by the PUPP, and grants phantom units to eligible participants at such times as the compensation committee determines to be appropriate. Such terms and conditions are set forth in an individual phantom unit award agreement at the time of each grant of phantom units.

In previous years we have typically granted PUPP awards to the named executive officers and certain other key employees each fiscal year. For the 2015 fiscal year, the compensation committee determined that one hundred percent (100%) of a named executive officer's total target annual PUPP award would be based solely on time-based vesting conditions (a "time-based PUPP award"). Although in past fiscal years a portion of the total target annual PUPP awards to the named executive officers was also based upon performance-based vesting conditions (a "performance-based PUPP award"), the compensation committee determined that time-based PUPP awards were appropriate for the 2015 fiscal year in order to retain executive talent under challenging industry conditions and to align executives' interests with those of our unitholders. In addition, while PUPP awards granted in prior years provide for settlement in the form of a cash payment, the PUPP awards for the 2015 fiscal year will be settled upon vesting in our Units (granted pursuant to the LTIP) in order to create further alignment with our unitholders and to preserve available cash. Please see "—Unit Ownership Requirements" below for a discussion of certain Unit ownership guidelines adopted during the 2015 fiscal year and applicable to our named executive officers.

Time- and performance-based PUPP awards that have been granted in previous years are typically measured over a full three-year time period, except for awards granted during the three-year ramp-in period following the adoption of the PUPP (the 2014 fiscal year being the last year of this period). With respect to the time-based PUPP awards made during the 2015 fiscal year, the awards will cliff vest in three years from the date of grant and will accumulate distribution equivalent rights ("DERs") from the date of grant until payout at vesting, in each case, subject to continued employment by the named executive officer. The compensation committee has broad discretion to vary or modify any particular performance goals applicable to any performance-based PUPP awards, which may vary between performance goals and participants.

The performance-based PUPP awards granted to the named executive officers for the years prior to the 2015 fiscal year vest and are earned based upon our relative TUR measured at the end of each annual performance period in the three-year vesting period. For annual performance periods ending after April 1, 2014, the compensation committee moved from measuring TUR verses the designated performance peer group to measuring TUR against the Alerian Natural Gas MLP Index. If we rank below the thirty-third percentile (33%) at the end of an annual performance period, the applicable portion of the performance-based PUPP awards will not vest. If we rank at the thirty-third percentile (33%) or above, a certain percentage of the applicable portion of the performance-based PUPP awards will vest in accordance with the following chart:

In addition to the satisfaction of the TUR vesting conditions described above with respect to the performance-based PUPP awards, participants must also generally be providing services to us or one of our affiliates at the end of the applicable performance period in order for the applicable portion of the performance-based PUPP award to become vested. For the 2015 time-based PUPP awards, participants must generally be providing services to us or one of our affiliates continuously through the applicable vesting date, which, as discussed above, is the third anniversary of the date of grant of the award. The compensation committee has authority to provide for accelerated vesting provisions in the event of a termination of employment or a change in control. Generally, in the event of a participant's death, disability, retirement, or termination of employment without cause, unvested PUPP awards will vest on a pro rata basis by taking into account the number of days of actual service provided to us or one of our affiliates on and after the date of grant versus the number of days in the entire vesting period for the award. With respect to performance-based PUPP awards, a "target" level of performance will be applied upon any acceleration of vesting, such that a maximum of 100% of the target performance-based PUPP award will become vested. Unless otherwise provided in an individual award agreement, if we undergo a change in control and the participant's employment is terminated for certain reasons, the PUPP awards will also receive accelerated vesting and, with respect to performance-based PUPP awards, a "target" level of performance will be applied to any acceleration of vesting.

The previously granted PUPP awards include distribution equivalent rights or DERs. During the period the PUPP award is outstanding, any distribution that we pay to unitholders generally will also be credited to the participant in the form of additional PUPP awards. The number of additional phantom units to be credited to a participant's PUPP account will be determined by dividing the full amount of the distribution we would have made to the participant if the phantom units were non-restricted Units, by the fair market value of a Unit on the payment date of any distribution.

Portions of the performance-based PUPP awards granted in the 2013 and 2014 fiscal years during the ramp-in period described above may become eligible to vest at the end of certain annual

performance periods, including at the end of the 2016 fiscal year. Upon reviewing the relative TUR performance of our company for the 2016 fiscal year, the compensation committee determined that, with respect to the applicable portion of the performance-based PUPP awards granted in the 2013 and 2014 fiscal years, we did not achieve the threshold performance level and therefore these portions of the performance-based PUPP awards have been forfeited.

2010 Long Term Incentive Plan. We adopted the LTIP in connection with our initial public offering. This plan provides for the grant of unit options, unit appreciation rights, restricted units, phantom units, unit awards, performance or incentive awards and other unit-based awards. Due to certain adverse tax consequences that may accompany the grant of an award that is settled in actual Units to Canadian citizens, this plan is largely reserved for grants of awards to our employees, consultants and directors who are United States citizens, but the LTIP may also be used to settle PUPP awards in the form of our Units rather than cash.

Niska Predecessor Class B Units. In 2006, Niska Predecessor issued Class B Units to some of our employees, including the named executive officers then employed by us. The Class B Units represented profits interests in Niska Holdings, and entitle the holders to share in distributions by Niska Holdings once the Class A Units in Niska Predecessor have received distributions equal to their contributed capital plus an 8% rate of return. As of March 31, 2010, the risk of forfeiture had lapsed on all of the Class B Units upon the completion of the time limitations or the achievement of the performance conditions associated with the units, as applicable, and certain of our named executive officers continue to hold these vested units and may receive certain distributions with respect to these awards. No grants of Class B Units occurred during the 2016 fiscal year. The Class B Units are equity interests in Niska Holdings and do not relate directly to our Units, and our company is not responsible for making any payments, distributions or settlements to any holder relating to the Class B Units.

Class D Units in Niska Holdings. In connection with their respective appointments to serve as executive officers of the company, Niska Holdings issued Class D Units to Messrs. Shea, Casaday, Davis and Wallace. The Class D Units are profits interests and represent actual (non-voting) equity interests in Niska Holdings that have no value for tax purposes on the date of grant but entitle the holders to share in distributions by Niska Holdings once a specified rate of return has been received by Class A holders of Niska Holdings. The Class D Units vest over a five-year period, generally subject to the holder's continued employment with the company, Niska Holdings or one of their respective subsidiaries. Certain additional information regarding the Class D Units awarded to Messrs. Shea, Casaday, Davis and Wallace during the 2015 fiscal year, which we have classified as "Option Awards" for purposes of these disclosures, is provided in the section entitled "Executive Compensation" below. However, as the Class D Units are equity interests in Niska Holdings, the Class D Units do not relate directly to our Units and our company is not responsible for making any payments, distributions or settlements to any holder relating to the Class D Units. Niska Holdings is solely responsible for making all payments, distributions and settlements to all holders relating to the Class D Units.

Health and Welfare Benefits. All of our regular full-time employees, including our named executive officers, receive certain health and welfare benefits. The benefits include a health and dental plan, a short- and long-term disability plan, basic and optional life insurance, and basic and optional accidental death and dismemberment insurance coverage.

Retirement and Pension Benefits. Our registered retirement savings plan, or RRSP Plan/Non-Registered Employee Savings Plan, provides Canadian resident employees, including certain of our named executive officers, with an opportunity to participate in a retirement savings plan. This plan is a Canadian retirement plan with features similar to a 401(k) plan or an individual retirement account administered in the United States. Our employees, including our named executive officers who are

Canadian citizens, are allowed to contribute their own funds, and we will, regardless of an employee's own contribution level, contribute 8% of an employee's base salary into the employee's RRSP Plan account, as well as make discretionary employer contributions on their behalf from time to time. Our named executive officers who are United States citizens are eligible to participate in a U.S. 401(k) plan, which allows each participant to contribute his own funds to his plan account, and the company provides up to a 5% match to the plan on his behalf. Further, in addition to this matching contribution, the company also provides a 6% contribution regardless of any employee contribution.

Perquisites. We provide our named executive officers with certain perquisites that we believe are in line with industry standards, as well as with benefits and perquisites similar to those provided by members of the Peer Group within our geographic region, and which we believe are necessary to remain competitive with regard to overall executive compensation. During the 2016 fiscal year, certain of our named executive officers received additional payments to be applied to expenses for home computers, club memberships (including memberships to industry organizations) and other personal expenses, as well as a monthly automobile allowance and paid parking at our office facilities.

On May 7, 2014, our company entered into an employment agreement with each of Messrs. Shea, Casaday, Davis and Wallace. In addition, on June 5, 2015, our company entered into a similar employment agreement with Mr. Powers, our other U.S.-based executive officer. Each employment agreement has a three-year initial term and will automatically renew for successive one-year renewal terms unless either party provides written notice of non-renewal at least 30 days prior to the end of the initial term or any renewal term. Each employment agreement also sets forth the officer's annualized base salary and his eligibility for discretionary bonus compensation and equity awards and provides for certain separation payments and benefits in the event the officer's employment is terminated under certain specified circumstances. The employment agreements with Messrs. Shea, Casaday, Davis and Wallace are filed as exhibits to our Form 8-K filed with the SEC on May 13, 2014, and the employment agreement with Mr. Powers is filed as an exhibit to our Form 8-K filed with the SEC on June 5, 2015.

We did not have employment agreements with any of our other named executive officers during the 2016 fiscal year. However, the PUPP awards granted to each named executive officer during the 2015 fiscal year and prior fiscal years contain termination and change of control provisions. With respect to the outstanding PUPP awards, we have provided severance and change in control protections to serve as a retention tool. In connection with the Transaction, we have also entered into a retention plan that could impact the vesting and settlement provisions of the PUPP awards for certain Canadian-based named executive officers, described in greater detail below.

We believe that the post-termination payments in the employment agreements and the PUPP agreements, as applicable, allow our officers to focus their attention and energy on making the best objective business decisions that are in our interest, and in the interest of our unitholders, without allowing personal considerations to influence the decision-making process. Executive officers at other companies in our industry and the general market against which we compete for executive talent commonly have post-termination and/or change in control provisions, and we have consistently provided these benefits to our executive officers in order to remain competitive in attracting and retaining skilled professionals in our industry. Please see "Executive Compensation—Potential Payments Upon Termination and Change in Control" for additional information.

In connection with his termination of employment on July 31, 2015, Mr. Davis entered into a Separation Agreement and General Release of Claims (the "Separation Agreement") with us, pursuant to which he received the same payments to which he would be entitled upon an involuntary termination of his employment without cause under his employment agreement, in exchange for a release of all claims against us and our affiliates. Mr. Davis also entered into an Agreement Regarding Niska Gas

Storage Partners LLC Phantom Unit Performance Plan Awards (the "PUPP Award Payment Agreement") that addresses the outstanding PUPP awards that Mr. Davis held at the time of his termination of employment. Additional information regarding the Separation Agreement and the PUPP Award Payment Agreement with Mr. Davis is also provided below under "Executive Compensation—Potential Payments Upon Termination and Change in Control."

We adopted the Niska Gas Storage Partners LLC Transaction Incentive and Retention Bonus Plan (the "Retention Plan") on June 14, 2015 in connection with the signing of the Merger Agreement. The Retention Plan may impact outstanding PUPP awards granted to certain employees, including Canadian-based executive officers such as Mr. Staples. The named executive officers other than Mr. Staples were specifically excluded from participating in the Retention Plan.

The Retention Plan will provide each participant with the opportunity to receive two retention awards: a cash retention payment (described further below) and a PUPP award carryover amount. The PUPP award carryover amount is a cash award that will be based upon the number of time-based phantom units that a participant holds at the time of the closing of the Transaction. The number of PUPP awards held by Mr. Staples that may be impacted by the Retention Plan will be determined at the time of the closing of the Transaction. If a phantom unit held by a Retention Plan participant is subject to performance-based vesting criteria, the phantom unit will be forfeited without consideration at the closing of the Transaction. In other words, if a participant does not hold any time-based phantom units at the time that the Transaction closes, they will not receive a PUPP award carryover amount in the Retention Plan. However, if the participant holds a phantom unit that is subject to time-based vesting criteria at the time of the closing of the Transaction, the phantom unit will be forfeited at the closing, but the participant will receive a cash amount in the Retention Plan that will be equal to the number of time-based vesting phantom units the participant holds immediately prior to the closing of the Transaction, multiplied by the per unit cash value of the consideration that regular Unit holders will receive in connection with the closing of the Transaction ($4.225). The PUPP award carryover account, if any, will be governed by the terms of the Retention Plan rather than the PUPP or the LTIP, but it will be subject to the same terms and conditions as those imposed upon the outstanding time-based PUPP awards that were forfeited at the closing, including vesting and payment schedules.

For additional details regarding the potential payments that Mr. Staples may receive pursuant to the Retention Plan, please see the section below titled "Executive Compensation—Potential Payments Upon Termination and Change in Control."

During the 2015 fiscal year, the compensation committee approved unit ownership requirements for our executive officers. The purpose of these Executive Unit Ownership Guidelines ("Ownership

Guidelines"), adopted effective May 7, 2014 ("Effective Date"), is to (i) require executive officers to own our Units and thereby (ii) further align the interests of our executive officers with those of our unitholders and (iii) further promote superior management and growth of our company's business.

Under the Ownership Guidelines, each executive officer is required to own Units having a value equal to the dollar amount of the applicable multiple of such executive's base salary as set forth in the table below.

Compliance with the Ownership Guidelines was initially determined based upon each executive officer's base salary in effect on the Effective Date and the closing price of the Units on the New York Stock Exchange on March 31, 2015. Thereafter, a redetermination shall be made every year on March 31, based upon (i) the average of each executive officer's base salary for the determination period and (ii) the average of the high and low closing prices of the Units on the New York Stock Exchange on March 31 of the calendar year in which the redetermination is made.

Executive officers must satisfy the Ownership Guidelines no later than five years following (i) the Effective Date, for those executive officers employed as of the Effective Date; or (ii) for new executive officers, the officer's date of hire or date of promotion into an executive position. If an executive officer does not meet the Ownership Guidelines within the time period set forth above, the executive officer will be promptly notified and will have until the next redetermination period to meet the Ownership Guidelines. If at the time of redetermination the executive officer still does not meet the Ownership Guidelines, then the executive officer will be required to retain all Units owned by the executive officer, including all restricted or phantom units, until the Ownership Guidelines are met.

For purposes of determining compliance with the Ownership Guidelines, each of the following qualifies as ownership of Units:

Unvested restricted units or unvested phantom units, in each case, subject to performance-based vesting conditions, are not considered Units for purposes of meeting the Ownership Guidelines.

The Ownership Guidelines are administered by the compensation committee. The compensation committee may, at any time, amend, modify or terminate the Ownership Guidelines in whole or in part, including, if the Ownership Guidelines would place a severe hardship on an executive officer, by developing alternative Unit ownership guidelines that reflects both the intention of the Ownership Guidelines and the personal circumstances of the executive officer.

We maintain an insider trading policy that is applicable to our directors and employees, including our named executive officers, which, among other things, prohibits such individuals from entering into short sales or from buying or selling puts, calls or other derivative securities in our Units. We also have generally designed our long term incentive program according to the tax effects that certain awards could have upon our employees. For Canadian citizens, grants of certain equity awards could create immediate adverse tax consequences, so we typically provide Canadian citizens with phantom units under the PUPP.

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

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

The year "2014" refers to the fiscal year beginning April 1, 2013 and ending March 31, 2014; the year "2015" refers to the fiscal year beginning April 1, 2014 and ending March 31, 2015; and the year "2016" refers to the fiscal year beginning April 1, 2015 and ending March 31, 2016. With respect to Canadian-based named executive officers, compensation was paid primarily in Canadian dollars but is reported in U.S. dollars in the tables and footnotes that follow. An exchange rate of (i) 0.9497 U.S. dollars for each Canadian dollar was used for 2014 amounts (the average exchange rate for the period as reported by the Bank of Canada), (ii) 0.8805 U.S. dollars for each Canadian dollar was used for 2015 amounts (the average exchange rate for the period as reported by the Bank of Canada), and (iii) 0.7638 U.S. dollars for each Canadian dollar was used for 2016 amounts (the average exchange rate for the period as reported by the Bank of Canada). Amounts reported as "Option Awards" in the tables and footnotes that follow relate to Class D Units in Niska Holdings that do not relate directly to

our Units and for which our company is not responsible for making any payments, distributions or settlements.

Name and Principal Position

William H. Shea, Jr.	2016	400,000	0	—	—	57,153	457,153
Chairman, President and Chief	2015	360,769	0	1,901,854	344,904	43,079	2,650,606
Executive Officer
Vance E. Powers	2016	298,700	0	—	—	55,982	354,682
Chief Financial Officer	2015	298,700	0	624,003	—	100,698	1,023,401
	2014	290,000	282,750	435,000	—	90,447	1,098,197
Mark D. Casaday	2016	320,000	0	—	—	43,194	363,194
Chief Operating Officer	2015	288,615	0	755,385	344,904	25,290	1,414,194
Rick J. Staples(5)	2016	247,815	0	—	—	46,803	294,618
Executive Vice President and	2015	285,678	0	665,265	—	53,685	1,004,628
Chief Commercial Officer	2014	299,156	364,596	747,889		57,117	1,468,758
Robert B. Wallace	2016	257,680	0	—	—	35,677	293,357
Vice President, Finance and	2015	232,407	0	665,260	197,088	21,716	1,116,471
Corporate Development
Bruce D. Davis, Jr.(6)	2016	85,893	0	164,570	—	567,948	818,411
Former Vice President, Chief	2015	232,407	0	665,260	98,544	21,690	1,017,901
Administrative Officer

(1): As described above under "Compensation Discussion and Analysis—Elements of Compensation—Discretionary Bonus Awards," we did not attain the Adjusted EBITDA Threshold for the 2016 fiscal year and the compensation committee, after considering the totality of the circumstances, determined not to make any payments to our named executive officers with respect to the discretionary annual cash bonus awards under the STIP for the 2016 fiscal year.
(2): Amounts reported as "Unit Awards" for 2015 and 2014 represent the grant date fair value of phantom unit awards under the PUPP determined in accordance with FASB ASC Topic 718, rather than the amounts that may actually be paid to each named executive officer upon vesting and settlement of an award. Pursuant to SEC rules, the amounts shown exclude the effect of estimated forfeitures and, with respect to the performance-based PUPP awards, are based upon the probable outcome of the associated performance conditions at the grant date. Additional details regarding the calculation of the value reported for phantom unit awards under the PUPP are included in Note 15 of the Notes to our Consolidated Financial Statements. Although PUPP awards are reported as "Unit Awards" above when granted, any PUPP awards granted prior to the 2015 fiscal year are settled, if at all, in cash payments rather than actual Units.

