|• 10-K • EX-12.1 • EXHIBIT 23.1 • EX-23.2 • EX-31.1 • EX-31.2 • EX-32.1 • EX-32.2 • EX-101.INS • EX-101.SCH • EX-101.CAL • EX-101.DEF • EX-101.LAB • EX-101.PRE|
Commission file number: 001-34733
Niska Gas Storage Partners LLC
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to section 12(g) of the Act:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes 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 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 Exchange Act). Yes o No ý
As of September 30, 2011, the aggregate market value of the registrant's common units held by non-affiliates was $203,700,000. This calculation of such market value should not be construed as an admission or conclusion by the registrant that any person is in fact an affiliate of the registrant.
As of June 8, 2012, the registrant had 34,492,245 common units and 33,804,745 subordinated units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
As used generally in the energy industry and in this report, the following terms have the meanings indicated below.
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 formed in 2006 to own and operate natural gas storage assets. We own or contract for approximately 221.5 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 77.3 Bcf of new storage capacity through low cost organic expansions, an increase of approximately 54%, bringing our total working gas capacity to 221.5 Bcf at the end of March 31, 2012. We are the largest independent owner and operator of natural gas storage assets in North America, based on our analysis of working gas capacity owned by other storage owners, adjusted according to each such owner's percentage ownership of its respective storage facilities.
Because the supply of natural gas remains relatively stable over the course of a year compared to the demand for natural gas, which fluctuates seasonally, natural gas storage facilities are needed to reallocate excess 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, with an average of 2.2 cycles.
Our common units are listed on the New York Stock Exchange, or the NYSE, under the symbol "NKA." You may find more information about us on our website at http://www.niskapartners.com. Our headquarters is located in Houston, TX, and our operations center is located in Calgary, Alberta, Canada.
The following diagram depicts our simplified organizational and ownership structure as at March 31, 2012:
Our Relationship with Holdco
Niska Sponsor Holdings Coöperatief U.A., or Holdco, owns our manager, approximately 49.3% of our outstanding common units, all of our subordinated units and all of our incentive distribution rights.
Over 95% of the equity in Holdco is owned by the by the Carlyle/Riverstone Global Energy and Power Fund III, L.P. and Carlyle/Riverstone Global Energy and Power Fund II, L.P. and affiliated entities (together, the "Carlyle/Riverstone Funds") with the balance owned by our current and former officers and employees. The Carlyle/Riverstone Funds are affiliated with Riverstone Holdings LLC, or Riverstone. Riverstone conducts buyout and growth capital investments in the midstream, exploration and production, oilfield service, 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 1.98% 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 nine members. Our manager appoints all members to our board, and three of our directors are
independent as defined under the independence standards established by the NYSE. For more information about our directors, see "ManagementDirectors and Executive Officers."
Third-Party Gas Storage Contracts
We store natural gas for a broad range of customers, including financial institutions, marketers, pipelines, power generators, utilities and producers of natural gas.
Long-Term Firm Storage Contracts
We provide multi-year, multi-cycle storage services to our customers under LTF contracts. The volume-weighted average life of our LTF contracts at March 31, 2012 was 2.1 years. Under our LTF contracts our customers are obligated to pay us monthly reservation fees in exchange for the right to inject, store and withdraw volumes of natural gas on days and for periods selected by them at injection or withdrawal rates up to maximums specified in the contract. The reservation fees are fixed charges owed to us regardless of the actual amount of storage capacity utilized by customers. When customers utilize the capacity that is reserved under these contracts we also collect variable fees based upon the actual volumes of natural gas injected or withdrawn. These variable fees are designed to allow us to recover our variable operating costs and make up a small percentage of the total fees we receive under our LTF contracts.
Under LTF contracts, the customer has the right, but not the obligation, to store 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 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 thus represent a steady and predictable baseline cash flow stream.
Short-Term Firm Storage Contracts
We also provide services for customers under STF contracts. STF contracts typically have terms of less than one year. Under an STF contract, a customer pays a fixed fee to inject a specified quantity of natural gas on a specified date or dates and to store that gas in our storage facilities until withdrawal on a specified future date or dates. An STF contract differs from an LTF contract in that the customer is obligated to inject and withdraw specified quantities of natural gas on specified dates rather than entitled to utilize injection and withdrawal capacity at its option. Because STF contracts set forth specified future injection and withdrawal dates, we can enter into offsetting transactions to lock in incremental fees as spot and future natural gas prices fluctuate prior to that activity date.
Under STF contracts the customer is obligated to perform the injection and withdrawal activities as specified in the contract, thus enabling us to enter into offsetting transactions to capture incremental opportunities as spot and future natural gas prices fluctuate prior to the specified withdrawal date. For example, if, after a customer enters into an STF contract to inject natural gas in July and to withdraw that gas in January, natural gas futures prices for January fall below February prices, we might enter
into an offsetting STF transaction for the same quantities, with the same or another customer, to inject in January and withdraw in February for a fee based on the January to February spread. The result in January would be that the second transaction offsets the first transaction resulting in no net flow obligation on our storage facility during January, and therefore, a fuel savings. By entering into offsetting transactions, we are able to capture additional opportunities as they are created throughout the year by the volatile natural gas futures prices.
Our portfolio of third-party customers consists of a mix of customer types, each of which tends to have a storage usage pattern that is different from those of other customers at the facility. This means that even though the withdrawal or injection capability of a facility may be fully contracted, it will generally not be fully utilized on any given day. We purchase, store and sell natural gas for our own account in order to utilize, or optimize, storage capacity and injection and withdrawal capacity that is: (1) not contracted to customers; (2) contracted to customers, but underutilized by them; or (3) available only on a short-term basis. We have a stringent risk policy that limits, among other things, our exposure to commodity price fluctuations by requiring us to promptly enter into a forward sale contract or other hedging transaction whenever we enter into a proprietary purchase contract. Therefore, inventory purchases are matched with forward sales or are otherwise economically hedged so that a margin is effectively locked in promptly after we enter into the purchase. As a result, there are no speculative positions beyond the minimal operational tolerances specified in our risk policy.
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 intraday opportunities. Unlike STF and LTF storage transactions, proprietary optimization requires us to fund the carrying cost of the inventory with our own working capital.
Risk management techniques, adapted to the unique aspects of 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.
Customers and Counterparties
Our gas storage customers include a broad mix of natural gas market participants, including financial institutions, producers, marketers, power generators, pipelines and municipalities. Approximately 90% of the counterparties under our natural gas storage contracts and proprietary storage optimization transactions either have an investment grade credit rating, provide us with another form of financial assurance, such as a letter of credit or other collateral, or are governmental entities. Our investment grade counterparties account for approximately 99% of our exposures as of March 31, 2012.
Although during certain reporting periods a large portion of our gross revenues can be attributed to one or two counterparties, these gross revenues reflect the full commodity value of natural gas sales under our optimization strategy and overstate the counterparties' contribution to our net margin (after cost of goods sold) that is more correlated with our net earnings and operating cash flow.
Our exposure to the volume of business transacted with a natural gas clearing and settlement facility is mitigated by the facility's requirement to post margin deposits to reduce the risk of default.
Our 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. Our facilities require low amounts of cushion gas, meaning that a relatively small amount of natural gas is required to remain inside our facilities in order to maintain a minimum facility pressure supporting the working gas. The size and flexibility of our facilities, together with the application of advanced skills in reservoir engineering, drilling, geology and geophysics, enable us to support individual high-cycle contracts in excess of the average physical cycling capabilities of our facilities. In addition to the facilities we own and operate, we also contract for 8.5 Bcf of natural gas storage capacity on a long-term basis from Natural Gas Pipeline Company of America LLC, or NGPL, on its pipeline system in the mid-continent at cost-of-service based rates that we believe are currently below market rates. The following table highlights certain important design information about our assets:
March 31, 2012:
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 important 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. Although WCSB production has leveled off in recent years, we have
seen stronger levels of natural gas production in 2012 compared to production in the prior 2 years. Further, we expect that Canadian natural gas production will be sustained in future years by new production from large new shale and tight gas plays in northeast British Columbia and western Alberta, a large remaining conventional natural gas resource base, and eventually Arctic gas from the Mackenzie Delta and Alaska.