The treatment of the phantom unit awards previously granted to Mr. Davis in fiscal 2015 (the full FASB ASC Topic 718 grant date fair value of which was reported in the "Unit Awards" column for 2015) in connection with his termination of employment on July 31, 2015 resulted in a modification charge with respect to those awards under FASB ASC Topic 718. As a result, in accordance with SEC rules, amounts reported in the "Unit Awards" column for Mr. Davis for 2016 reflect the associated incremental fair value of the awards, computed as of the modification date in accordance with FASB ASC Topic 718. This same amount is also discussed below under "Grants of Plan Based Awards" and the value realized with respect to the portion of such awards that was settled in connection with his termination of employment is reflected in the "Options Exercised and Units Vested" table. However, none of our named executive officers, including Mr. Davis, received a grant of any equity-based incentive awards during the 2016 fiscal year due to the restrictions set forth in the Merger Agreement.
(3): In connection with their respective appointments to serve as executive officers of our company, Messrs. Shea, Casaday, Davis and Wallace each received an award of Class D Units in Niska Holdings on May 7, 2014. The Class D Units are profits interests and represent actual (non-voting) equity interests in Niska Holdings that have no value for tax purposes on the date of grant but entitle the holders to share in distributions by Niska Holdings once a specified rate of return has been received by Class A holders of Niska Holdings. The Class D Units vest over a five-year period, generally subject to the holder's continued employment with the company, Niska Holdings or one of their respective subsidiaries. We believe that, despite the fact that the Class D Units do not require the payment of an exercise price, these awards are most similar economically to stock options and, as such, they are properly classified as "options" for purposes of the SEC's executive compensation disclosure rules under the definition provided in Item 402(a)(6)(i) of Regulation S-K since these awards have "option-like features." The amounts reflected in the "Option Awards" column report the value, determined as of the grant date under FASB ASC Topic 718, of the Class D Units, which for accounting purposes are treated as profits interest awards subject to a service condition, and do not reflect the amounts, if any, that may actually be distributed to holders of the Class D Units. Further information regarding the assumptions used in the valuation of these awards is included in Note 15 of the Notes to our Consolidated Financial Statements. However, as equity interests in Niska Holdings, the Class D Units do not relate directly to our Units and our company is not responsible for making any payments, distributions or settlements to any holder relating to the Class D Units. Niska Holdings is solely responsible for making all payments, distributions and settlements to all holders relating to the Class D Units.

Executive Officer

William H. Shea, Jr.	43,999	—	—	—	7,347	5,807	—	—	57,153
Vance E. Powers	31,612	—	12,000	—	6,780	5,590	—	—	55,982
Mark D. Casaday	31,200	—	—	—	7,347	4,647	—	—	43,194
Rick Staples	19,825	14,588	9,324	2,832	—	—	234	—	46,803
Robert B. Wallace	24,587	—	—	—	7,347	3,743	—	—	35,677
Bruce D. Davis, Jr.	9,448	—	—	—	3,364	8,715	—	546,421	567,948

(a): In connection with his termination of employment on July 31, 2015, Mr. Davis received the payments to which he was entitled upon an involuntary termination without cause under his employment agreement dated May 7, 2014. These payments consisted of (i) a severance payment in the aggregate amount of $515,360, less applicable taxes, withholdings and any other legal standard deductions, and (ii) $31,061 in health insurance premium costs for COBRA continuation coverage during fiscal 2016 under our group health care plan for the period August 2015 through March 2016, which were paid by us on Mr. Davis's behalf. In addition, 19,868 PUPP phantom units held by Mr. Davis became vested upon his termination of employment and were settled in the form of common units. Mr. Davis' 28,478 remaining PUPP phantom units will vest upon the closing of the Transaction. The treatment of these phantom unit awards in connection with Mr. Davis's termination of employment resulted in a modification charge with respect to those awards under FASB ASC Topic 718. See note (2) to the "Summary Compensation Table" above for more information. All unvested Class D Units held by Mr. Davis were forfeited upon his termination of employment and his vested Class D Units were repurchased by Niska Holdings for $0.00.

We did not grant any plan-based awards, including any PUPP awards, during the 2016 fiscal year, and none of our named executive officers received any grants of plan-based awards for services provided to us during the 2016 fiscal year from any other entity. Please see "Compensation Discussion and Analysis—Objectives of Our Executive Compensation Program and Impact of the Transaction" for additional information regarding our compensation program for the 2016 fiscal year.

The treatment of the phantom unit awards previously granted to Mr. Davis in fiscal 2015 (the full FASB ASC Topic 718 grant date fair value of which was reported in the "Unit Awards" column of the "Summary Compensation Table" for 2015) in connection with his termination of employment on July 31, 2015 resulted in a modification charge with respect to those awards under FASB ASC Topic 718. As a result, in accordance with SEC rules, amounts reported in the "Unit Awards" column of the "Summary Compensation Table" for Mr. Davis for 2016 reflect the associated incremental fair value of the awards, computed as of the modification date in accordance with FASB ASC Topic 718. The value realized with respect to the portion of such awards that was settled in connection with his termination of employment is reflected in the "Options Exercised and Units Vested" table.

A discussion of material factors necessary to an understanding of the information disclosed in the Summary Compensation Table for the 2016 fiscal year is provided above under "Compensation Discussion and Analysis."

The table below reflects the outstanding phantom unit awards under the PUPP that each of our named executive officers held as of March 31, 2016. In addition, it reflects the number of outstanding Class D Units in Niska Holdings held by certain named executive officer as of March 31, 2016. Class D

Units in Niska Holdings do not relate directly to our Units and our company is not responsible for making any payments, distributions or settlements related to the Class D Units.

	Option Awards(1)

	Number of Securities Underlying Unexercised Options, Exercisable (#)		Number of Securities Underlying Unexercised Options, Unexercisable (#)
							Unit Awards
					Option Exercise Price ($)		Unit Awards
Name					Option Exercise Price ($)	Option Expiration Date	Number of Time-based Units That Have Not Vested (#)(2)		Market Value of Units That Have Not Vested ($)(3)
William H. Shea, Jr.		112,000		168,000	n/a	n/a		138,210	$	496,174
Vance E. Powers		—		—				51,335	$	184,293
Mark D. Casaday		112,000		168,000	n/a	n/a		54,896	$	197,077
Rick J. Staples		—		—				54,730	$	196,481
Robert B. Wallace		64,000		96,000	n/a	n/a		48,346	$	173,662
Bruce D. Davis, Jr.		—		—				28,478	$	102,236

(1)

Reflects Class D Units in Niska Holdings, which became vested as to 20% of the total award on May 6, 2015 and vests as to 5% of the total award on the last day of each June, September, December and March during the period commencing on June 30, 2015 and ending on March 31, 2019, generally subject to the holder's continued employment with the company, Niska Holdings or one of their respective subsidiaries. Awards reflected as "Unexercisable" are Class D Units that have not yet vested. All unvested Class D Units previously held by Mr. Davis were forfeited upon his termination of employment on July 31, 2015 and his vested Class D Units were repurchased by Niska Holdings for $0.00.

(2)

All outstanding time-based PUPP awards will be settled, if at all, in Units. Assuming that all time-based vesting conditions are met for the awards, the time-based PUPP awards granted to the named executive officers during the 2015 fiscal year cliff vest on March 31, 2017. As of March 31, 2016, the named executive officers held the following numbers of these units:

(a): Mr. Shea held 138,210 units, including 13,580 additional phantom units credited following the date of grant pursuant to DERs;
(b): Mr. Powers held 51,335 units, including 5,044 additional phantom units credited following the date of grant pursuant to DERs;
(c): Mr. Casady held 54,896 units, including 5,395 additional phantom units credited following the date of grant pursuant to DERs;
(d): Mr. Staples held 54,730 units, including 5,378 additional phantom units credited following the date of grant pursuant to DERs; and
(e): Mr. Wallace held 48,346 units, including 4,751 additional phantom units credited following the date of grant pursuant to DERs.

As of March 31, 2016, Mr. Davis held 28,478 remaining units that will vest upon the closing of the Transaction.

(3)

In accordance with SEC rules, the values reported in this column are calculated by multiplying the closing price of our Units on March 31, 2016 ($3.59), by the number of outstanding time-based PUPP awards reported in the table above.

The table below reflects the number of time-based PUPP awards that vested during the 2016 fiscal year. The named executive officers did not hold any options to purchase our Units during the 2016 fiscal year, and no performance-based PUPP awards became vested during the 2016 fiscal year because we did not achieve the threshold performance level. Therefore, all remaining outstanding portions of previously awarded performance-based PUPP awards have been forfeited.

While certain named executive officers hold Class D Units, which are profits interests in Niska Holdings, a portion of which vested during the 2016 fiscal year, no payments or distributions were made with respect to any Class D Units during the 2016 fiscal year.

(1): The phantom units held by Mr. Powers and Mr. Staples that vested during the 2016 fiscal year (including 8,595 and 13,632 additional phantom units, respectively, credited following the date of grant pursuant to DERs) were settled in cash payments rather than actual Units. The 19,868 phantom units held by Mr. Davis that became vested upon his termination of employment were settled in the form of Units.
(2): In accordance with SEC rules, the amounts reported in the "Value Realized on Vesting" column above were calculated using the closing price of our Units on the applicable vesting date, which was (a) April 24, 2015 ($2.06), with respect to 22,785 phantom units held by Mr. Powers and 34,177 phantom units held by Mr. Staples; (b) March 31, 2016 ($3.59), with respect to 13,042 phantom units held by Mr. Powers and 23,611 phantom units held by Mr. Staples; and (c) July 31, 2015 ($3.36), with respect to the phantom units held by Mr. Davis. However, the award agreements require that we settle the awards held by Mr. Powers and Mr. Staples in cash using the average closing price of our Units during the 30-day period preceding the applicable settlement date. As result, Messrs. Powers and Staples actually received $89,170 and $147,923, respectively, with respect to the phantom units reported in this table.

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

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

PUPP. The phantom units that we granted to each of our named executive officers under the PUPP during 2015 and prior fiscal years contain certain termination and change in control benefits. The PUPP participants must generally be providing services to us or one of our affiliates on an applicable vesting date in order for their award to vest, but in the event of a PUPP participant's death, "disability," "retirement," or termination of employment without "cause" (each quoted term as defined below), an unvested phantom unit will vest on a pro rata basis by taking into account the number of days of actual service provided to us or one of our affiliates versus the number of days in the entire vesting period for the award.

If we incur a "change in control" and the participant also is terminated by us (or the successor entity) other than for cause or the participant resigns as a result of a "constructive dismissal" (each quoted term as defined below), then all unvested phantom units will vest.

Other than with respect to Mr. Davis (whose employment actually terminated during the 2016 fiscal year and whose actual related payments are discussed below under "—Termination Benefits to Mr. Davis"), the table below shows the estimated value of the acceleration of the phantom units that each officer would have received upon certain terminations of employment. For purposes of the table below we have assumed that the termination of employment occurred on March 31, 2016 and our common units were valued at $3.59 (the closing price of a common unit on March 31, 2016). The actual amount that any named executive officer will receive with respect to his phantom units, however, can only be determined upon an actual termination of employment.

Employment Agreements. On May 7, 2014, we entered into employment agreements with each of Messrs. Shea, Casaday, Davis and Wallace (the "Employment Agreements"). In addition, we entered into a similar Employment Agreement with Mr. Powers on June 5, 2015. Each Employment Agreement contains certain provisions regarding potential severance benefits. The Employment Agreements do not contain provisions regarding change in control benefits. We do not currently maintain any employment or similar agreements with any other named executive officers.

Upon a termination of employment by us without "cause" or by a named executive officer for "good reason," the Employment Agreements provide that the named executive officer shall generally be eligible to receive (i) 24 months of the then-current base salary for such named executive officer, less any statutory withholding, payable over a 24-month period and (ii) up to 18 months of reimbursement, on a monthly basis, of the monthly premium costs paid by the named executive officer for continuation coverage under the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended ("COBRA"), provided that such reimbursement shall terminate at the time the named executive officer becomes eligible to be covered under a group health plan sponsored by another employer. In the event of a named executive officer's termination of employment for any other reason, the Employment Agreements provide that the named executive officer shall receive no further payments or benefits other than any accrued obligations.

Under the Employment Agreements, the following terms have the meanings set forth below:

The Employment Agreements contain standard restrictive covenants. The confidentiality restriction under the Employment Agreements is perpetual. The non-competition and non-solicitation restrictions under the Employment Agreements apply during the employment period and cover the six month period following termination of employment.

In addition to the amounts noted above with respect to the phantom unit awards, if Messrs. Shea, Powers, Casaday, or Wallace terminated employment for good reason or were terminated by us without cause on March 31, 2016, the amounts shown in the table below are the estimated payments that would become due to each of Messrs. Shea, Powers, Casaday, and Wallace. The table below does not include payments or benefits that Messrs. Shea, Powers, Casaday, and Wallace would be entitled to receive regardless of the reason for the termination, including but not limited to: (i) accrued but unpaid base salary, (ii) accrued, but unused, vacation, (iii) accrued benefits under plans, programs and award agreements or (iv) any unreimbursed eligible expenses. Because Mr. Davis actually terminated employment during the 2016 fiscal year, the actual payments related to his termination are discussed below under "—Termination Benefits to Mr. Davis."

Class D Units in Niska Holdings. The Class D Units that were issued to Messrs. Shea, Casaday, and Wallace by Niska Holdings contain certain termination provisions but do not contain any provisions directly related to a change in control of our company. If the employment of one of the Class D Unit recipients is terminated by us without "cause" (including non-renewal of such recipient's employment agreement), by the recipient for "good reason" or due to death or "disability" (each quoted term as defined above under "Potential Payments Upon Termination or Change in Control—Employment Agreements"), then (i) the recipient shall forfeit, without consideration, all Class D Units that have not yet vested as of the date of termination and (ii) for a period of 180 days following termination, Niska

Holdings shall have the right (but not the obligation) to repurchase any or all of the vested Class D Units held by such recipient on the date of such termination at fair market value. As of March 31, 2016, 40% of the Class D Units held by Messrs. Shea, Casaday, and Wallace had vested. Thus, assuming a termination of employment on March 31, 2016 for one of the foregoing reasons, Messrs. Shea, Casaday, and Wallace would forfeit 60% of their Class D Units and Niska Holdings would have the right to repurchase the remaining 40% of the Class D Units that each officer retained at fair market value, which we estimate would be $0.00 as of March 31, 2016. All unvested Class D Units held by Mr. Davis were forfeited upon his termination of employment on July 31, 2015, and his vested Class D Units were repurchased by Niska Holdings for $0.00.

As described above, the Class D Units are equity interests in Niska Holdings, do not relate directly to our Units and our company is not responsible for making any payments, distributions or settlements to any recipient relating to the Class D Units. Niska Holdings is solely responsible for making all payments, distributions and settlements, if any, to all recipients relating to the Class D Units.

Termination Benefits to Mr. Davis. In connection with his termination of employment on July 31, 2015, Mr. Davis entered into a Separation Agreement and General Release of Claims (the "Separation Agreement") with us, pursuant to which he received the same payments to which he would be entitled upon an involuntary termination of his employment without cause under his employment agreement, in exchange for a release of all claims against us and our affiliates. These payments consisted of (i) a severance payment in the aggregate amount of $515,360, less applicable taxes, withholdings and any other legal standard deductions, and (ii) $31,061 in health insurance premium costs for COBRA continuation coverage during fiscal 2016 under our group health care plan for the period August 2015 through March 2016, which were paid by us on Mr. Davis's behalf. These cash payments are also included above in the "All Other Compensation" column of the Summary Compensation Table for 2016.

Mr. Davis also entered into an Agreement Regarding Niska Gas Storage Partners LLC Phantom Unit Performance Plan Awards (the "PUPP Award Payment Agreement") that addresses the outstanding PUPP awards that Mr. Davis held at the time of his termination of employment. As described in the PUPP Award Payment Agreement, 19,868 PUPP phantom units held by Mr. Davis became vested upon his termination of employment and were settled in the form of common units. Mr. Davis' 28,478 remaining PUPP phantom units will vest upon the closing of the Transaction.

Retention Plan. We adopted the Niska Gas Storage Partners LLC Transaction Incentive and Retention Bonus Plan (the "Retention Plan") on June 14, 2015 in connection with the signing of the Merger Agreement. The Retention Plan may impact outstanding PUPP awards granted to certain employees, including Canadian-based executive officers such as Mr. Staples. The named executive officers other than Mr. Staples were specifically excluded from participating in the Retention Plan.