AECO Hub is connected to the extensive Alberta System. Most of the 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 Hub Facilities
AECO Suffield and AECO Countess, the two facilities that make up the AECO Hub, are geographically separated, but the toll design of the Alberta System means that they are both commercially located at the same point. This enables us to operate the two facilities as one integrated commercial operation without customers incurring incremental transportation costs. Customers nominate injections or withdrawals at Suffield's interconnect with the Alberta System, and AECO Hub allocates the nominations between its Suffield and Countess facilities based on its reservoir management strategy.
Our rights to use the reservoirs at Suffield and Countess are held pursuant to a series of natural gas storage agreements, trust arrangements and similar instruments entered into with the holders of subsurface mineral interests of the land where the reservoirs are situated. Rights to access, occupy and use the lands for facilities including the well sites and pipelines are derived from access agreements, right-of-ways, easements, leases and other similar land use agreements with the surface owners of such land.
Suffield Storage Facility. AECO Suffield is located in southeastern Alberta. It is near the Alberta System's "eastern gate," the largest natural gas delivery point in Canada, where gas is delivered into TransCanada's mainline pipeline system (transporting 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 80.0 Bcf. The storage reservoirs are connected to a central processing and compression facility by a system of five pipelines. Compression is provided by natural gas powered engines that have a total of more than 36,000 horsepower.
All of the processing and compression facilities and substantially all of the well sites for the storage reservoirs are located on the Canadian Forces Base, Suffield military training range, or CFB Suffield. CFB Suffield is open prairie land, which provides relatively low costs for seismic surveys, drilling and pipelining. While the military restricts access to the well sites on a limited basis from time-to-time (i.e., during military exercises), AECO Suffield has not experienced any operational issues due to the location since its inception in 1988.
Countess Storage Facility. AECO Countess is located in south central Alberta, approximately 60 miles east of Calgary. Countess is connected to a large diameter pipe of the Alberta System. This modern 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 70.0 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 LTF transactions at AECO Hub are for a gas storage capacity of 1.0 Bcf or greater and average 3.0 Bcf. LTF contract terms have been chosen so that a manageable amount of contracts expire each year, avoiding exposure to a large contract turnover volume. Existing commitments represent approximately 60% of AECO Hub's capacity for the fiscal year ending March 31, 2013. The weighted average contract life of our LTF storage contracts at AECO Hub is 2.3 years but most of our current customers have consistently entered into new contracts when their existing contracts expire. The largest contract we have at AECO Hub is in the seventh year of an initial term of 10 years, with the potential to be extended in five year increments to a maximum term of 25 years under certain circumstances. Upon the expiration of the initial term and each subsequent five year extension, this contract is automatically extended for five additional years unless either party exercises its right to terminate the contract. Under the contract terms, the party exercising its early termination rights is subject to the payment of an early termination fee.
AECO Hub is subject to provincial regulatory jurisdiction. Operations are subject to the regulation of the Alberta Energy Resources Conservation Board, or the Alberta ERCB, which must also approve proposed expansions of storage capacity. AECO Hub is not subject to active market regulation. 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 the Alberta ERCB. 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, or HDMC storage facility. This HDMC capability is made possible by the rock quality of the Wild Goose reservoirs and the extensive use of horizontal well technology.
Wild Goose is strategically located in a highly-liquid hub market and is one of only four independent operating storage facilities in northern California. Wild Goose provides natural gas receipt and delivery services at Pacific Gas & Electric Company, or PG&E Citygate, a liquid trading point where natural gas supply from multiple upstream basins meets the volatile California end-use gas demands that create a dependence on natural gas storage. This location provides customers with the opportunity to take advantage of PG&E Citygate pricing, liquidity and arbitrage opportunities.
Wild Goose operates 17 natural gas storage wells that are completed in three depleted natural gas reservoirs with an effective working capacity of 50.0 Bcf and a gas generated compression of 20,800 horsepower. The Wild Goose reservoirs are located in high quality rock formations. In addition, the reservoirs have a strong water drive mechanism, which helps maintain reservoir pressure and well deliverability. Rights to use the reservoirs at Wild Goose for natural gas storage are held pursuant to a series of natural gas storage leases with the surface owners of the lands where the reservoirs are situated as well as mineral owner agreements and similar instruments entered into with the holders of subsurface mineral interests in such lands. Rights for the lands used for the pipelines are derived from right-of-ways, easements, leases, and other similar land-use agreements.
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 with over a dozen third-party customers for terms of one year or longer. Existing commitments represent approximately 74% of Wild Goose's capacity for the fiscal year ending March 31, 2013. The weighted average contract life of our LTF storage contracts at Wild Goose is 1.7 years, but many of our current customers have consistently entered into new contracts when their existing contracts expire.
Wild Goose is regulated as a state utility by the CPUC and is certified to serve the California intra-state market. Wild Goose has regulatory authority to negotiate market based rates for third-party storage contracts and buys and sells 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. Wild Goose has received the State of CaliforniaDepartment of Conservation Award for Outstanding Oilfield Lease and Facility Maintenance for six consecutive years.
Our Salt Plains storage facility is located 110 miles north of Oklahoma City, Oklahoma, in a region of growing demand for natural gas as a fuel for heating and power generation. Salt Plains provides intrastate services in Oklahoma through its connection to pipelines operated by ONEOK Gas Transportation Pipelines, L.L.C., or ONEOK, and intrastate and interstate services through its interconnect with pipelines operated by Southern Star Central Gas Pipeline, Inc., or Southern Star.
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 that are completed in a depleted natural gas storage reservoir characterized by high-quality rock. The wells are connected to a central plant facility by seven miles of pipeline. Rights to use the reservoir at Salt Plains for natural gas storage are held pursuant to a series of gas storage agreements with the mineral rights owners of the lands where the reservoir is situated. Rights for the lands used for the pipelines are derived under these gas storage agreements as well as from right-of-way grants from other land owners.
Existing commitments represent approximately 45% of Salt Plains' capacity for the 2013 fiscal year. The weighted average contract life of our LTF storage contracts at Salt Plains is 1.3 years, but most of our current customers have consistently entered into new contracts when their existing contracts expire.
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.
NGPL Contracted Capacity
Since 2001, our subsidiary has contracted for 8.5 Bcf of gas storage capacity on the MidCon leg and the TexOk leg of the NGPL pipeline system in the mid-continent. The NGPL system connects and balances Gulf Coast and mid-continent supply basins with Chicago and other Midwestern U.S. end-use markets. NGPL has a number of different storage facilities on its pipeline system and manages its
storage capacity as pools on separate legs of the pipeline. Under NGPL's FERC-approved tariff, NGPL is limited to charging cost-of-service rates for its transportation and storage services. We currently have multiple LTF storage contracts with NGPL that expire on various dates through 2017. We have a tariff-based right of first refusal to renew these contracts at NGPL's favorable cost-of-service rate, effectively making this capacity a long-term asset without any invested capital, with an option to exit either temporarily or permanently, should the rate be above market value.
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 services.
Access Gas Services
We have a small but growing natural gas marketing business in Eastern Canada, British Columbia and Alberta serving commercial, industrial and retail customers. This is also a margin business where supply is locked in to serve customers at committed prices. In Eastern Canada, EnerStream Agency Services also provides fee-based agency services to natural gas end-users.