The Retention Plan will provide each participant with the opportunity to receive two retention awards: a cash retention payment (described further below) and a PUPP award carryover amount. The PUPP award carryover amount is a cash award that will be based upon the number of time-based phantom units that a participant holds at the time of the closing of the Transaction. The number of PUPP awards held by Mr. Staples that may be impacted by the Retention Plan will be determined at the time of the closing of the Transaction. If a participant holds a phantom unit that is subject to time-based vesting criteria at the time of the closing of the Transaction, the phantom unit will be forfeited at the closing, but the participant will receive a cash account in the Retention Plan that will be equal to the number of time-based vesting phantom units the participant holds immediately prior to the closing of the Transaction, multiplied by the per unit cash value of the consideration that regular Unit holders will receive in connection with the closing of the Transaction ($4.225). The PUPP award carryover account, if any, will be governed by the terms of the Retention Plan rather than the PUPP or the LTIP, but it will be subject to the same terms and conditions as those imposed upon the

outstanding time-based PUPP awards that were forfeited at the closing, including vesting and payment schedules. If the closing of the Transaction had occurred on March 31, 2016, Mr. Staples would have received a $231,234 cash payment in exchange for the 54,730 time-based phantom units held by him.

The Retention Plan will also provide participants with an opportunity to receive a separate cash-based retention award that is not tied to the PUPP awards. This cash retention amount will vest on the first to occur of the closing of the Transaction or the termination date of the Merger Agreement, subject to the participant remaining continuously employed until the applicable vesting date. However, the cash retention amount would also become vested in the event that the employee is terminated without cause at any time between the date that is sixty days prior to the date of the closing of the Transaction and the actual closing date. The Retention Plan generally defines "cause" to mean (i) the occurrence of any act or omission by the participant that would qualify as an event of "cause" within the meaning of the definition of "cause" contained in any existing or future written employment agreement between the applicable participant and us, any of our subsidiaries, or their successors and assigns, (ii) the willful or negligent failure by the participant to substantially perform the participant's duties (other than any such failure resulting from a disability), (iii) the participant commits, or is convicted of or pleads no contest to, a felony or crime involving moral turpitude, (iv) the participant willfully engages in gross misconduct, (v) the participant violates our code of ethics conduct policy (or that of an affiliate), or (vi) the participant commits one or more significant acts of dishonesty as regards us or any affiliate. The cash retention amount that Mr. Staples will be eligible to earn under the Retention Plan is $195,886.69. All cash payments (including cash payments related to the conversion of PUPP awards) will be converted to Canadian currency for any Canadian residents at the time of payment based on the average exchange rate between the U.S. and Canada for the thirty day period immediately prior to the date of the applicable conversion.

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

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

Officers, employees or paid consultants and advisors of our manager or its affiliates who also serve as our directors do not receive additional compensation for their service as our directors. Directors who are not officers, employees or paid consultants and advisors of our manager or its affiliates ("Eligible

Directors") receive an annual cash retainer of $50,000 and receive an annual award of Units with a market value equal to $50,000, each subject to proration for partial years. In addition, Eligible Directors receive $1,500 for each board and committee meeting that they attend, other than with respect to conflicts committee meeting fees, which for 2016 were $2,500 per meeting. The chairpersons of our audit and compensation committees receive an additional annual fee of $15,000. Directors also receive reimbursement for out-of-pocket expenses associated with attending meetings of the board or committees and director and officer liability insurance coverage. Each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law. The elements and amounts of director compensation will remain the same for the 2017 fiscal year.

As our Chief Executive Officer, Mr. Shea did not receive any compensation for his service on our board during the 2016 fiscal year and all compensation provided to Mr. Shea in connection with services he performs for us in any capacity is included in the Summary Compensation Table above. Other board members that served on our board during the 2016 fiscal year (i.e., Ralph Alexander, E. Bartow Jones, Andrew W. Ward, and Olivia C. Wassenaar) were not paid any compensation by us for their services as board members, as they are appointed and compensated by Riverstone, an affiliate of our manager. The compensation received by the Eligible Directors for their board service during the 2016 fiscal year, in U.S. dollars, is set forth below:

(1): The Eligible Directors had the option of participating in the Deferred Plan (described below) for the 2016 fiscal year, thus certain cash fees reported within this column were not actually received by the Eligible Directors due to the deferral of those amounts into the Deferred Plan. None of the Eligible Directors deferred any cash fees to the Deferred Plan for the 2015 calendar year. Messrs. Hennigan and Jackson also did not elect to defer any cash fees to the Deferred Plan for the 2016 calendar year; however, Mr. Muther deferred all cash fees for the 2016 calendar year. All Eligible Directors maintained an accumulated balance in the Deferred Plan as of the end of the 2016 fiscal year, but none of the Eligible Directors received above market earnings with respect to their respective accounts within the Deferred Plan for fiscal 2016. For these purposes, earnings are considered above market if they exceed 120% of the applicable federal long term rate, with compounding at the time the earnings rate under the plan is set.
(2): Represents the aggregate grant date fair value of the fully vested Units granted to the Eligible Directors during the 2016 fiscal year, determined in accordance with FASB ASC Topic 718. On May 20, 2015, Messrs. Hennigan, Jackson and Muther each received 12,462 common units. On November 19, 2015, Messrs. Hennigan, Jackson and Muther each received 7,884 common units. As of March 31, 2016, none of the directors held any outstanding options or any outstanding, unvested equity awards.

On August 10, 2011, we adopted the Niska Gas Storage Partners LLC Director Deferred Compensation Plan (the "Deferred Plan"). The purpose of the Deferred Plan is to allow us to attract and retain Eligible Directors to serve as our directors. The Deferred Plan is an unfunded arrangement intended to be exempt from the participation, vesting, funding and fiduciary requirements set forth in Title I of the Employee Retirement Income Security Act of 1974, as amended, and to comply with Section 409A of the Internal Revenue Code of 1986, as amended ("Section 409A"). Our obligations under the Deferred Plan are general unsecured obligations to pay deferred compensation in the future to Eligible Director participants in accordance with the terms of the Deferred Plan.

Participation, Deferrals and Contributions. The Deferred Plan is based on a calendar year plan year. Eligible Directors may participate in the Deferred Plan, provided that they are not residents of Canada for purposes of the Income Tax Act (Canada) and not otherwise subject to Canadian taxation under the Income Tax Act (Canada). Any such Eligible Director may become a participant (a "Participant") in the Deferred Plan for an applicable plan year by electing during the open enrollment period to defer a portion of his or her compensation on an election form. A Participant may defer a stated dollar amount, or a designated whole number percentage, up to a maximum percentage of 100% of the Participant's compensation for the applicable plan year. At the time of election, the Participant can choose to defer the compensation until either (i) termination of the Participant's board service or (ii) a future year in which the Participant is still providing services to us and that is at least two calendar years after the year in which the deferred compensation would otherwise have been paid (a "Scheduled In-Service Withdrawal"). We may also elect to make a discretionary contribution to a

Participant's account, which may be subject to a vesting schedule, in an amount and at such time as determined by our board.

Investment Options. At the time of making his or her deferral election, a Participant will also select the investment option with which the Participant would like for us to credit the Participant for basic deferrals. The Participant may select between two cash investment crediting rate options: (i) an annual rate of interest equal to one percent (1%) below the prime rate of interest as quoted by Bloomberg, compounded daily, or (ii) one or more benchmark mutual funds chosen by the plan administrator as an investment option for the Deferred Plan. Notwithstanding the preceding sentence, under the Deferred Plan, we have the discretion to choose an investment crediting rate for a Participant other than the investment crediting rate requested by the Participant; provided that such investment crediting rate cannot be less than (i) in the preceding sentence.

Distributions. A Participant may elect to receive a distribution of his Deferred Plan account upon a termination of service at any of the following times: (i) as soon as practicable following the termination of board service, (ii) in the first January following the termination of service, or (iii) in the second January following the termination of service. All account distributions are made in lump sum cash payments. If a Participant fails to elect the time at which his account balance will be paid out, it will be paid as soon as practicable following the termination of service. If a Participant elected to receive a Scheduled In-Service Withdrawal, the Participant may subsequently elect to delay such distribution for a minimum period of five calendar years; provided that such election is made at least 12 months prior to the date that such distribution would otherwise be made. If a Participant elected to receive a Scheduled In-Service Withdrawal and the Participant's board service is otherwise terminated prior to such distribution, the Scheduled In-Service Withdrawal will be cancelled and the entire account balance of the Participant will be paid according to the Participant's termination distribution election. In the event of an unforeseeable emergency, a Participant may apply to the plan administrator, who has sole and absolute discretion to approve such application, to request that all or a portion of the Participant's account balance be distributed prior to termination or a Scheduled In-Service Withdrawal. In the event a Participant dies while providing services to us, the Participant's account balance will be paid to the Participant's beneficiary in the manner previously elected by the Participant. The Deferred Plan has provisions that provide for special distribution rights with respect to any spousal claims made pursuant to a domestic relations order.

Administration. The Deferred Plan is administered by our board of directors, or a plan administrator that our board may appoint, which we refer to as the plan administrator. The plan administrator directly administers the Deferred Plan and has the right to adopt rules of procedure and regulations necessary for administration of the Deferred Plan and will review and render decisions respecting claims for benefits under the Deferred Plan, among other powers and duties. The Deferred Plan may be amended, suspended, or terminated at any time by our board; provided that, no such amendment, suspension or termination may adversely impact the amount of benefits a participant has accrued under the Deferred Plan or deprive a participant of such benefits except to the extent required by applicable law. The Deferred Plan also provides for claims for benefits procedures and a review process in the event of a dispute by a Participant under the Deferred Plan.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them as of May 24, 2016, subject to community property laws where applicable.

Name of Beneficial Owner

Niska Sponsor Holdings Cooperatief U.A.(1)	20,488,525	53.93	%	—	—	—
William H. Shea, Jr.	—	—
Vance E. Powers	2,000	*		—	—	—
Mark D. Casaday	—	—
Bruce D. Davis, Jr(2)	—	—
Rick J. Staples	—	—		—	—	—
Robert B. Wallace	—	—		—	—	—
Ralph Alexander	—	—
Michael J. Hennigan	30,918	*
James G. Jackson	43,173	*		—	—	—
E. Bartow Jones	—	—		—	—	—
Stephen C. Muther	49,258	*		—	—	—
Andrew W. Ward	—	—		—	—	—
Olivia Wassenaar	—	—
All directors and executive officers as a group (13 persons)	125,349	*		—	—	—

The following table sets forth certain information with respect to our equity compensation plans as of March 31, 2016.

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

Holdco owns 20,488,525 common units, representing approximately 53.93% of our units and the all the incentive distribution rights. In addition, our manager owns a 1.80% managing member interest in us.

Effective May 12, 2006, our subsidiary, AECO Partnership, entered into a services agreement with certain affiliates of Holdco pursuant to which it would provide employees to manage certain development projects for Holdco or its affiliates in return for a service fee that is to be agreed upon between the parties from time to time. AECO Partnership subsequently assigned its rights and obligations under the services agreement to Niska Partners Management ULC in an Amended and Restated Services Agreement.

Effective July 1, 2015, a management services agreement was established between Mainline Energy Partners, LLC ("Mainline"), REP Management Company VI, LLC, a Riverstone-related entity, and the Company, in which three US executives of Niska Partners will provide services to Mainline. Mainline will reimburse the Company for all reasonable direct and indirect costs and expenses incurred by the Company, including a portion of salaries and benefits, overhead costs and direct out-of-pocket expenses incurred by Niska Partners related to Mainline.

Conflicts of interest exist and may arise in the future as a result of the relationships between our manager and its affiliates (including Holdco), on the one hand, and us and our unaffiliated members, on the other hand. Our directors and officers have fiduciary duties to manage our manager in a manner beneficial to its owners. At the same time, our manager has a fiduciary duty to manage us in a manner beneficial to our unitholders. Our Operating Agreement contains provisions that specifically define our manager's fiduciary duties to the unitholders. Our Operating Agreement also specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware

Limited Liability Company Act, which we refer to as the Delaware Act, provides that Delaware limited liability companies may, in their Operating Agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a manager to members and us.

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

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

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

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

The following table presents fees for professional services rendered by KPMG LLP for 2016 and 2015:

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

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

		Description

2.1	—	Agreement and Plan of Merger and Membership Interest Transfer Agreement, dated as of June 14, 2015, by and among Niska Gas Storage Partners LLC, Niska Gas Storage Management LLC, Niska Sponsor Holdings Coöperatief U.A., Swan Holdings LP and Swan Merger Sub LLC (incorporated by reference to Exhibit 2.1 of the Company's current report on Form 8-K filed on June 18, 2015)
3.1	—	Certificate of Formation of Niska Gas Storage Partners LLC dated January 26, 2010 (incorporated by reference to exhibit 3.1 to Amendment No. 2 to the Company's Registration Statement on Form S-1 (Registration No. 333-165007), filed on April 15, 2010)
3.2	—	Second Amended and Restated Operating Agreement of Niska Gas Storage Partners LLC, dated as of April 2, 2013 (incorporated by reference to exhibit 3.2 to the Company's Current Report on Form 8-K, filed on April 3, 2013)
4.1	—	Registration Rights Agreement between Niska Gas Storage Partners LLC and Niska Sponsor Holdings Coöperatief U.A. dated May 17, 2010 (incorporated by reference to exhibit 10.2 of the Company's Current Report on Form 8-K, filed on May 19, 2010)

			Description

4.2		—	Amendment No. 1 to Registration Rights Agreement made as of August 24, 2011, by and between Niska Gas Storage Partners LLC and Niska Sponsor Holdings Coöperatief U.A. (incorporated by reference to exhibit 4.1 of the Company's Quarterly Report on Form 10-Q, filed on November 7, 2011)
4.3		—	Indenture dated as of March 17, 2014 among Niska Gas Storage Canada ULC and Niska Gas Storage Canada Finance Corp., as issuers, each of the Guarantors party thereto, and The Bank of New York Mellon, as Trustee (incorporated by reference to exhibit 4.1 to the Company's Current Report on Form 8-K, filed on March 18, 2014)
10.1†		—	Niska Gas Storage Partners LLC 2010 Long-Term Incentive Plan effective as of May 16, 2010 (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on May 19, 2010)
10.2		—	Services Agreement dated March 5, 2010 among AECO Gas Storage Partnership, Niska GS Holdings US, L.P. and Niska GS Holdings Canada L.P. (incorporated by reference to exhibit 10.3 to Amendment No. 1 to the Company's Registration Statement on Form S-1 (Registration No. 333-165007), filed on March 29, 2010)
10.3		—	Amended and Restated Credit Agreement dated June 29, 2012, among Niska Gas Storage US LLC, AECO Gas Storage Partnership, Niska Gas Storage Partners LLC and Royal Bank of Canada, as Administrative Agent and Collateral Agent, and the other Lenders and joint book managers party thereto (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on July 5, 2012)
10.4		—	Sponsor Equity Restructuring Agreement by and among Niska Gas Storage Partners LLC and Niska Sponsor Holdings Coöpertief U.A., dated as of April 2, 2013 (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on April 3, 2013)
10.5	†	—	Employment Agreement, dated May 7, 2014, between the Company and William H. Shea, Jr. (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on May 13, 2014)
10.6	†	—	Employment Agreement, dated May 7, 2014, between the Company and Mark D. Casaday (incorporated by reference to exhibit 10.2 of the Company's Current Report on Form 8-K, filed on May 13, 2014)
10.7	†	—	Employment Agreement, dated May 7, 2014, between the Company and Robert B. Wallace (incorporated by reference to exhibit 10.3 of the Company's Current Report on Form 8-K, filed on May 13, 2014)
10.8	†	—	Employment Agreement, dated May 7, 2014, between the Company and Bruce D. Davis, Jr. (incorporated by reference to exhibit 10.4 of the Company's Current Report on Form 8-K, filed on May 13, 2014)
10.9	†	—	Separation Agreement and General Release of Claims, executed on June 18, 2014, between Niska Partners Management ULC and Simon Dupéré, Niska Gas Storage Partners LLC and Niska Holdings L.P. (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on June 20, 2014)
10.10	†	—	Release and Confidentiality Agreement, dated as of June 25, 2014, by and between Niska Gas Storage Partners LLC and Jason Kulsky (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on June 30, 2014)

			Description

10.11	†	—	Employment Agreement, dated June 5, 2015, between the Company and Vance E. Powers. (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on June 5, 2015)
10.12		—	Commitment Letter, dated June 14, 2015, by and between BIF II Swan Finance Co. (Delaware) LLC and Niska Gas Storage Partners LLC (incorporated by reference to exhibit 10.1 of the Company's current report on Form 8-K filed on June 18, 2015)
10.13		—	Credit Agreement, dated as of July 28, 2015, by and between Niska Gas Storage Partners LLC, as the borrower, Swan Finance LP, as Administrative Agent and Collateral Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company's current report on Form 8-K filed on July 31, 2015)
10.14		—	Separation Agreement and General Release of Claims, executed on July 31, 2015, between Bruce D. Davis, Jr., Niska Gas Storage Partners LLC, Niska Gas Transport Inc. and Niska Holdings L.P. (incorporated by reference to Exhibit 10.1 of the Company's current report on Form 8-K filed on August 4, 2015)
10.15		—	Agreement Regarding Niska Gas Storage Partners LLC Phantom Unit Performance Plan Awards, executed on July 31, 2015, between Bruce D. Davis, Jr. and Niska Gas Storage Partners LLC (incorporated by reference to Exhibit 10.2 of the Company's current report on Form 8-K filed on August 4, 2015)
10.16		—	Amendment No. 1 to Amended & Restated Credit Agreement, dated as of February 29, 2016, by and among Niska Gas Storage US, LLC and AECO Gas Storage Partnership, as borrowers, the other loan parties party thereto, Royal Bank of Canada, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company's current report on Form 8-K filed on March 1, 2016)
12.1	*	—	Statement regarding computation of ratios of earnings to fixed charges
21.1	*	—	List of Subsidiaries of Niska Gas Storage Partners LLC
23.1	*	—	Consent of KPMG LLP
31.1	*	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
31.2	*	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
32.1	**	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	**	—	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	*	—	XBRL Instance Document.
101.SCH	*	—	XBRL Taxonomy Extension Schema Document.
101.CAL	*	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB	*	—	XBRL Taxonomy Extension Presentation Linkbase Document.
101.PRE	*	—	XBRL Taxonomy Extension Presentation Linkbase Document.