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, or CWA, the Clean Air Act, or CAA, the Safe Drinking Water Act, or SDWA and comparable legislation in Canada, limiting or preventing the release of materials from our facilities, managing wastes generated by our operations, the installation of pollution control equipment, responding to releases of process materials or wastes from our operations, and the risk of substantial liabilities for pollution resulting from our operations. The Occupational Safety and Health Act, or OSHA, comparable state statutes that regulate the protection of the health and safety of workers, as well as the Occupational Health and Safety Act in the Province of Alberta, and comparable federal legislation in Canada also apply to our operations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil, and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. We believe that we are in substantial compliance with existing environmental laws and regulations and that such laws and regulations will not have a material adverse effect on our business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. For example, on April 17, 2012, the EPA finalized rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOC's, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors and controllers of natural gas processing plants, dehydrators, storage tanks and other production equipment. These rules may require a number of modifications to our operations including the installation of new equipment to control emissions. As a result, there can be no assurance of the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.
Occupational Safety and Health Act
The workplaces in the U.S. associated with the storage facilities we operate are subject to the requirements of the Federal Occupational Safety and Health Act, or OSHA, as amended, as well as comparable state statutes that regulate the protection of the health and safety of workers. Workplaces in Canada associated with our operations are subject to the requirements of the Occupational Health and Safety Act in the Province of Alberta and comparable federal legislation. Failure to comply with OSHA requirements, or comparable requirements in Canada, including general industry standards, recordkeeping requirements and monitoring of occupational exposure to regulated substances, could subject us to fines or significant compliance costs.
There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases (GHGs). Future regulation of GHGs in the United States could occur pursuant to future U.S. treaty commitments, new domestic legislation that may impose a carbon emissions tax or establish a cap-and-trade program or regulation by the EPA. The Obama Administration has indicated its support for a mandatory cap and trade program to reduce GHG emissions, and it is possible federal legislation could be adopted in the future. Similarly, the outcomes of ongoing international negotiations since Durbin make it possible that a new, legally-binding international instrument to control GHGs will be adopted in the future.
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 though, 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). Although we would not be impacted to any
greater degree than other similarly situated natural gas storage companies, a stringent GHG control program could have an adverse effect on our cost of doing business and reduce demand for the natural gas storage services we provide.
In 2006, 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 is scheduled to take effect in 2012. However, various legal challenges threatens to delay California's cap-and-trade program. No final determination has been made with regard to the potential applicability of the AB 32 cap-and-trade program to our operations. We are therefore not in a position to quantify any potential costs associated with compliance under the program as proposed. However, any limitation a finalized program places on GHG emissions from our equipment and operations could require us to incur costs to reduce the GHG emissions associated with our operations.
Even in the absence of new federal legislation the U.S. Environmental Protection Agency, or EPA, has begun to regulate GHG emissions using its authority under the federal Clean Air Act (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 EPA has issued following exercising the authority affirmed by Massachusetts v. EPA include: (1) the December 2009 "endangerment finding" determining that air pollution from six GHGs endangers public health and welfare, and that mobile sources cause or contribute to that air pollution; (2) the May 2010 "Tailpipe Rule," issued jointly with the National Highway Traffic Safety Administration setting GHG emission and fuel economy standards for new light-duty vehicles; (3) the April 2010 "Timing Rule," concluding that stationary source regulation under Titles I and V of the CAA (involving Prevention of Significant Deterioration regulations and operating permits, respectively) must regulate GHG emissions beginning when such emissions are subject to controls under the mobile source provisions of the Act; (4) the June 2010 "Tailoring Rule," exempting small stationary sources from PSD and Title V requirements through regulations modifying the Act's emissions thresholds; and (5) the December 2010 "SIP Call" rule, finding 13 State Implementation Plans ("SIPs") inadequate because they did not regulate GHGs from stationary sources, and directing those States to correct the inadequacies or face federalization of their permitting programs. All of these regulations are subject to legal challenges but the D.C. Circuit has refused to stay the rules while the challenges are pending.
In addition to the above rules, on March 27, 2012 the EPA proposed GHG emissions standards for power plants. The EPA also plans to propose new GHG emission standards for refineries. The new standard for power plans along with the current EPA's GHG regulations could affect the demand for natural gas.
Pursuant to a Congressional mandate in the FY2008 Consolidated Appropriations Act, EPA has promulgated regulations requiring the measuring and reporting of GHG emissions from a variety of industrial sources. Finalized in October 2009, the Mandatory Reporting of Greenhouse Gas Emissions Rule (Mandatory Reporting Rule or MRR) sets out general provisions applicable to all entities with MRR compliance obligations, as well as a series of subparts covering particular industrial sectors. For most sectors, MRR obligations are triggered when the facility's emissions exceed 25,000 metric tons of carbon dioxide equivalent in a year, however, some facilities will be covered regardless of their emissions levels. Since the initial MRR was finalized, the EPA has gone on to finalize additional subparts, bringing new sectors within the scope of the rule. Finalized in June 2010, Subpart W of the MRR applies to owners and operators of petroleum and natural gas systems, which are defined to include onshore oil and natural gas production, offshore oil and natural gas production, onshore natural gas process, onshore natural gas transmission and compression, underground natural gas
storage, LNG storage, and LNG import and export activities be subject to the MRR's requirements if they emit more than 25,000 metric tons of carbon dioxide equivalent per year. Because our primary business involves underground natural gas storage, we are potentially subject to Subpart W of the MRR.
British Columbia has been in the process of implementing a cap-and-trade system consistent with the requirements of the WCI. The province has created a Climate Action Secretariat that is responsible for developing cap-and-trade rules. Ontario, another province participating in the WCI, has committed to a phase out of coal-fired power by 2014.
Alberta regulates GHG emissions under the Climate Change and Emissions Management Act, the Specified Gas Reporting Regulation (the "SGRR"), which imposes GHG emissions reporting requirements, and the Specified Gas Emitters Regulation (the "SGER"), which imposes GHG emissions limits. A facility subject to the SGRR must report if it has GHG emissions of 50,000 metric tonnes or more from a facility in any year. Under the SGER, GHG emission limits apply once a facility has direct GHG emissions in a year of 100,000 metric 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, 2012, we had 130 employees. Our executive officers are currently employed by 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 Buckeye Partners (Lodi), PG&E, NW Natural, 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. We anticipate that growing demand for natural gas storage in the markets we serve will be met with increasing storage capacity, either through the expansion of existing facilities or the construction of new storage facilities.
Our cash expenditures related to our optimization activities are highest during summer months, and our cash receipts from our optimization activities are highest during winter months. Consequently, our results of operations for the summer are generally lower than for the winter.
In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described below, which could materially adversely affect our business, financial condition and results of operations. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be adversely affected.
Risks Inherent in Our Business
We may not have sufficient cash following the establishment of cash reserves and payment of fees and expenses to enable us to make cash distributions to holders of our common units at the minimum quarterly distribution rate under our cash distribution policy.
We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.35 per unit, or $1.40 per unit per year, which will require cash of approximately $12.3 million per quarter, or $49.2 million per year, based on the number of common units currently outstanding. Under our cash distribution policy, the amount of cash we can distribute on our units principally depends upon the amount of cash generated from our operations, which will fluctuate based on, among other things:
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:
For a description of additional restrictions and factors that may affect our ability to pay cash distributions, see "Management's Discussion of Financial Condition and Results of OperationsLiquidity and Capital Resources."
In addition, we have not paid any distributions on our subordinated units with respect to the quarters ended on or after September 30, 2011. We may not have sufficient cash available for distributions on our subordinated units in the future. Any further reduction in the amount of cash available for distributions could impact our ability to pay the minimum quarterly distribution on our common units in full. Moreover, we may not be able to increase distributions on our common units if we are unable to pay the full minimum quarterly distribution on our subordinated units.