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

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

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

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

Management evaluated Niska Partners' internal control over financial reporting as of March 31, 2016. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013) ("COSO"). As a result of this assessment and based on the criteria in the COSO framework, management has concluded that, as of March 31, 2016, Niska Partners' internal control over financial reporting was effective.

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

We have audited Niska Gas Storage Partners LLC's internal control over financial reporting as of March 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Niska Gas Storage Partners LLC's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

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

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

In our opinion, Niska Gas Storage Partners LLC maintained, in all material respects, effective internal control over financial reporting as of March 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Niska Gas Storage Partners LLC and subsidiaries as of March 31, 2016 and 2015, and the related consolidated statements of earnings (loss) and comprehensive income (loss), changes in members' equity, and cash flows for each of the years in the three-year period ended March 31, 2016, and our report dated June 10, 2016 expressed an unqualified opinion on those consolidated financial statements.

We have audited the accompanying consolidated balance sheets of Niska Gas Storage Partners LLC and subsidiaries as of March 31, 2016 and 2015, and the related consolidated statements of earnings (loss) and comprehensive income (loss), changes in members' equity, and cash flows for each of the years in the three-year period ended March 31, 2016. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Niska Gas Storage Partners LLC and subsidiaries as of March 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended March 31, 2016, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Niska Gas Storage Partners LLC's internal control over financial reporting as of March 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated June 10, 2016 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

Niska Gas Storage Partners LLC

Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss)

(in thousands of U.S. dollars, except for per unit amounts)

	Year ended March 31,

	2016			2015			2014
REVENUES
Fee-based revenue (Note 16)	$	54,734		$	92,340		$	135,356
Optimization, net (Note 16)		(389	)		5,979			72,040

		54,345			98,319			207,396
EXPENSES (INCOME)
Operating		29,806			39,230			40,834
General and administrative		29,993			26,833			39,937
Depreciation and amortization (Notes 5, 6 and 17)		57,435			117,323			41,286
Interest (Notes 7 and 18)		52,301			51,336			66,315
Loss on extinguishment of debt (Note 8)		—			—			36,697
Impairment of goodwill (Note 6)		—			245,604			—
Losses (gains) on disposals of assets		268			(64	)		—
Foreign exchange (gains) losses		(349	)		380			1,182
Other (income) expense		(4	)		(11	)		358

EARNINGS (LOSS) BEFORE INCOME TAXES		(115,105	)		(382,312	)		(19,213	)

Income tax expense (benefit) (Note 12)
Current		2,536			2,595			82
Deferred		(14,310	)		(34,251	)		(10,338	)

		(11,774	)		(31,656	)		(10,256	)

NET EARNINGS (LOSS) AND COMPREHENSIVE INCOME (LOSS)	$	(103,331	)	$	(350,656	)	$	(8,957	)



Net earnings (loss) allocated to:
Managing Member	$	(1,861	)	$	(6,352	)	$	(171	)



Common unitholders	$	(101,470	)	$	(344,304	)	$	(8,786	)



Earnings (loss) per unit allocated to common unitholders—basic and diluted	$	(2.67	)	$	(9.34	)	$	(0.25	)

Niska Gas Storage Partners LLC

Consolidated Balance Sheets

(in thousands of U.S. dollars)

	As at March 31,

	2016			2015
ASSETS
Current Assets
Cash and cash equivalents	$	10,246		$	11,699
Margin deposits		13,233			13,285
Trade receivables		3,041			2,598
Accrued receivables		35,630			44,140
Natural gas inventory		41,268			136,295
Prepaid expenses and other current assets (Note 4)		12,787			3,788
Short-term risk management assets (Notes 13 and 14)		37,460			41,600

		153,665			253,405
Long-term Assets
Property, plant and equipment, net of accumulated depreciation (Note 5)		772,023			820,467
Intangible assets, net of accumulated amortization (Note 6)		35,852			41,829
Deferred financing costs, net of accumulated amortization (Note 7)		7,004			11,001
Other assets		3,183			3,329
Long-term risk management assets (Notes 13 and 14)		20,170			30,928

		838,232			907,554

	$	991,897		$	1,160,959



LIABILITIES AND MEMBERS' EQUITY
Current Liabilities
Obligations under credit facilities (Note 8)	$	146,086		$	193,500
Current portion of obligations under capital lease (Note 9)		1,381			1,339
Trade payables		389			885
Current portion of deferred taxes (Note 12)		1,154			2,334
Deferred revenue		457			6,669
Accrued liabilities (Note 10)		51,518			47,686
Short-term risk management liabilities (Notes 13 and 14)		32,146			25,560

		233,131			277,973
Long-term Liabilities
Long-term risk management liabilities (Notes 13 and 14)		15,915			20,833
Asset retirement obligations (Note 11)		2,581			2,308
Other long-term liabilities		1,196			1,270
Deferred income taxes (Note 12)		75,229			88,317
Obligations under capital lease (Note 9)		8,206			9,587
Long-term debt (Note 8)		575,000			575,000

		678,127			697,315
Members' Equity (Note 15)
Common units		(184,946	)		(81,805	)
Managing Members' interest		265,585			267,476

		80,639			185,671
Commitments and contingencies (Notes 8 and 20)

	$	991,897		$	1,160,959

Niska Gas Storage Partners LLC

Consolidated Statements of Cash Flows

(in thousands of U.S. dollars)

	Year ended March 31,

	2016			2015			2014
Operating Activities
Net earnings (loss)	$	(103,331	)	$	(350,656	)	$	(8,957	)
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Unrealized foreign exchange (gains) losses		(206	)		372			1,500
Deferred income tax benefit (Note 12)		(14,310	)		(34,251	)		(10,338	)
Unrealized risk management losses (gains) (Note 16)		16,566			(31,694	)		8,732
Depreciation and amortization (Notes 5, 6 and 17)		57,435			117,323			41,286
Amortization of deferred financing costs (Notes 7 and 18)		4,076			3,652			3,354
Loss on extinguishment of debt (Note 8)		—			—			36,697
Losses (gains) on disposals of assets		268			(64	)		—
Impairment of goodwill (Note 6)		—			245,604			—
Non-cash compensation (Note 15)		1,653			2,305			—
Write-downs of inventory (Note 16)		4,300			63,800			4,600
Changes in non-cash working capital (Note 21)		90,854			(55,835	)		15,033

Net cash provided by (used in) operating activities		57,305			(39,444	)		91,907

Investing Activities
Property, plant and equipment expenditures		(3,133	)		(7,587	)		(3,159	)
Purchase of customer contracts		—			—			(2,007	)
Proceeds on disposal of assets		—			14			—

Net cash used in investing activities		(3,133	)		(7,573	)		(5,166	)

Financing Activities
Proceeds from debt issuance		—			—			575,000
Debt redemption / repurchase		—			—			(672,361	)
Proceeds from credit facilities		211,800			712,700			784,500
Repayments of credit facilities		(260,300	)		(638,700	)		(730,000	)
Payments of financing costs		(2,614	)		(857	)		(10,855	)
Payments of unit issuance costs		—			(13	)		(218	)
Repayments of obligations under capital lease		(1,339	)		(1,299	)		(1,259	)
Distributions to unitholders (Note 15)		(3,354	)		(20,105	)		(34,051	)

Net cash (used in) provided by financing activities		(55,807	)		51,726			(89,244	)

Effect of translation on foreign currency cash and cash equivalents		182			(714	)		(403	)
Net (decrease) increase in cash and cash equivalents		(1,453	)		3,995			(2,906	)
Cash and cash equivalents, beginning of the year		11,699			7,704			10,610

Cash and cash equivalents, end of the year	$	10,246		$	11,699		$	7,704



Supplemental cash flow disclosures (Note 22)

Niska Gas Storage Partners LLC

Consolidated Statements of Changes in Members' Equity

(in thousands of U.S. dollars)

	Common Units			Subordinated Units			Managing Member's Interest			Total

Balance, March 31, 2013	$	321,642		$	265,877		$	9,858		$	597,377
Cancellation of subordinated units		—			(265,877	)		265,877			—
Net earnings (loss)		(8,786	)		—			(171	)		(8,957	)
Distributions to unitholders		(51,293	)		—			(1,028	)		(52,321	)
Issuance of common units		18,041			—			—			18,041

Balance, March 31, 2014		279,604			—			274,536			554,140

Net earnings (loss)		(344,304	)		—			(6,352	)		(350,656	)
Distributions to unitholders		(38,985	)		—			(751	)		(39,736	)
Issuance of common units		19,618			—			—			19,618
Non-cash equity contribution from parent		480			—			10			490
Non-cash compensation		1,782			—			33			1,815

Balance, March 31, 2015		(81,805	)		—			267,476			185,671

Net earnings (loss)		(101,470	)		—			(1,861	)		(103,331	)
Distributions to unitholders		(3,294	)		—			(60	)		(3,354	)
Non-cash compensation		1,623			—			30			1,653

Balance, March 31, 2016	$	(184,946	)	$	—		$	265,585		$	80,639

Niska Gas Storage Partners LLC

Notes to Consolidated Financial Statements

(Thousands of U.S. dollars, except for per unit amounts)

Niska Gas Storage Partners LLC ("Niska Partners" or the "Company") is a publicly-traded Delaware limited liability company (NYSE:NKA) which independently owns and/or operates natural gas storage assets in North America. The Company operates the Countess and Suffield gas storage facilities (collectively, the AECO Hub™) in Alberta, Canada, and the Wild Goose and Salt Plains gas storage facilities in California and Oklahoma, respectively. Each of these facilities markets natural gas storage services in addition to optimizing storage capacity with its own proprietary gas purchases.

In June 2015, the Company, Niska Gas Storage Management LLC (the "Managing Member" or the "Manager"), Niska Sponsor Holdings Có ó pertief U.A. ("Holdco") and certain of their affiliates entered into a definitive agreement to be acquired by Brookfield Infrastructure Partners L.P. and its institutional partners ("Brookfield"). Under the terms of the agreement ("Merger Agreement"), Brookfield will acquire all of the Company's outstanding common units for $4.225 per common unit in cash and will acquire the Managing Member and the Incentive Distribution Rights ("IDRs") in the Company (the "Transaction") prior to June 14, 2017. A period provided for in the Merger Agreement for unsolicited consideration of alternative acquisition proposals expired on July 29, 2015.

The closing of the Transaction is dependent on certain conditions related to regulatory requirements being satisfied, including the approval of the California Public Utilities Commission ("CPUC" or the "Commission"). On June 9, 2016, the CPUC issued a decision which approved the transfer of control of the Wild Goose facility to Brookfield. The decision is effective immediately. The Company expects that the merger transaction will proceed in accordance with the terms of the Merger Agreement and that it will close on or prior to July 31, 2016.

At March 31, 2016, Niska Partners had 37,988,724 common units outstanding. Of this amount, 20,488,525 common units are owned by the Carlyle/Riverstone Energy and Power Fund II and Carlyle/Riverstone Energy and Power Fund III and certain affiliates (together the "Carlyle/Riverstone Funds"), through Niska Holdings L.P. and Holdco, along with a 1.80% Managing Member's interest in the Company and all of the Company's IDRs. Including all of the common units owned by the Carlyle/Riverstone Funds, along with the 1.80% Managing Member's interest, the Carlyle/Riverstone Funds have a 54.76% ownership interest in the Company excluding the IDRs, which are a variable interest. The remaining 17,500,199 common units, representing a 45.24% ownership interest in the Company excluding the IDRs, are owned by the public.

These consolidated financial statements have been prepared to reflect the consolidated financial position, results of operations and cash flows of Niska Partners and its subsidiaries and have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").

These financial statements include the accounts of Niska Partners and its wholly-owned subsidiaries, including AECO Gas Storage Partnership, Wild Goose Storage LLC, Niska Gas Storage, LLC, Salt Plains Storage, LLC, Access Gas Services Inc., Access Gas Services (Ontario) Inc., EnerStream Agency Services Inc., and Niska Partners Management ULC. All material intercompany transactions have been eliminated, as well as various management and holding companies.

In preparing these financial statements, Niska Partners is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. Management uses the most current information available and exercises careful judgment in making these estimates. Although management believes that these consolidated financial statements have been prepared within the limits of materiality and within the framework of its significant accounting policies summarized below, actual results could differ from these estimates. Changes in estimates are accounted for on a prospective basis.

The Company's assessment of each of the four revenue recognition criteria as they relate to its revenue producing activities is as follows:

Persuasive evidence of an arrangement exists. The Company's customary practices are to enter into a written contract, executed by both the customer and the Company.

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

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

Collectability is reasonably assured. Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers' financial position (e.g. cash position and credit rating) and their ability to pay. If collectability is not

considered reasonably assured at the outset of an arrangement in accordance with the Company's credit review process, revenue is recognized when the fee is collected.

Fee-based revenue consists of long-term contracts for storage fees that are generated when we provide storage services on a monthly basis and short-term fees associated with park and loan activities. Long-term contract revenue consists of monthly storage fees and fuel and commodity charges for injections and withdrawals. Long-term contract revenue is accrued on a monthly basis in accordance with the terms of the customer contracts. Customer charges for injections and withdrawals are recorded in the month of injection or withdrawal. Short-term contract revenue consists of fees for injections and withdrawals, where the customer pays a fixed fee to inject a specified quantity of natural gas on a specified date or dates and withdraw a specified quantity of natural gas on a specified date. The fee stipulated in a short-term contract for each performance obligation (injection and withdrawal) is recognized when the service occurs.

Energy trading contracts resulting in the delivery of a commodity where Niska Partners is the principal in the transaction are recorded as optimization revenues at the time of physical delivery. Realized and unrealized gains and losses on financial energy trading contracts are included in optimization revenue (see Note 14).

Optimization revenue, net includes realized gains and losses and the net change in unrealized gains and losses on financial and physical energy trading contracts. Optimization revenue results from the purchase of inventory and its forward sale to future periods through financial and physical trading contracts. These derivative contracts are economic hedges that have been entered into to manage commodity price and currency risk associated with buying and selling natural gas across future time periods (see Note 14). The Company does not designate these instruments as hedges and therefore records the unrealized gains and losses on the changes in their fair value through net earnings. Contracts resulting in the delivery of a commodity where Niska Partners is the principal in the transaction are recorded as optimization revenues at the time of physical delivery.

Sales taxes collected from customers and remitted to governmental authorities are excluded from revenues in the consolidated statements of earnings (loss) and comprehensive income (loss).

Niska Partners considers all highly liquid investments purchased with an initial maturity of three months or less to be cash equivalents.

Cash held in margin represents the right to receive or the obligation to pay cash collateral under a master netting arrangement that has not been offset against derivative positions. These derivatives are marked-to-market daily; the profit or loss on the daily position is then paid to, or received from, the account as appropriate under the terms of the Company's contract with its broker.

The Company's inventory is natural gas injected into storage which is held for resale. Inventory is valued at the lower of weighted average cost or market. Adjustments to write down the costs of inventory to market are recorded as an offset to optimization revenues while costs to store the gas are recognized as operating expenses in the period the costs are incurred in the consolidated statements of earnings (loss) and comprehensive income (loss).

Property, plant and equipment are recorded at cost when purchased. Depreciation is computed using the declining balance method for each category of asset using the following rates:

Property, plant and equipment under capital leases are depreciated using the declining balance method over the lesser of the useful lives of the assets or the lease term.

Costs of major overhauls of engines and compressors included within the facilities account are depreciated using the actual number of hours used over the estimated number of hours until the next scheduled major overhaul.

Certain volumes of hydrocarbons defined as cushion are required for maintaining a minimum field pressure. Cushion is considered a component of the facility and as such is not amortized. Cushion is monitored to ensure that it provides effective pressure support for the facility. In the event that cushion moves to another area of the reservoir where it does not provide effective pressure support, a loss is recorded, within depreciation expense, equal to the cost of estimated volumes that have migrated. Proceeds from sale of cushion are classified as operating activities in the consolidated statements of cash flows since the predominant source of cash flows for natural gas purchases and sales are operating in nature.

Repairs, maintenance and renewals that do not provide future economic benefits to the assets are expensed as incurred. Interest costs for the construction or development of long-lived assets held by operational entities are capitalized and amortized over the related asset's estimated useful life.

Niska Partners records a liability for an asset retirement obligation when the legal obligation to retire the asset has been incurred with an offsetting increase to the carrying value of the related tangible long-lived asset. The recognition of an asset retirement obligation requires that management make numerous estimates, assumptions and judgments regarding such factors as the estimated probabilities, amounts and timing of settlements, the credit-adjusted risk-free rate, inflation rates and

future advances in technology. In periods subsequent to initial measurement of the liability, the Company must recognize changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Over time, the liability is accreted to its future value, and the capitalized cost is depreciated over the useful life of the related asset. Accretion of the asset retirement obligations due to the passage of time is recorded as an expense in the statement of earnings. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss.

Certain risk management assets and liabilities and certain accrued gas sales and purchases are presented on a net basis in the balance sheet when all of the following exist: (i) Niska Partners and the other party owe the other a determinable amount; (ii) the Company has the right to set off the amount owed with the amount owed by the other party; (iii) Niska Partners intends to set off; and (iv) the right of setoff is enforceable by law.

Niska Partners determines a lease to be an operating or capital lease based upon the terms of the lease, estimated fair value of the leased assets, estimated life of the leased assets, and the contractual minimum lease payments as defined within the lease agreements. If the Company concludes that it has substantively all of the risks of ownership of a leased property and therefore is deemed the owner of the property for accounting purposes, it records an asset and related obligations under capital lease at the lower of the present value of the minimum lease payments or the fair value of the asset.

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

Intangible assets represent contractual rights obtained in connection with a business combination that had favorable contractual terms relative to market as of the acquisition date.