The amount of cash we have available for distribution to holders of our units depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net earnings.
The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses for financial accounting purposes and may not pay cash distributions during periods when we record net earnings.
Our level of exposure to the market value of natural gas storage services could adversely affect our revenues and cash available to make distributions.
As portions of our third-party 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:
As of March 31, 2012, approximately 27% of our LTF contracts and all of our STF contracts were due to expire on or before March 31, 2013. A prolonged downturn in the natural gas storage market due to the occurrence of any of the above factors could result in our inability to renegotiate or replace a number of our LTF contracts upon their expiration, leaving more capacity exposed to the value that could be generated through STF contracts or optimization. STF and optimization values would be impacted by the same factors, and market conditions could deteriorate further before the opportunity to extract value with those strategies could be realized.
Further, our lines of business and assets are concentrated solely in the natural gas storage industry. Thus, adverse developments, including any of the industry-specific factors listed above, would have a more severe impact on our business, financial condition, results of operations and ability to pay distributions than if we maintained a more diverse business.
We face significant competition that may cause us to lose market share, negatively affecting our business.
Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors. The natural gas storage business is highly competitive. The principal elements of competition among storage facilities are rates, terms of service, types of service, deliverability, supply and market access, flexibility and reliability of service. Our operations compete primarily with other storage facilities in the same markets in the storage of natural gas. The CPUC has adopted policies that favor the development of new storage projects and there are numerous projects, including expansions of existing facilities and greenfield construction projects, at various stages of development in the market where our Wild Goose facility operates. These projects, if developed and placed into service, may compete with our storage operations.
We also compete with certain pipelines, marketers and liquefied natural gas, or LNG, facilities that provide services that can substitute for certain of the storage services we offer. In addition, natural gas as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas storage services. Some of our competitors have greater financial resources and may now, or in the future, have greater access to expansion or development opportunities than we do.
If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to compete effectively. Some of these competitors may expand or construct new storage facilities that would create additional competition for us. The storage facility expansion and 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 storageways 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, results of operations and ability to pay distributions to our members.
Our operations are subject to operational hazards and unforeseen interruptions, which could have a material adverse effect on our business.
Our operations are subject to the many hazards inherent in the storage of natural gas, including, but not limited to:
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.
We are not fully insured against all risks incident to our business, and if an accident or event occurs that is not fully insured it could adversely affect our business.
We may not be able to obtain the levels or types of insurance we desire, and the insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not covered by insurance could have a material adverse effect on our business, financial condition, results of operations and ability to pay distributions to our members.
We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our financial results and cash available for distribution.
We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use the capacity could have a material adverse effect on our business, financial condition, results of operations and ability to pay distributions to our members.
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
We have $643.8 million principal amount outstanding of the 8.875% senior notes due 2018 of Niska US and Niska Canada. In addition, we have credit facilities that provide us up to $400 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 terminating distributions and reducing or delaying our business activities, acquisitions, investments or capital expenditures. In addition, we may take actions such as selling assets, restructuring or refinancing our debt or seeking additional equity capital although we may not be able to effect any of these actions on satisfactory terms, or at all. Our inability to obtain additional financing on terms favorable to us or our inability to service our debt could have a material adverse effect on our business, results of operations, financial condition and ability to pay distributions. See "Management's
Discussion and Analysis of Financial Condition and Results of OperationsLiquidity 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, the indenture governing our senior notes and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make distributions to our members. For example, our credit agreement and the indenture governing our senior notes restrict or limit our ability to:
Furthermore, our credit agreement contains covenants requiring us to maintain certain financial ratios and tests, including that we maintain a fixed charge coverage ratio of 1.1 to 1.0 at the end of each fiscal quarter when excess availability under both revolving credit facilities is less than 15% of the aggregate amount of availability under both credit facilities. Our ability to comply with those covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement or the indenture governing our senior notes, the lenders or the noteholders, as the case may be, will be able to accelerate the maturity of all borrowings and demand repayment of amounts outstanding, our lenders' commitment to make further loans to us may terminate, and we may be prohibited from making distributions to our members. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.