Intangible assets representing customer contracts and relationships are amortized over their useful lives. These assets are reviewed for impairment as impairment indicators arise. When such events or circumstances are present, the recoverability of long-lived assets is assessed by determining whether the carrying value will be recovered through the expected undiscounted future cash flows. In the event that the sum of the expected future cash flows resulting from the use of the asset is less than the carrying

value of the asset, an impairment loss equal to the excess of the asset's carrying value over its fair value is recorded.

Pipeline rights of way are formal agreements granting rights of way in perpetuity and are not subject to amortization but are subject to an annual impairment test.

The Company uses natural gas derivatives and other financial instruments to manage its exposure to changes in natural gas prices, and foreign exchange rates. These financial assets and liabilities, which are recorded at fair value on a recurring basis, are included in one of three categories based on a fair value hierarchy with realized and unrealized gains (losses) recognized in net earnings (loss) for the period (see Note 14).

The fair value of the Company's derivative risk management contracts are recorded as a component of risk management assets and liabilities, which are classified as current or non-current assets or liabilities based upon the anticipated settlement date of the contracts.

The functional and reporting currency of the Company is the U.S. dollar. Non-U.S. dollar denominated monetary items are translated into U.S. dollars at the rate of exchange in effect at the balance sheet date. Non-U.S. dollar denominated non-monetary items are translated to U.S. dollars at the exchange rate in effect when the transaction occurred. Revenues and expenses denominated in foreign currencies are translated at the actual exchange rate or average exchange rate in effect during the period. Foreign exchange gains or losses on translation are included as a component of net earnings (loss) for the period.

Deferred financing costs relate to costs incurred on the issuance of debt, and are amortized over the term of the related debt to interest expense using the effective interest method for costs related to the senior notes offering. Deferred financing costs incurred on credit facilities are amortized on a straight line basis. Any remaining unamortized deferred financing costs related to repurchased senior notes are written off on the dates of redemption.

The Company is not a directly taxable entity. Income taxes on its income are the responsibility of the individual unitholders and accordingly, have not been recorded in the consolidated financial statements. However, Niska Partners does own corporate subsidiaries which are taxable corporations subject to Canadian federal and provincial income taxes and which are included in the consolidated financial statements.

Income taxes on the Canadian corporate subsidiaries are determined using the asset and liability method, which results in deferred income tax assets and liabilities arising from temporary differences.

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

The Company's policy is to recognize accrued interest and penalties on accrued tax balances as components of interest expense.

Niska Partners' compensation committee approves the awards of unit-based performance plans to certain key employees. These awards include both time and performance-based components.

Unit-based awards are classified as liabilities when expected to be settled in cash or when the Company has the option to settle in cash or equity. This accounting treatment has resulted from the Company's historical practice of choosing to settle this type of award in cash. When awards are classified as liabilities, the fair value of the units granted is determined on the date of grant and is re-measured at each reporting period until the settlement date. The fair value at each re-measurement date is equal to the settlement expected to be incurred based on the anticipated number of units vested, adjusted for (i) the passage of time and (ii) the payout threshold associated with the performance targets which the Company expects to achieve compared to its established peers. The pro-rata number of units vested is calculated as the number of performance awards multiplied by the percentage of the requisite service period.

Unit-based awards that are expected to be settled in units are classified as equity. The fair value of the units granted is determined on the date of grant and is amortized to equity using the straight-line method over the vesting period. Each equity settled award permits the holder to receive one common unit on the vesting date.

All of the granted unit-based awards have the right to receive additional units in lieu of cash distributions paid on the outstanding units. The typical vesting period ranges from two to three years from the date of grant.

In May 2014, the FASB adopted Accounting Standards Update No. 2014-09 ("ASU 2014-09"), Revenue from Contracts with Customers. Under the new rules, companies will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects to receive in exchange for the goods or services. The rules also require more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. This was subsequently amended by two additional updates, Accounting Standards Update No. 2015-14 in which the implementation date for public entities was deferred to become effective for interim and annual periods in fiscal years beginning after December 15, 2017, and Accounting

Standards Updated No. 2016-08 in which additional guidance on principal versus agent considerations in recording revenue were provided. Management is currently evaluating the impact of the pending adoption of ASU 2014-09 on the Company's consolidated financial statements and has not yet determined the method by which it will adopt the standard in 2018.

In August 2014, the FASB adopted Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The new accounting guidance requires management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern within one year after the date that the financial statements are issued. It also requires increased disclosures if management determines that substantial doubt about the entity's ability to continue as a going concern exist. The Company will adopt this guidance on April 1, 2017, and Management believes that its impact will not be material to the Company's results of operations and amount of disclosures.

In April 2015, the FASB adopted Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. Under the new accounting guidance, companies are required to present deferred financing costs related to a recognized debt liability as a direct deduction from the carrying amount of the related debt, consistent with debt discounts. In June 2015, FASB adopted Accounting Standards Update No. 2015-15, which further clarified that the Company may choose to present deferred financing costs related to line-of-credit agreements as an asset and amortize the costs ratably over the term of the line-of-credit agreement. The Company will adopt this guidance on April 1, 2016 on a retrospective basis, wherein the balance sheet of each individual date presented will be adjusted to show long-term debt net of related deferred financing costs. In line with ASU 2015-15, the Company has chosen to continue to present the deferred financing costs related to the credit facilities as an asset.

In July 2015, the FASB adopted Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory. Under the updated accounting guidance, companies are required to measure inventory at the lower of cost and net realizable value, whereas previously companies would be able to measure inventory at the lower of cost or market (which included several different methods). The Company will adopt this guidance on April 1, 2017 on a prospective basis, and Management believes that its impact will not be material to the Company's balance sheet and results of operations.

In November 2015, the FASB adopted Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes. Under the new accounting guidance, companies are required to change the presentation of deferred income taxes to include deferred tax liabilities and assets as noncurrent in a classified statement of financial position. This differs from previous guidance whereby deferred tax liabilities and assets were split between current and long term portions. The Company will adopt this guidance on April 1, 2018, and Management believes that its impact will not be material to the Company's results of operations and amount of disclosures.

In January 2016, the FASB adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. The new accounting guidance addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. The Company will adopt this guidance on April 1, 2018, and Management believes that its impact will not be material to the Company's results of operations and amount of disclosures.

In February 2016, the FASB adopted Accounting Standards Update No. 2016-02 ("ASU 2016-02"), Leases. Under the new accounting guidance, leases classified as operating leases, which were historically not included on the balance sheet, will be required to recognize a liability to make lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. Management is currently evaluating the impact of the pending adoption of ASU 2016-02 on the Company's consolidated financial statements and has not yet determined the method by which it will adopt the standard in 2019.

In March 2016, the FASB adopted Accounting Standards Update No. 2016-06 ("ASU 2016-06"), Contingent Put and Call Options in Debt Instruments. The amendments in this update clarify the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts using a four-step decision sequence, which could result in the embedded derivative being separated from the host contract and accounted for separately as a derivative. Management is currently evaluating the impact of the pending adoption of ASU 2016-06 on the Company's consolidated financial statements and has not yet determined the method by which it will adopt the standard on April 1, 2018.

In March 2016, the FASB adopted Accounting Standards Update No. 2016-09 ("ASU 2016-09"), Compensation—Stock Compensation. The amendments in this update effect several aspects of the accounting for share-based payment transactions, including income tax consequences, and the classification on the statement of cash flows. Management is currently evaluating the impact of the pending adoption of ASU 2016-09 on the Company's consolidated financial statements and believes that its impact will not be material to the Company's results of operations and amount of disclosures when it adopts the new standard on April 1, 2018.

As substantially all inventory is economically hedged, any hedging gains or losses are offset by realized losses or gains from the sale of physical inventory.

	As at March 31, 2016

	Cost		Accumulated Depreciation			Net Book Value
Cushion	$	332,259	$	—		$	332,259
Pipelines and measurement		296,669		(112,574	)		184,095
Wells		127,469		(49,122	)		78,347
Facilities		278,360		(104,769	)		173,591
Computer hardware and software		4,507		(3,730	)		777
Construction in progress, including projects under development		2,099		—			2,099
Office furniture, equipment and other		2,515		(1,660	)		855

	$	1,043,878	$	(271,855	)	$	772,023

	As at March 31, 2015

	Cost		Accumulated Depreciation			Net Book Value
Cushion	$	356,655	$	—		$	356,655
Pipelines and measurement		296,669		(102,885	)		193,784
Wells		127,297		(45,004	)		82,293
Facilities		276,892		(92,473	)		184,419
Computer hardware and software		4,293		(3,440	)		853
Construction in progress, including projects under development		1,486		—			1,486
Office furniture, equipment and other		2,515		(1,538	)		977

	$	1,065,807	$	(245,340	)	$	820,467

Facilities include cost and accumulated depreciation of assets under capital lease of $14.2 million and $8.3 million as of March 31, 2016, respectively, and $14.2 million and $6.6 million as of March 31, 2015, respectively. It also includes the cost and accumulated depreciation of major overhauls of engines and compressors of $3.2 million and $0.3 million, respectively, at March 31, 2016, and $2.4 million and $0.1 million, respectively, at March 31, 2015.

During the year ended March 31, 2015, the Company concluded that a number of factors, including the continued narrow difference between summer and winter prices in the natural gas futures market, combined with a significant reduction in natural gas price volatility and a significant decline in the Company's equity market capitalization were impairment indicators. This determination was made because these factors had a material negative effect on the Company's current financial performance and expected performance in future years.

The goodwill impairment test is performed at a reporting unit level. Reporting units are identified and distinguished based on how the associated business is managed, taking into consideration the nature of services offered, the types of customer contracts entered into and the nature of the economic and regulatory environment. Niska Partners has four reporting units (its AECO Hub^TM facility in Alberta, its Wild Goose facility in California, its Salt Plains facility in Oklahoma and its contractual capacity on the Natural Gas Pipeline of America ("NGPL") system). These reporting units are aggregated into one operating segment for financial reporting purposes. Prior to the impairment test, Niska Partners' total goodwill of $245.6 million was allocated to the AECO Hub^TM facility ($228.0 million) and the NGPL capacity ($17.6 million). There was no goodwill recorded at the Wild Goose or Salt Plains facilities.

The performance of the impairment test involves a two-step process. The first step determines whether an impairment exists by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the estimated fair value of the reporting unit exceeds its carrying amount, no impairment is necessary. If the carrying amount of a reporting unit exceeds its estimated fair value, the second step measures the amount of impairment by comparing the implied fair value of the reporting unit goodwill with the carrying amount of that goodwill. An entity assigns the fair value of a reporting unit to all of the assets and liabilities of that unit as if the reporting unit had been acquired in a business combination. The excess of the fair value of a reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill.

The Company determined the fair value of the AECO Hub^TM and NGPL reporting units using a combination of the present value of future cash flows method and the comparable transactions method. The present value of future cash flows was estimated using: (i) discrete financial forecasts, which rely on management's estimates of revenue, expenses and volumes; (ii) long-term natural gas volatility and seasonal spreads; (iii) long-term average exchange rates between the United States dollar and the Canadian dollar; and (iv) appropriate discount rates. The comparable transactions method analyzed other purchases of similar assets and considered: (i) the anticipated cash flows of the Company determined above; (ii) recent transaction multiples based on anticipated cash flows; and (iii) the similarity of comparable transactions to the Company's facilities. Specifically, the Company used experience and forecasted amounts to estimate cycling volumes and expenses, the future summer to winter spreads which reflects its longer-term outlook, and extrinsic values consistent with those achieved in the business to estimate future revenue. The Company also used a comparable transaction multiple consistent with recent transactions for depleted reservoir storage facility acquisitions (the type of facilities comparable to the Company's AECO Hub^TM facility). Both the AECO Hub^TM and the NGPL reporting units failed step one of the goodwill impairment test; therefore, the second step of impairment test was performed. In step two, the Company compared the implied fair value of each reporting unit's goodwill with the respective carrying amount of that goodwill. Under step two of the impairment test, significant assumptions in measuring the fair value of the assets and liabilities included: (i) the replacement cost, depreciation and obsolescence and useful lives of property, plant and equipment; and (ii) the present value of incremental cash flows attributable to certain intangible assets. Based on the step two analysis, the Company determined its goodwill balance was fully impaired, and accordingly an impairment charge of $245.6 million was recorded.

Information regarding the Company's intangible assets is included in the following table:

Customer contracts and relationships are amortized over the term of the respective contracts, being 1 to 8 years remaining at March 31, 2016. The following table presents an estimate of future amortization expense based upon the Company's intangible assets at March 31, 2016:

Amortization expense for customer contacts and relationships for each of the three years ended March 31, 2016 is presented in Note 17.

Information regarding the Company's deferred financing costs consists of the following:

	As at March 31,

	2016			2015
Deferred financing costs, beginning of the year	$	20,091		$	20,078
Additions		2,656			13

Deferred financing costs, end of the year		22,747			20,091

Accumulated amortization, beginning of the year		(9,090	)		(5,438	)
Amortization recognized as interest (see Note 18)		(4,076	)		(3,652	)

Accumulated amortization, end of the year		(13,166	)		(9,090	)

Net book value		9,581			11,001
Less: portion classified as current (see Note 4)		(2,577	)		—

	$	7,004		$	11,001



Life in years		1 - 3			2 - 4

In March 2014, Niska Partners completed a private placement of senior unsecured notes due 2019 (the "6.50% Senior Notes" or "Notes") through its subsidiaries Niska Gas Storage Finance Corp. and Niska Gas Storage Canada ULC (together, the "Issuers"). Net proceeds from the offering of approximately $563.3 million, after deducting underwriters' discounts and fees, along with borrowings under our asset-based revolving credit facilities, were used to redeem the then outstanding principal amount of $643.8 million of the 8.875% Senior Notes due 2018. Including a call premium of approximately $28.6 million and the write-off of unamortized deferred financing costs of $8.1 million, the Company recognized a loss of $36.7 million, which was recorded as a loss on extinguishment of debt in fiscal 2014. Costs directly related to the issuance of the new Notes were capitalized as deferred financing costs and are amortized to interest expense over the term of the debt.

On December 3, 2014, the U.S. Securities and Exchange Commission accepted and made effective the Company's exchange offer whereby holders of the 6.50% Senior Notes were permitted to exchange such Senior Notes for new freely transferable Senior Notes. The terms of the new units are identical to the units issued on March 17, 2014 except that the new units are registered under the Securities Act and generally do not contain restrictions on transfer. The exchange offer was completed on January 7, 2015 and substantially all the holders of the Senior Notes accepted the offer.

The 6.50% Senior Notes are senior unsecured obligations which are: (1) effectively junior to Niska Partners' secured obligations to the extent of the value of the collateral securing such debt; (2) equal in right of payment with all existing and future senior unsecured indebtedness of the Company; and (3) senior in right of payment to any future subordinated indebtedness of Niska Partners. The 6.50% Senior Notes are fully and unconditionally guaranteed by Niska Partners and certain of its direct and indirect subsidiaries on a senior unsecured basis, and are: (1) effectively junior to each guarantor's secured obligations; (2) equal in right of payment with all existing and future senior unsecured indebtedness of each guarantor; and (3) senior in right of payment to any future subordinated indebtedness of each guarantor. Interest on the 6.50% Senior Notes is payable semi-annually on October 1 and April 1, and will mature on April 1, 2019. As of March 31, 2016, the estimated fair market value of the Notes was $460.0 million.

Prior to October 1, 2016, the Company has the option to redeem up to 35% of the aggregate principal amount of the 6.50% Senior Notes using net cash proceeds from certain equity offerings at a

price of 106.50% plus accrued and unpaid interest. The Company may also redeem all or a part of the 6.50% Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.25% during the twelve-month period beginning on October 1, 2016, 101.625% during the twelve-month period beginning on October 1, 2017 and at par beginning on October 1, 2018, plus accrued and unpaid interest. The Company is not required to make mandatory redemptions or sinking fund payments with respect to the 6.50% Senior Notes.

The indenture governing the 6.50% Senior Notes limits Niska Partners' ability to pay distributions in respect of, repurchase or pay dividends on its membership interests (or other capital stock) or make other restricted payments. However, it does not prohibit certain types or amounts of restricted payments, including a general basket of $75.0 million of restricted payments.

The indenture governing the Notes contains certain other covenants that, among other things, limit Niska Partners and certain of its subsidiaries' ability to:

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

Upon the occurrence of a change of control together with a decrease in the ratings of the 6.50% Senior Notes by either Moody's or S&P by one or more gradations within 90 days of the change of control event, Niska Partners must offer to repurchase the Notes at 101% of the principal amount of the notes to be repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.

The Company's ability to repurchase the 6.50% Senior Notes upon a change of control will be limited by the terms of its debt agreements, including the Credit Agreement. In addition, the Company cannot assure that it will have the financial resources to repurchase the Notes upon a change of control.

Niska Partners, through its subsidiaries, Niska Gas Storage US, LLC and AECO Gas Storage Partnership has senior secured asset-based revolving credit facilities, consisting of a U.S. revolving credit facility and a Canadian revolving credit facility (the "Revolving Credit Facilities", or the "Credit Agreement").

These revolving credit facilities previously provided for revolving loans and letters of credit in an aggregate principal amount of up to $200.0 million for each of the U.S. and Canadian revolving credit facilities. Loans under the U.S. revolving facility will be denominated in U.S. dollars and loans under the Canadian revolving facility may be denominated, at Niska Partners' option, in either U.S. or Canadian dollars.

On February 29, 2016, the Company completed an amendment and extension of its Credit Agreement, which included the approval of a change of control associated with the Transaction. The amended and restated Revolving Credit Facilities extends the term of the original agreement from June 29, 2016 to September 30, 2016 and allows for an additional term extension to December 31, 2016 providing that the Transaction has closed. The maximum capacity of the amended and restated Credit Agreement was reduced to $160.0 million for each of the U.S. and Canadian revolving credit facilities effective February 29, 2016 and effective June 29, 2016, interest on borrowings under the Credit Agreement will increase by 1% to the extent that the Company's consolidated leverage ratio is above 5.0 to 1.0.

Borrowings under the Revolving Credit Facilities are limited to a borrowing base calculated as the sum of specified percentages of eligible cash equivalents, eligible accounts receivable, the net liquidating value of hedge positions in broker accounts, eligible inventory, issued but unused letters of credit, and certain fixed assets minus the amount of any reserves and other priority claims. Borrowings bear interest at a floating rate, which (1) in the case of U.S. dollar loans can be either LIBOR plus an applicable margin or, at the Company's option, a base rate plus an applicable margin, and (2) in the case of Canadian dollar loans can be either the bankers' acceptance rate plus an applicable margin or, at the Company's option, a prime rate plus an applicable margin. The Credit Agreement provides that the Company may borrow only up to the lesser of the level of our then current borrowing base and our committed maximum borrowing capacity, which is currently $320.0 million. As of March 31, 2016, the borrowing base collateral totaled $225.3 million.

Obligations under the Credit Agreement are guaranteed by Niska Partners and all of the Company's direct and indirect wholly owned subsidiaries (subject to certain exceptions) and secured by a lien on substantially all of the Company's and its direct and indirect subsidiaries' current and fixed assets (subject to certain exceptions). Certain fixed assets will only be required to be part of the collateral to the extent such fixed assets are included in the borrowing base under the Credit Agreement. The aggregate borrowing base under the Credit Agreement includes $150.0 million (the "PP&E Amount") due to a first-priority lien on fixed assets granted to the lenders.

The Credit Agreement contains limitations on Niska Partners' ability to incur additional debt or to pay distributions in respect of, repurchase or pay dividends on its membership interests (or other capital stock) or make other restricted payments. These limitations are similar to those contained in the indenture governing the 6.50% Senior Notes, but contain certain substantive differences. As of

March 31, 2016, Niska Partners was in compliance with all covenant requirements under the 6.50% Senior Notes and the Credit Agreement.

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

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

The Credit Agreement provides that, upon the occurrence of certain events of default, the Company's obligations thereunder may be accelerated and the lending commitments terminated. Such events of default include payment defaults to the lenders, material inaccuracies of representations and warranties, covenant defaults, cross-defaults to other material indebtedness, including the notes, voluntary and involuntary bankruptcy proceedings, material money judgments, material events relating to pension plans, certain change of control events and other customary events of default. As of March 31, 2016, $106.0 million (March 31, 2015—$193.5 million) in borrowings, with a weighted average interest rate of 4.27% (March 31, 2015—3.98%), were outstanding under the Credit Facilities. Issued letters of credit amounted to $9.6 million and $5.8 million as of March 31, 2016 and 2015, respectively.

On July 28, 2015, the Company entered into a credit agreement with Brookfield for a $50.0 million short-term credit facility (the "Short-term Credit Facility"), which may be borrowed on subject to certain customary conditions. As of March 31, 2016, the outstanding amount of $40.1 million under the Short-term Credit Facility bears interest at an annual rate of 10%, which is payable in cash on a quarterly basis, unless the Company elects to pay such interest in-kind by capitalizing accrued interest into the principal amount. During the year ended March 31, 2016, $1.1 million of interest was accrued and paid in-kind.

Amounts borrowed under the Short-term Credit Facility may be prepaid without premium and penalty, and all amounts due and owing under the Short-term Credit Facility will be payable on the earlier of January 28, 2017 or the first to occur of (a) the acceleration of the loans during the continuance of an event of default under the Short-term Credit Facility; (b) the date on which the Merger Agreement is terminated in accordance with its terms; (c) the date that is 90 days after the date on which the required lenders have determined that the acquisition of the business of the Company and its subsidiaries pursuant to the Merger Agreement cannot or will not be consummated for any reason, including without limitation regulatory matters or legal bars; and (d) any uncured breach of any other agreement between the Company and certain affiliates, on the one hand, and any lenders or any affiliate thereof, on the other hand, which results in termination of such agreement.

The Company's obligations under the Short-term Credit Facility are secured by substantially all of the assets of the Company and its subsidiaries that guarantee the obligations under its Revolving Credit Facilities. The Short-term Credit Facility requires the Company to comply with certain affirmative and negative covenants, with the Company permitted to enter into activities to the extent permitted by both the Merger Agreement and the Company's Revolving Credit Facilities. The Company is also subject to customary events of default, substantially consistent with its Revolving Credit Facilities.

On June 9, 2016, the CPUC issued a decision which approved the transfer of control of the Wild Goose facility to Brookfield, effective immediately. The Company believes that it is probable that the Merger will be completed on or before July 31, 2016 at which time the Company will pursue replacement financing. See Notes 1 and 26 for additional information on the Merger. Should the merger not close as anticipated, the maturity of the Revolving Credit Facilities on September 30, 2016 would require the Company to seek a further extension of the maturity date or raise additional funds to repay the amounts projected to be outstanding at that time because the Company does not expect to have sufficient resources to completely repay the outstanding balances of the Revolving Credit Facilities and the Short-Term Credit Facility on their respective maturity dates. Failure to repay the Revolving Credit Facilities when due would also constitute an event of default under the terms of the 6.50% Senior Notes. Management can provide no assurance that the Company will be able to obtain a further extension of the maturity date or raise additional funds to repay the Revolving Credit Facilities and Short-Term Credit Facility upon maturity.

Niska Partners has no independent assets or operations other than its investments in its subsidiaries. The 6.50% Senior Notes, Revolving Credit Facilities and Short-term Credit Facility have been jointly and severally guaranteed by Niska Partners and substantially all of its subsidiaries. Niska Partners' subsidiaries have no significant restrictions on their ability to pay distributions or make loans to Niska Partners, which are prepared and measured on a consolidated basis, and have no restricted assets as of March 31, 2016.

The Company's principal debt covenant is the fixed charge coverage ratio, which is included in the Credit Agreement and in the Indenture. When the fixed charge coverage ratio is less than 2.0 times, Niska Partners is restricted in its ability to issue new debt. When the fixed charge coverage ratio is

below 1.75 to 1.0, the Company is restricted in its ability to pay distributions. When the Company's FCCR is below 1.1 times, the Company will be unable to borrow the last 15% of availability without triggering an event of default. At March 31, 2016, the fixed charge coverage ratio was 0.3 to 1.0 and the Company was subject to the above restrictions limiting the last 15% of availability under the Credit Agreement. Accordingly, the availability under the Credit Agreement has been reduced by 15%, to $191.5 million. As of March 31, 2016, $56.9 million of the Company's availability remained unutilized.

The Company leases certain equipment under a lease arrangement for estimated future minimum lease payments of approximately $10.5 million. Niska Partners may purchase the assets after August 15, 2020 for an agreed portion of the acquisition cost. The present value of the minimum future lease payments is based on the total costs incurred by the lessor and has been reflected in the balance sheet as a current and a non-current obligation under capital lease. The underlying obligations are denominated in U.S. dollars, have an imputed interest rate of 3.08% and are owing through the lease maturity in August 2021.

Following are the future principal and interest payments of obligations under capital lease as of March 31, 2016:

Niska Partners' asset retirement obligations relate to the plugging and abandonment of the storage facilities and wells at the end of their estimated useful economic lives. At March 31, 2016, the estimated undiscounted cash flows required to settle the asset retirement obligations were approximately $60.6 million, calculated using an inflation rate of 2% per annum. The estimated liability at March 31, 2016 was $2.6 million after discounting the estimated cash flows at a rate of 8% per annum. At March 31, 2016, the expected timing of payment for settlement of the obligations is 41 years.

Total income tax benefit differed from the amounts computed by applying the tax rate to earnings (loss) before income taxes as a result of the following:

	Year ended March 31,

	2016			2015			2014
Earnings (loss) before income taxes	$	(115,105	)	$	(382,312	)	$	(19,213	)
U.S. federal corporate statutory rate		35.00	%		35.00	%		35.00	%

Expected tax benefits		(40,287	)		(133,809	)		(6,725	)
Earnings (loss) of non-taxable entities		16,970			(1,925	)		(6,296	)
Change in Canadian statutory tax rates		7,288			—			—
Canadian statutory tax rate differences		5,625			39,056			3,559
Adjustments and assessments		(646	)		2,592			(690	)
Non-deductible expense related to asset impairment		—			57,001			—
Change in valuation allowance		(2,770	)		2,314			(1,248	)
Non-deductible expenses and other		2,046			3,115			1,144

Income tax benefit	$	(11,774	)	$	(31,656	)	$	(10,256	)

The Company is not a taxable entity in the United States. Income taxes on its income are the responsibility of individual unitholders and have accordingly not been recorded in the consolidated financial statements. Niska Partners has Canadian corporate subsidiaries, which are taxable corporations subject to income taxes, and are included in the consolidated financial statements.

As at March 31, 2016, Niska Partners' Canadian subsidiaries had accumulated non-capital losses of approximately $122.1 million (March 31, 2015—$76.4 million) that can be carried forward and applied against future taxable income. These non-capital losses have resulted in deferred income tax assets of $32.8 million (March 31, 2015—$19.0 million). Additionally, Niska Partners' Canadian subsidiaries had recognized deferred income tax assets related to capital losses of $33.8 million at March 31, 2016 (March 31, 2015—$33.8 million). These capital losses represent $4.6 million (March 31, 2015—$4.2 million) of deferred tax assets, of which $4.6 million (March 31, 2014—$4.2 million) have been offset by valuation allowances due to the uncertainty of their realization. Of the total tax assets related to losses, $122.1 million will begin to expire at the end of 2034.

For the year ended March 31, 2016, Niska Partners recognized $ nil (March 31, 2015—$0.1 million; March 31, 2014—$ nil) of potential interest and penalties associated with uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction, various state jurisdictions and other foreign jurisdictions. The Company is subject to income tax examinations for the fiscal years ended 2008 through 2016 in most jurisdictions. Deferred income tax assets and liabilities reflect the tax effect of differences between the basis of assets and liabilities for book and tax purposes. The tax effect of temporary differences that give rise to significant components of the deferred income tax liabilities and deferred income tax assets are presented below:

	As at March 31,

	2016			2015
Deferred income tax assets:
Non-capital loss carry forwards	$	32,815		$	18,959
Risk management liabilities		23,289			19,919
Capital losses		4,561			4,223
Deferred financing costs		2,907			4,006
Other		5,713			2,774

		69,285			49,881
Valuation allowance		(8,603	)		(7,173	)

Total deferred income tax assets	$	60,682		$	42,708



Deferred income tax liabilities:
Property, plant and equipment	$	101,914		$	99,628
Risk management assets		26,346			24,202
Intangible assets		8,621			9,510
Other		184			19

Total deferred income tax liabilities		137,065			133,359

Net deferred income tax liability	$	76,383		$	90,651

The classification of net deferred income tax liabilities recorded on the balance sheets is as follows:

When accounting for uncertainty in income taxes, a company recognizes a tax benefit in the financial statements for an uncertain tax position if management's assessment is that the position is "more likely than not" (i.e. a likelihood greater than fifty percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term "tax position" refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods.

The following table indicates the changes to the Company's unrecognized tax benefits for the years ended March 31, 2016 and 2015. The term "unrecognized tax benefits" refers to the differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in the financial statements. Interest and penalties are not included.

Substantially all of the $2.1 million of unrecognized tax benefits at March 31, 2016, would have an impact on the effective tax rate if subsequently recognized.

The Company engages in ongoing discussions with tax authorities regarding the resolution of tax matters in various jurisdictions. Both the outcome of these tax matters and the timing of the resolution and/or closure of the tax audits are highly uncertain. It is management's assessment that no unrecognized tax benefits will be recognized within the next twelve months.

The Company has exposure to commodity and environmental compliance prices, foreign currency, counterparty credit, interest rate, and liquidity risk. Risk management activities are tailored to the risk they are designed to mitigate.

As a result of its natural gas inventory and any future requirements to purchase cushion, Niska Partners is exposed to risks associated with changes in price when buying and selling natural gas across future time periods. To manage these risks and reduce variability of cash flows, the Company utilizes a combination of financial and physical derivative contracts, including forwards, futures, swaps and option contracts. The use of these contracts is subject to the Company's risk management policies. These contracts have not been treated as hedges for financial reporting purposes and therefore changes in fair value are recorded directly in earnings.

Forward contracts and futures contracts are agreements to purchase or sell a specific financial instrument or quantity of natural gas at a specified price and date in the future. Niska Partners enters into forward contracts and futures contracts to mitigate the impact of changes in natural gas prices. In addition to cash settlement, exchange traded futures may also be settled by the physical delivery of natural gas. Swap contracts are agreements between two parties to exchange streams of payments over time according to specified terms. Swap contracts require receipt of payment for the notional quantity of the commodity based on the difference between a fixed price and the market price on the settlement date. Niska Partners enters into commodity swaps to mitigate the impact of changes in natural gas prices.

Option contracts are contractual agreements to convey the right, but not the obligation, for the purchaser of the option to buy or sell a specific physical or notional amount of a commodity at a fixed price, either at a fixed date or at any time within a specified period. Niska Partners enters into option agreements to mitigate the impact of changes in natural gas prices.

To limit its exposure to changes in commodity prices, Niska Partners enters into purchases and sales of natural gas inventory and concurrently matches the volumes in these transactions with offsetting derivative contracts. To comply with its internal risk management policies, Niska Partners is required to limit its exposure of unmatched volumes of proprietary current natural gas inventory to an aggregate overall limit of 8.0 MDth. At March 31, 2016, 25.3 MDth (March 31, 2015—47.2 MDth) of natural gas inventory was offset with financial contracts, representing 99.2% (March 31, 2015—98.6%) of total inventory. Fuel gas included in the volumes above that is used for operating facilities is not offset. Total volume of our fuel gas was 0.3 MDth and 0.0 MDth as of March 31, 2016 and 2015, respectively.

As of March 31, 2016 and March 31, 2015, the volumes of inventories which were economically hedged using each type of contract were (In MDth):

In addition to the volumes mentioned above, as at March 31, 2016, the Company has entered into forward purchase contracts for 1.5 MDth of natural gas representing 42% of its estimated cushion purchases in fiscal 2017.

One of Niska Partners' operating facilities, the Wild Goose storage facility, is located in California. In 2006, California adopted AB 32, the Global Warming Solutions Act of 2006, with a goal of reaching: (i) 1990 greenhouse gases ("GHG") emissions levels by the year 2020; (ii) 80% of 1990 levels by 2050; and (iii) a mandatory emission reporting program. AB 32 required the California Air Resources Board ("ARB") to develop a scoping plan describing the approach California will take to reduce GHGs to achieve the goal of reducing emissions to 1990 levels by 2020 (the "2020 Goal"). The scoping plan was first approved by the ARB in 2008 which identifies a cap-and-trade program as one of the strategies California will employ to meet the 2020 Goal. In 2010, ARB approved that cap-and-trade program and it came into effect on January 1, 2013.

Entities are subject to compliance obligations if they exceed certain ARB-defined emission thresholds. During each year of the program, the ARB issues emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year. Emitters can obtain allowances from the ARB at quarterly auctions or from third parties or exchanges. Emitters may also satisfy a portion of their compliance obligation through the purchase of offset credits; e.g., credits for GHG reductions achieved by third parties (such as landowners, livestock owners, and farmers) that occur outside the industry sectors covered under the cap through ARB-qualified offset projects such as reforestation or biomass projects. During fiscal 2016, the Company determined that it had exceeded its allowed emissions threshold and became subject to compliance obligations whereby it must purchase allowances or offset credits. As of March 31, 2016, the Company had $0.8 million of accrued emission allowances and offset credits, and the Company was exposed to risks associated with changes in the price of credits for GHG reductions.

Niska Partners is exposed to counterparty credit risk on its trade and accrued accounts receivable and risk management assets. Counterparty credit risk is the risk of financial loss to the Company if a customer fails to perform its contractual obligations. Niska Partners engages in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. Credit risk associated with trade and accrued receivables is mitigated by the high percentage of investment grade customers, collateral support of receivables and Niska Partners' ability to take ownership of customer owned natural gas stored in its facilities in the event of non-payment. For the years ended March 31, 2016 and 2015, no expense related to doubtful accounts was recognized as a result of receivables deemed to be uncollectible. It is management's opinion that no allowance for doubtful accounts was required as of March 31, 2016 and March 31, 2015.

The Company analyzes the financial condition of counterparties prior to entering into an agreement. Credit limits are established and monitored on an ongoing basis. Management believes, based on its credit policies, that the Company's financial position, results of operations and cash flows will not be materially affected as a result of non-performance by any single counterparty. Credit risk is assessed prior to transacting with any counterparty and each counterparty is required to maintain an investment grade rating, provide a parental guarantee from an investment grade parent, or provide an alternative method of financial assurance (letter of credit, cash, etc.) to support proposed transactions. In addition, the Company's tariffs contain provisions that permit it to take title to a customer's inventory should the customer's account remain unpaid for an extended period of time. Although the Company relies on a few counterparties for a significant portion of its revenues, one counterparty making up 46%, 54% and 56% of gross revenues for the years ended March 31, 2016, 2015 and 2014, respectively, is a physical natural gas clearing and settlement facility that requires counterparties to post margin deposits equal to 125% of their net position, which reduces the risk of default.

Exchange traded futures and options comprise approximately 74.1% of Niska Partners' commodity risk management assets at March 31, 2016 (March 31, 2015—69.0%). These exchange traded contracts have minimal credit exposure as the exchanges guarantee that every contract will be margined on a daily basis. In the event of any default, Niska Partners' account on the exchange would be absorbed by other clearing members. Because every member posts an initial margin, the exchange can protect the exchange members if or when a clearing member defaults.

Included in the fair value of energy contracts at March 31, 2016 and 2015 are one to five year contracts to sell natural gas to customers in retail markets. Niska Partners has recorded a reduction in the fair value of these contracts of $1.6 million at March 31, 2016 (March 31, 2015—$1.7 million), representing an estimate of the expected credit exposure from these counterparties over their contractual lives.

The Company assesses interest rate risk by continually identifying and monitoring changes in interest rate exposures that may adversely impact expected future cash flows. At March 31, 2016, the Company was exposed to interest rate risk resulting from variable rates on the Revolving Credit Facilities. At March 31, 2016, $115.6 million in borrowings and letters of credit were outstanding under the Credit Agreement and Niska Partners had exposure to interest rate fluctuations.

Niska Partners had no interest rate swap or swaption agreements at March 31, 2016 and 2015.

Liquidity risk is the risk that Niska Partners will not be able to meet its financial obligations as they become due. The Company's approach to managing liquidity risk is to contract a substantial part of its facilities to generate constant cash flow and to ensure that it always has sufficient cash and credit facilities to meet its obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to its reputation. See Note 8 for details of the Company's debt.

Foreign currency risk is created by fluctuations in foreign exchange rates. As Niska Partners' Canadian subsidiaries conduct a portion of their activities in Canadian dollars, earnings and cash flows are subject to currency fluctuations. The performance of the Canadian dollar relative to the U.S. dollar could positively or negatively affect earnings. Niska Partners is exposed to cash flow risk to the extent that Canadian currency outflows do not match inflows. Niska Partners enters into currency swaps to mitigate the impact of changes in foreign exchange rates. The notional value of currency swaps as at March 31, 2016 was $38.3 million (March 31, 2015—$19.6 million). These contracts expire on various dates between April 2016 and February 2017. Niska Partners did not elect hedge accounting treatment and therefore changes in fair value are recorded directly into earnings under the optimization revenue caption of the statements of earnings (loss) and comprehensive income (loss).

The following table shows the fair values of the Company's risk management assets and liabilities:

Information about the Company's risk management assets and liabilities that had netting or rights of offset arrangements are as follows:

As at March 31, 2016	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet		Margin Deposits not Offset in the Balance Sheet			Net Amounts

Assets
Commodity derivatives	$	150,448	$	(94,211	)	$	56,237	$	(42,737	)	$	13,500
Currency derivatives		1,937		(544	)		1,393		—			1,393

Total assets		152,385		(94,755	)		57,630		(42,737	)		14,893

Liabilities
Commodity derivatives		140,740		(94,211	)		46,529		(42,620	)		3,909
Currency derivatives		2,076		(544	)		1,532		(940	)		592

Total liabilities		142,816		(94,755	)		48,061		(43,560	)		4,501

Net	$	9,569	$	—		$	9,569	$	823		$	10,392

As at March 31, 2015	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet		Margin Deposits not Offset in the Balance Sheet			Net Amounts

Assets
Commodity derivatives	$	148,385	$	(79,346	)	$	69,039	$	(50,070	)	$	18,969
Currency derivatives		5,167		(1,678	)		3,489		—			3,489

Total assets		153,552		(81,024	)		72,528		(50,070	)		22,458

Liabilities
Commodity derivatives		125,418		(79,346	)		46,072		(39,338	)		6,734
Currency derivatives		1,999		(1,678	)		321		(321	)		—

Total liabilities		127,417		(81,024	)		46,393		(39,659	)		6,734

Net	$	26,135	$	—		$	26,135	$	(10,411	)	$	15,724

The following amounts represent the Company's expected realization into earnings for derivative instruments, based upon the fair value of these derivatives as of March 31, 2016:

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

The carrying amount of cash and cash equivalents, margin deposits, trade receivables, accrued receivables, trade payables and accrued liabilities reported on the consolidated balance sheet approximate fair value.

Fair values have been determined as follows for the Company's assets and liabilities that were accounted for or disclosed at fair value on a recurring and non-recurring basis as of March 31, 2016 and 2015:

As at March 31, 2016	Level 1		Level 2		Level 3		Total

Assets
Commodity derivatives	$	—	$	56,237	$	—	$	56,237
Currency derivatives		—		1,393		—		1,393

Total assets	$	—	$	57,630	$	—	$	57,630



Liabilities
Commodity derivatives	$	—	$	46,529	$	—	$	46,529
Currency derivatives		—		1,532		—		1,532
Long-term debt		—		460,000		—		460,000

Total liabilities	$	—	$	508,061	$	—	$	508,061

As at March 31, 2015	Level 1		Level 2		Level 3		Total

Assets
Commodity derivatives	$	—	$	69,039	$	—	$	69,039
Currency derivatives		—		3,489		—		3,489
Goodwill		—		—		—		—

Total assets	$	—	$	72,528	$	—	$	72,528



Liabilities
Commodity derivatives	$	—	$	46,072	$	—	$	46,072
Currency derivatives		—		321		—		321
Long-term debt		—		432,688		—		432,688

Total liabilities	$	—	$	479,081	$	—	$	479,081

The Company's financial assets and liabilities recorded at fair value on a recurring basis have been categorized as Level 2. The determination of the fair value of assets and liabilities for Level 2 valuations is generally based on a market approach. The key inputs used in Niska Partners' valuation models include transaction-specific details such as notional volumes, contract prices, and contract terms as well as forward market prices and basis differentials for natural gas obtained from third-party service providers (typically the New York Mercantile Exchange, or NYMEX). There were no changes in Niska Partners' approach to determining fair value and there were no transfers out of Level 2 during the three-year period ended March 31, 2016.

The fair value of debt is the estimated amount the Company would have to pay to transfer its debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are supported by observable market transactions when available.

Non-financial assets and liabilities are re-measured at fair value on a non-recurring basis. During the year ended March 31, 2015, the Company wrote down goodwill to its estimated fair value of $nil, which is classified as a Level 3 measurement in the table above. There were no other non-financial assets or liabilities recorded at fair value as of March 31, 2016 and 2015.

The Managing Member units are held by the Manager which has a 1.80% Managing Member interest in Niska Partners. The operating agreement provides that the Managing Member interest entitles the Manager the right to receive distributions of Available Cash (as defined in the operating agreement) each quarter.

The Manager has sole responsibility for conducting the Company's business and for managing its operations. Pursuant to the operating agreement, the Manager has delegated the power to conduct Niska Partners' business and manage its operations to the Company's board of directors, of which all of the members are appointed by the Manager.

The Manager has agreed not to withdraw voluntarily prior to March 31, 2020 subject to certain conditions outlined in the operating agreement. Prior to that time, the Manager may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of the outstanding units, voting together as a single class, including units held by the Manager and its affiliates. Any removal of the Manager is also subject to the approval of a successor manager by the vote of the holders of a majority of the outstanding common units and notional subordinated units, voting as separate classes. The ownership of more than 33¹/3% of the outstanding units by the Manager and its affiliates gives them the ability to prevent the Manager's removal. At March 31, 2016, Holdco, which is an affiliate of the Manager, owned approximately 53.93% of the outstanding common and all of the notional subordinated units. At any time, the owners of the Manager may sell or transfer all or part of their ownership interests in the Manager to an affiliate or a third-party without the approval of the unitholders.

The common units are a class of non-managing membership interests in Niska Partners. The holders of the common units are entitled to participate in the Company's distributions and exercise the rights and privileges available to members under the Company's operating agreement. The operating agreement provides that the common unitholders have the right to receive distributions of Available Cash (as defined in the operating agreement) each quarter in an amount equal to $0.35 per common unit (the "Minimum Quarterly Distribution"), plus any arrearages in the payment of the Minimum Quarterly Distribution.

Within 45 days after the end of each quarter Niska Partners may make cash distributions to the members of record on the applicable record date. Niska Partners distributed $3.4 million and $39.7 million to the holders of common units and the Managing Member during the years ended March 31, 2016 and 2015, respectively. On January 28 and May 6, 2015, the Company's Board of Directors suspended the quarterly distribution to common unitholders for the third and fourth quarters of fiscal 2015, respectively, and under the Merger Agreement, the Company has committed to not make cash distributions until the earlier of the date of closing or termination of the Transaction.

The distribution in fiscal 2016 relates to withholding taxes paid to the Canadian tax authorities on behalf of the Company's unitholders. As of the beginning of fiscal 2016, one of the Company's Canadian subsidiaries owed interest to a non-Canadian subsidiary. During the year ended March 31, 2016, the Company filed a tax election that deemed this interest as paid, which triggered an obligation for the Company to pay withholding taxes. Consistent with similar transactions in the past, the Company has accounted for this payment as a distribution to unitholders.

Niska Partners filed a registration statement with the SEC to authorize the issuance of up to 7,500,000 common units in connection with a distribution reinvestment plan ("DRIP"). The DRIP provides unitholders of record and beneficial owners of common units a voluntary means by which unitholders can increase the number of common units owned by reinvesting the quarterly cash

distributions unitholders would otherwise receive in the purchase of additional common units. This registration statement became effective on July 31, 2013. Common units purchased under the DRIP will come from the Company's authorized but unissued common units or from common units purchased on the open market.

There were no cash distributions during the year ended March 31, 2016, and accordingly no shares were issued under the DRIP during the period. During the year ended March 31, 2015, Unitholders, substantially all of which were represented by the Carlyle/Riverstone Funds, elected to participate in the DRIP and were issued 2,243,664 common units (March 31, 2014—1,252,815 common units) in lieu of receiving cash distributions of $19.6 million (March 31, 2014—$18.3 million).

During the year ended March 31, 2015, 2,243,664 units were issued under the Company's DRIP bringing the total number of common units outstanding at March 31, 2015 to 37,988,724. During the year ended March 31, 2016, there were no changes to the number of common units outstanding.

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

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

IDRs are separate interest and represent participating securities. The IDRs entitle the Carlyle/Riverstone Funds to receive 48% of any quarterly cash distributions after Niska Partners' common unitholders have received the full minimum quarterly distribution ($0.35 per unit) for each quarter plus any arrearages from prior quarters (of which there are currently none). In addition, for a remaining period of two years, and provided that the Carlyle/Riverstone Funds continue to own a majority of both the Managing Member and the IDRs, the Carlyle/Riverstone Funds will be deemed to own 33.8 million "Notional Subordinated Units" in connection with votes to remove and replace the Managing Member. These Notional Subordinated Units are not entitled to distributions, but preserve the Carlyle/Riverstone Fund's voting rights with respect to the removal of the Managing Member. As of March 31, 2016, the Company has not made any payments with respect to the IDRs.

On May 7, 2014, Niska Holdings L.P. (the "Sponsor Partnership"), the parent of Holdco (which is the direct and indirect parent of the Company) awarded non-voting Class D Units in the Sponsor Partnership (the "Class D Units") to certain executives. The Class D Units are profits interest awards which have a service condition. As the Class D Units were issued to employees and a director, equity-classified compensation expense has been recorded in the Company's financial statements.

The Class D Units entitle the holders thereof to 15% of distributions made by the Sponsor Partnership to its Class A unitholders after its Class A unitholders receive distributions made by the Sponsor Partnership after May 17, 2014 in excess of the amount of any capital contributions made by the Class A unitholders after May 17, 2014 plus $331.0 million, each increased by 8% per annum compounded quarterly. The Sponsor Partnership will retain distributions (other than tax distributions) in respect of unvested Class D Units until such Class D Units vest. Of the awarded Class D Units, 20% vested on May 6, 2015. The remaining unvested units will vest at a rate of 5% on the last day of each fiscal quarter during the period commencing on June 30, 2015 and ending on March 31, 2019. The units have no expiry date provided the employee remains employed with the Sponsor Partnership, the Company or one or more of their respective subsidiaries. The fair value of the Class D Units is based on an enterprise value, with allocations of that value calculated under the terms of Niska Holdings L.P.'s operating agreement.

For the year ended March 31, 2016, there was no non-cash compensation expense related to the Class D Units (2015—$0.5 million, 2014—$nil).

The Company maintains compensatory unit-based performance plans (the "Plans") to provide long-term incentive compensation for certain employees and directors, and to align their economic interest with those of common unitholders. The Plans are administered by the Compensation Committee of the Board of Directors and permit the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, other unit-based awards, distribution equivalent rights and substitution awards. Unit-based awards are settled either in cash or in common units following the satisfaction of certain time and/or performance criteria.

The Company agreed not to grant additional unit awards under these plans based on the terms of the Merger Agreement.

Unit-based awards are classified as liabilities when expected to be settled in cash or when the Company has the option to settle in cash or equity. This accounting treatment has resulted from the Company's historical practice of choosing to settle this type of award in cash. When awards are classified as liabilities, the fair value of the units granted is determined on the date of grant and is re-measured at each reporting period until the settlement date. The fair value at each remeasurement date is equal to the settlement expected to be incurred based on the anticipated number of units vested adjusted for (i) the passage of time and (ii) the payout threshold associated with the performance targets which the Company expects to achieve compared to its established peers. The performance criterion is based on total unitholder return ("TUR") metrics compared to such metrics of a select group of the Company's peers. The TUR metrics reflect the Company's percentile ranking during the

applicable performance period compared to a peer group. The pro-rata number of units vested is calculated as the number of performance awards multiplied by the percentage of the requisite service period.

The following tables summarize the Company's unit-based awards outstanding and nonvested unit-based awards as of March 31, 2016:

As of March 31, 2016, outstanding unit-based awards classified as liability and equity amounted to 743,609 units and 321,265 units, respectively. Of the outstanding unit-based awards classified as liability, 95,347 units could be settled in cash or units.

Information on weighted average unit price at grant date and number of unit-based awards granted is as follows:

Unit-based compensation for the year ended March 31, 2016 was an expense of $2.9 million, a recovery of $1.6 million for the year ended March 31, 2015, and expense of $11.2 million for the year ended March 31, 2014. Amounts paid to employees for unit-based awards settled in cash for the years ended March 31, 2016, 2015 and 2014 were $0.3 million, $10.6 million and $2.3 million, respectively. In August 2015, 19,868 equity awards were settled using common units purchased from the open market for $0.1 million. No other equity awards were settled during the years ended March 31, 2016, 2015 and 2014.

As of March 31, 2016, there was $2.6 million (March 31, 2015—$5.1 million) of total unrecognized compensation cost related to nonvested unit-based awards granted that were subject to both time and performance conditions. That cost is expected to be recognized over the next two years.

In July 2015, the Company offered certain eligible employees retention award opportunities that will become vested on the earlier of the date of successful closing of the Transaction or the ninetieth day following the termination of the Transaction contemplated in the Merger Agreement. To participate in this plan, each participant was required to forfeit rights to any outstanding performance-based unit awards and agree that all settlements, if any, of the outstanding time-based unit awards will be settled in cash.

Eligible employees with 466,949 outstanding unit-based awards participated in this plan which resulted in modifications of their original awards. In addition, 28,478 equity awards that would have been forfeited upon the termination of a previous employee were modified to remain eligible to vest upon the closing of the Transaction. These modifications did not result in additional compensation costs for the Company.

Niska Partners uses the two-class method for allocating earnings per unit ("EPU"). The two-class method requires the determination of net income allocated to member interests as shown below.

	Year ended March 31,

	2016			2015			2014
*Numerator:*
Net earnings (loss)	$	(103,331	)	$	(350,656	)	$	(8,957	)
Less:
Managing Member's interest		1,861			6,352			171

Net earnings (loss) attributable to common unitholders	$	(101,470	)	$	(344,304	)	$	(8,786	)



*Denominator:*
Basic:
Weighted average units outstanding		37,988,724			36,882,713			34,941,036
Diluted:
Weighted average units outstanding		37,988,724			36,882,713			34,941,036
Earnings (loss) per unit
Basic	$	(2.67	)	$	(9.34	)	$	(0.25	)



Diluted	$	(2.67	)	$	(9.34	)	$	(0.25	)



*Weighted average number of equity-settled awards:*		442,525			451,001			—

The Company maintains a unit-based compensation plan that could dilute EPU in future periods. Because those awards were anti-dilutive for fiscal 2016 and 2015, the EPU calculations above exclude the weighted average number of equity-settled unit-based awards.

Long-term contract revenue for the year ended March 31, 2015 included a one-time contract termination payment of $26.0 million as a result of the termination by TransCanada Gas Storage Partnership ("TransCanada"), the Company's largest volumetric customer, of its previous storage service agreement.

The Company's inventory is valued at the lower of weighted-average cost or market. During each of the years in the three-year period ended March 31, 2016, the forward prices of natural gas fell below the carrying cost of the Company's inventories, and as such, inventories were written down.

Depreciation for the year ended March 31, 2016 includes $24.5 million (March 31, 2015—$64.7 million; March 31, 2014—$nil) related to migration of cushion at two of the Company's facilities. The Company records a provision for migration when it has been determined that cushion is no longer providing effective cushion support. Amortization of intangible assets for the year ended March 31, 2015 includes an amortization of $11.7 million related to the termination of the prior storage service agreement with TransCanada, to reflect the change in timing of cash flows related to this customer relationship.

The Company has a receivable of $4.8 million as of March 31, 2016 from Holdco (March 31, 2015—$6.1 million), as outlined in Note 20—Commitments and Contingencies.

In addition to the amount above, as of March 31, 2016 the Company had receivables from other related parties of $0.7 million ($nil as of March 31, 2015) which are included in accrued receivable in the balance sheet. These receivables relate to reimbursement of costs incurred by Niska Partners on behalf of a related party as well as management fees charged to affiliated entities for certain administrative services.

During the year ended March 31, 2016, Niska Partners recognized management fees and reimbursable costs amounting to $1.2 million (March 31, 2015—$nil; March 31, 2014—$0.2 million) as reductions to general and administrative expenses.

During the year ended March 31, 2015, the Carlyle/Riverstone Funds elected to participate in the DRIP and were issued 2,243,470 common units (March 31, 2014—1,252,810 common units) in lieu of receiving cash distributions of $19.6 million (March 31, 2014—$18.3 million).

In June 2015, the Company engaged the services of certain consultants for consideration of $5.8 million, the payment of which is contingent upon the successful closing of the Transaction.

As of March 31, 2016, the Company was under review by Canadian tax authorities for withholding taxes paid on behalf of Carlyle/Riverstone and the investors of the Carlyle/Riverstone Funds for earnings distributions made prior to the Company's IPO. The Company has received an updated notice from the Canadian tax authorities of a proposed assessment equivalent to $4.8 million (2015—$10.6 million) and the Company has recorded Management's best estimate of $4.8 million (2015—$6.1 million), as a liability to the Canadian tax authorities. Niska Holdings L.P., a company held by the Carlyle/Riverstone Funds and the parent of Holdco, guaranteed the repayment of any amounts owing with respect to this matter to the Company. Accordingly, as the Company believes collection of any amounts owing is reasonably assured, it has recorded a corresponding receivable of $4.8 million (2015—$6.1 million).

The Company and its subsidiaries are also subject to other legal and tax proceedings and actions arising in the normal course of business. While the outcome of these proceedings and actions cannot be predicted with certainty, it is the opinion of Management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.

Niska Partners entered into non-cancelable operating leases for office space, cushion gas, leases for land use rights at its operating facilities, storage capacity at other facilities, equipment, and vehicles used in its operations. The remaining lease terms expire between April 2016 and January 2059 and provide for the payment of taxes, insurance and maintenance by the lessee. A renewal option exists on

the office space lease to extend the term for another five years, exercisable prior to the termination of the original lease.

The minimum lease payments disclosed in the above table have not been reduced by the total of minimum rentals to be received in the future under non-cancelable subleases as of March 31, 2016 of $1.0 million. Consolidated lease and rental expense, net of sublease recoveries of $0.9 million, amounted to $10.5 million for the year ended March 31, 2016 (March 31, 2015—$13.6 million; March 31, 2014—$11.9 million). During the year ended March 31, 2016, lease and rental expense included contingent rent amounting to $ nil (March 31, 2015—$ nil; March 31, 2014—$0.4 million). Where applicable, contingent rent is due whenever a certain percentage of revenue exceeds minimum lease costs.

Purchase obligations arising as a result of forward purchase contracts in place at March 31, 2016 were as follows:

Purchase obligations consisted of forward physical and financial commitments related to future purchases of proprietary natural gas inventory and cushion gas. As the Company economically hedges substantially all of its natural gas purchases, there are forward sales that offset these commitments which are not included in the above table. As at March 31, 2016, forward physical and financial sales for all future periods related to proprietary gas totaled $1,001.8 million.

As at March 31, 2016, the Company had $9.6 million of issued and outstanding letters of credit to various counterparties to support natural gas purchase commitments.

	Year ended March 31,

	2016			2015			2014
Margin deposits	$	52		$	19,342		$	(14,137	)
Trade receivables		(256	)		3,114			(3,383	)
Accrued receivables		8,629			110,484			(44,459	)
Natural gas inventory		90,727			(124,955	)		3,676
Prepaid expenses and other current assets		(6,421	)		542			358
Other assets		67			(517	)		(807	)
Trade payables		(270	)		(212	)		(149	)
Accrued liabilities		4,609			(63,709	)		68,106
Deferred revenue		(6,212	)		596			5,468
Other long-term liabilities		(71	)		(520	)		360

Net changes in non-cash working capital	$	90,854		$	(55,835	)	$	15,033

	Year ended March 31,

	2016		2015		2014
Interest paid in cash	$	47,182	$	30,083	$	63,769
Interest paid in-kind		1,086		—		—
Taxes paid		1,958		50		73
Non-cash investing activities:
Non-cash changes in working capital related to property, plant and equipment	$	126	$	2,203	$	(2,426	)
Non-cash transfer of natural gas inventory to cushion		—		—		15,264
Non-cash financing activities:
Non-cash earnings distributions and reinvestments		—		19,631		18,270

Under the Company's Short-term Credit Facility, interest is payable in cash on a quarterly basis, unless the Company elects to pay such interest in-kind by capitalizing accrued interest into the principal amount. During the year ended March 31, 2016, the Company elected to pay $1.1 million of interest in-kind.

In March 2014, the Company reclassified the balance of its long-term natural gas inventory to cushion within property, plant and equipment to reflect operational requirements.

The Company's process for the identification of reportable segments involves examining the nature of services offered, the types of customer contracts entered into and the nature of the economic and regulatory environment.

Niska Partners operates along functional lines in its commercial, engineering, and operations teams for operations in Alberta, Northern California, and the U.S. Midcontinent. All functional lines and facilities offer the same services: fee-based revenue, and optimization. The Company has a marketing business which is an extension of the Company's proprietary optimization activities. Proprietary optimization activities occur when the Company purchases, stores and sells natural gas for its own account in order to utilize or optimize storage capacity that is not contracted or available to third party customers. All services are delivered using reservoir storage. The Company measures profitability consistently along all functional lines based on revenues and earnings before interest, taxes, depreciation and amortization, before unrealized risk management gains and losses. The Company has aggregated its operating segments into one reportable segment as at March 31, 2016 and 2015 and for each of the three years ended March 31, 2016.

Information pertaining to the Company's short term and long term contract services and net optimization revenues is presented on the consolidated statements of earnings (loss) and comprehensive income (loss). All facilities have the same types of customers: major companies in the energy industry, industrial, commercial, and local distribution companies, and municipal energy consumers. Revenues are primarily attributed to the geographic area based on where services are provided or the natural gas is sold.

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

	Year ended March 31,

	2016			2015			2014
Net realized revenues
U.S.	$	33,060		$	32,265		$	58,128
Canada		42,151			98,160			162,600
Net unrealized revenues
U.S.		(16,231	)		20,452			142
Canada		(335	)		11,242			(8,874	)
Write-downs of inventory
U.S.		(4,300	)		(22,600	)		(500	)
Canada		—			(41,200	)		(4,100	)
Inter-entity
U.S.		(156	)		(4,266	)		—
Canada		156			4,266			—

	$	54,345		$	98,319		$	207,396

Niska Partners' exposure to the volume of business transacted with a natural gas clearing and settlement facility is described in Note 13. While the clearing and settlement facility is its direct counterparty, its risk exposure to dependence on this counterparty is mitigated through the large number of members of the clearing and settlement facility who create the demand for these transactions.

During the three years ended March 31, 2016, Niska Partners did not have any other customers comprise greater than 10% of total gross revenue.

Quarterly results are influenced by the seasonal and other factors inherent in Niska Partners' business. The following table summarizes the quarterly financial data for the years ended March 31, 2016 and 2015:

	First Quarter (unaudited)			Second Quarter (unaudited)			Third Quarter (unaudited)			Fourth Quarter (unaudited)			Year ended March 31,

Fiscal 2016
Revenue, net	$	9,245		$	17,336		$	18,620		$	9,144		$	54,345
Earnings (loss) before income taxes		(33,468	)		(26,103	)		(25,696	)		(29,838	)		(115,105	)
Net earnings (loss) and comprehensive income (loss)		(37,407	)		(19,609	)		(20,992	)		(25,323	)		(103,331	)
Earnings (loss) per unit		(0.97	)		(0.51	)		(0.54	)		(0.65	)		(2.67	)
Fiscal 2015
Revenue, net	$	55,377		$	10,590		$	39,219		$	(6,867	)	$	98,319
Earnings (loss) before income taxes		(27,864	)		(36,180	)		(275,258	)		(43,010	)		(382,312	)
Net earnings (loss) and comprehensive income (loss)		(18,972	)		(28,832	)		(259,623	)		(43,229	)		(350,656	)
Earnings (loss) per unit		(0.52	)		(0.78	)		(6.85	)		(1.12	)		(9.34	)

Included in the amounts above are the following related to cushion gas migration and proprietary inventory write-downs:

Reflected in net revenue above includes a one-time contract termination payment of $26.0 million during the first quarter of fiscal 2015. Reflected in net earnings (loss) and comprehensive income (loss) above includes goodwill impairment of $245.6 million in the third quarter of fiscal 2015.

On June 9, 2016, the CPUC issued a decision which approved the transfer of control of the Wild Goose facility to Brookfield. The decision is effective immediately. The Company expects that the merger transaction will proceed in accordance with the terms of the Merger Agreement and that it will close on or prior to July 31, 2016.


ý		Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended March 31, 2016
OR
o		Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to


Delaware (State or other jurisdiction or organization)		27-1855740 (I.R.S. Employer Identification No.)
170 Radnor Chester Road, Suite 150 Radnor, PA (Address of principal executive offices)		19087 (Zip Code)

Title of Each Class		Name of Exchange on which Registered

Common Units Representing Limited Liability Company Interests		New York Stock Exchange


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



PART I
Item 1.	Business	1
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	36
Item 2.	Properties	36
Item 3.	Legal Proceedings	36
Item 4.	Mine Safety Disclosures	36
PART II
Item 5.	Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	37
Item 6.	Selected Financial Data	40
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A.	Quantitative and Qualitative Disclosures About Market Risks	67
Item 8.	Financial Statements and Supplementary Data	71
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	71
Item 9A.	Controls and Procedures	71
Item 9B.	Other Information	71
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	72
Item 11.	Executive Compensation	80
Item 12.	Security Ownership of Certain Beneficial Owners and Management	104
Item 13.	Certain Relationships and Related Transactions, and Director Independence	106
Item 14.	Principal Accounting Fees and Services	108
PART IV
Item 15.	Exhibits, Financial Statement Schedules	108
FINANCIAL STATEMENTS
Niska Gas Storage Partners LLC Index to Financial Statements		F-1

Three Months Ended	High		Low

March 31, 2016	$	3.75	$	3.01
December 31, 2015	$	3.47	$	2.66
September 30, 2015	$	3.72	$	3.02
June 30, 2015	$	3.99	$	1.21
March 31, 2015	$	4.62	$	1.44
December 31, 2014	$	12.91	$	2.71
September 30, 2014	$	16.10	$	12.27
June 30, 2014	$	16.43	$	12.26

Record Date	Payment Date	Per Common Unit

November 12, 2014	November 20, 2014	$	0.35
August 11, 2014	August 19, 2014	$	0.35
May 19, 2014	May 27, 2014	$	0.35

Name		Title

William H. Shea, Jr.		Chairman, President and Chief Executive Officer
Vance E. Powers		Chief Financial Officer
Mark D. Casaday		Chief Operating Officer
Rick J. Staples		Executive Vice President and Chief Commercial Officer
Robert B. Wallace		Vice President, Finance and Corporate Development
Bruce D. Davis, Jr.(1)		Vice President, Chief Administrative Officer (through July 31, 2015)

Name	2015 and 2016 Fiscal Year Base Salary

	(in U.S. dollars)
William H. Shea, Jr.	$	400,000
Vance E. Powers	$	298,700
Mark D. Casaday	$	320,000
Rick J. Staples(1)	$	247,815
Robert B. Wallace	$	257,680
Bruce D. Davis, Jr.(2)	$	257,680

TUR Ranking at End of Annual Performance Period	Performance Level

75th Percentile	Maximum	200	%
50th Percentile	Target	100	%
33rd Percentile	Threshold	50	%

Executive Position		Multiple of Base Salary

Chief Executive Officer		Five times (5x)
Other Executive Officers		Three times (3x)

Name		Value Realized on Vesting ($)(2)

William H. Shea, Jr.	—		—
Vance E. Powers	35,827	$	93,758
Mark D. Casaday	—		—
Rick J. Staples	57,788	$	155,168
Robert B. Wallace	—		—
Bruce D. Davis, Jr.	19,868	$	66,756

Name	Termination of Employment Due to Death, Disability, Retirement, or our Termination of the Executive without Cause ($)(1)		Termination of Employment without Cause, or due to a Constructive Dismissal, in Connection with a Change in Control ($)(2)

William H. Shea, Jr.	$	235,217	$	496,174
Vance E. Powers	$	87,366	$	184,293
Mark D. Casaday	$	93,426	$	197,077
Rick J. Staples	$	93,143	$	196,481
Robert B. Wallace	$	82,279	$	173,662



Mr. Shea	800,000	60,827	860,827
Mr. Powers	597,400	55,798	653,198
Mr. Casaday	640,000	66,797	706,797
Mr. Wallace	515,360	3,698	519,058

Name

Michael J. Hennigan	127,589	50,861	178,450
James G. Jackson	123,500	50,861	174,361
Stephen C. Muther	126,500	50,861	177,361

Plan Category

Equity compensation plans approved by unitholders:
2010 Long-Term Incentive Plan	0	(1)	N/A	2,716,153
Equity compensation plans not approved by unitholders:
N/A	—		—	—

	Year Ended March 31,

	2016		2015
Audit Fees	$	1,554,000	$	1,322,000
Audit—Related fees		—		150,000

Total	$	1,554,000	$	1,472,000

Exhibit Number					Description

	101.DEF	*	—		XBRL Taxonomy Extension Definition Linkbase Document.


	NISKA GAS STORAGE PARTNERS LLC
	By:	/s/ WILLIAM H. SHEA, JR. William H. Shea, Jr. Chairman, President and Chief Executive Officer and Director
Date: June 10, 2016

Signature	Title	Date


/s/ WILLIAM H. SHEA, JR. William H. Shea, Jr.	Chairman, President and Chief Executive Officer and Director (Principal Executive Officer)	June 10, 2016
/s/ VANCE E. POWERS Vance E. Powers	Chief Financial Officer (Principal Financial and Accounting Officer)	June 10, 2016
/s/ RALPH ALEXANDER Ralph Alexander	Director	June 10, 2016
/s/ MICHAEL J. HENNIGAN Michael J. Hennigan	Director	June 10, 2016
/s/ JAMES G. JACKSON James G. Jackson	Director	June 10, 2016
/s/ E. BARTOW JONES E. Bartow Jones	Director	June 10, 2016
/s/ STEPHEN C. MUTHER Stephen C. Muther	Director	June 10, 2016

Signature	Title	Date


/s/ ANDREW W. WARD Andrew W. Ward	Director	June 10, 2016
/s/ OLIVIA C. WASSENAAR Olivia C. Wassenaar	Director	June 10, 2016


NISKA GAS STORAGE PARTNERS LLC FINANCIAL STATEMENTS
Management's Report On Internal Control Over Financial Reporting			F-2
Report of Independent Registered Public Accounting Firm On Internal Control Over Financial Reporting			F-3
Report of Independent Registered Public Accounting Firm for the Years Ended March 31, 2016, 2015 and 2014			F-4
Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss) for the Years Ended March 31, 2016, 2015 and 2014			F-5
Consolidated Balance Sheets as of March 31, 2016 and 2015			F-6
Consolidated Statements of Cash Flows for the Years Ended March 31, 2016, 2015 and 2014			F-7
Consolidated Statements of Changes in Members' Equity for the Years Ended March 31, 2016, 2015 and 2014			F-8
Notes to Consolidated Financial Statements			F-9


/s/ WILLIAM H. SHEA, JR. William H. Shea, Jr. President and Chief Executive Officer and Director		/s/ VANCE E. POWERS Vance E. Powers Chief Financial Officer


Pipelines and measurement		5%
Wells		5%
Facilities (excluding costs of major overhauls)		Between 5% and 22%
Computer hardware and software		30%
Office furniture and fixtures		20%
Other		10%

	As at March 31,

	2016		2015
Prepaid losses on early settlement of economic hedges	$	6,631	$	—
Current portion of deferred financing costs		2,577		—
Other prepaid expenses		3,579		3,788

	$	12,787	$	3,788

	As at March 31,

	2016			2015
Customer contracts and relationships, beginning of the year	$	165,080		$	165,080
Less accumulated amortization		(147,498	)		(141,521	)

Customer contracts and relationships, end of the year		17,582			23,559
Pipeline rights of way		18,270			18,270

	$	35,852		$	41,829

For the fiscal year ending:		Amortization Expense

March 31, 2017			7,513
March 31, 2018			3,558
March 31, 2019			3,341
March 31, 2020			3,138
March 31, 2021 and thereafter			32

	As at March 31,

	2016			2015
6.50% Senior Notes due 2019	$	575,000		$	575,000
Revolving credit facilities		106,000			193,500
Short-term credit facility		40,086			—

		721,086			768,500
Less: portion classified as current		(146,086	)		(193,500	)

	$	575,000		$	575,000

	As at March 31,

	2016		2015
Accrued interest	$	20,975	$	21,411
Accrued gas purchases		16,099		13,917
Employee-related accruals		4,029		2,369
Current income tax payable		3,622		2,936
Other accrued liabilities		6,793		7,053

	$	51,518	$	47,686

	As at March 31,

	2016			2015
Balance, beginning of the year	$	2,308		$	1,975
Additions		33			22
Accretion		274			500
Effect of foreign exchange translation		(34	)		(189	)

Balance, end of the year	$	2,581		$	2,308

	As at March 31,

	2016		2015
Balance at beginning of the year	$	1,530	$	1,735
Additions (reductions) based on tax positions taken in a prior year		554		(205	)

Balance at end of the year	$	2,084	$	1,530

	As at March 31,

	2016		2015
Forwards		0.9		1.5
Futures		24.4		46.0
Swaps		0.0		(0.3	)

		25.3		47.2

As at March 31, 2016	Energy Contracts			Currency Contracts			Total

Short-term risk management assets	$	36,067		$	1,393		$	37,460
Long-term risk management assets		20,170			—			20,170
Short-term risk management liabilities		(30,614	)		(1,532	)		(32,146	)
Long-term risk management liabilities		(15,915	)		—			(15,915	)

	$	9,708		$	(139	)	$	9,569

As at March 31, 2015	Energy Contracts			Currency Contracts			Total

Short-term risk management assets	$	39,392		$	2,208		$	41,600
Long-term risk management assets		29,647			1,281			30,928
Short-term risk management liabilities		(25,560	)		—			(25,560	)
Long-term risk management liabilities		(20,512	)		(321	)		(20,833	)

	$	22,967		$	3,168		$	26,135

Fiscal year ending March 31,	Energy Contracts		Currency Contracts			Total

2017	$	5,453	$	(139	)	$	5,314
2018 and beyond		4,255		—			4,255

	$	9,708	$	(139	)	$	9,569