The indenture governing our senior notes prohibits us from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, 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 senior notes contains an additional general basket of $75 million not contained in our credit agreement.
See "Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesOur $400.0 Million Credit Agreement" and "Our 8.875% Senior Notes Due 2018." Any subsequent replacement of our credit agreement, our senior notes or any new indebtedness could have similar or greater restrictions.
We will be required to make capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to pay cash distributions may be diminished or our financial leverage could increase.
In order to increase our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations. To fund our expansion capital expenditures, we will be required to use cash from our operations or incur borrowings or sell additional common units or other membership interests. Such uses of cash from operations will reduce cash available for distribution to our members. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our members. In addition, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional membership interests may result in significant unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.
If we do not successfully complete expansion projects or make and integrate acquisitions that are accretive, our future growth may be limited.
A principal focus of our strategy is to 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 placed 15 Bcf of storage capacity at our Wild Goose facility in service during the year ended March 31, 2012. Some construction work is expected at Wild Goose to fully commission injection/withdrawal enhancements and improve pipeline connections with Pacific Gas and Electric in fiscal 2013. 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, results of operations and ability to pay distributions to our members may be materially adversely affected.
Exposure to currency exchange rate fluctuations will result in fluctuations in our cash flows and operating results.
Currency exchange rate fluctuations could have an adverse effect on our results of operations. Historically, a portion of our revenue has been generated in Canadian dollars, but we incur operating and administrative expenses in both U.S. dollars and Canadian dollars and financing expenses in U.S. dollars. If the Canadian dollar weakens significantly, we would be required to convert more Canadian dollars to U.S. dollars to satisfy our obligations, which would cause us to have less cash available for distribution.
A significant strengthening of the U.S. dollar could result in an increase in our financing expenses and could materially affect our financial results under U.S. GAAP. In addition, because we report our operating results in U.S. dollars, changes in the value of the U.S. dollar also result in fluctuations in our reported revenues and earnings. In addition, under U.S. GAAP, all foreign currency-denominated monetary assets and liabilities such as cash and cash equivalents, accounts receivable, restricted cash, accounts payable, long-term debt, capital lease obligations and asset retirement obligations are revalued and reported based on the prevailing exchange rate at the end of the reporting period. This revaluation may cause us to report significant non-monetary foreign currency exchange gains and losses in certain periods.
Our operations are subject to environmental and worker safety laws and regulations that may expose us to significant costs and liabilities.
Our natural gas storage activities are subject to stringent and complex federal, state, provincial and local environmental and worker safety laws and regulations. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. Moreover, new, stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our compliance costs or the cost of any remediation of environmental contamination that may become necessary, and these costs could be material. In addition, laws and regulations to reduce emissions of greenhouse gases could affect the production or consumption of natural gas and, adversely affect the demand for our storage services and the rates we are able to charge for those services. See "BusinessRegulation" for more information.
A change in the jurisdictional characterization of our assets by regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
AECO Hub in Alberta is not currently subject to rate regulation. The Alberta Energy Resources Conservation Board, or the ERCB, has jurisdiction to regulate the technical aspects of construction, development, and operation of storage facilities. If approved to do so by the Alberta Government, the AUC, may also set prices for 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 EPAct 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for certain violations of up to $1,000,000 per day for each violation. FERC also has the authority to order disgorgement of profits from transactions deemed to violate the Natural Gas Act and the EPAct 2005.
We hold title to our storage reservoirs under various types of leases and easements, and our rights thereunder generally continue only for so long as we pay rent or, in some cases, minimum royalties.
Our rights under storage easements and leases continue for so long as we conduct storage operations and pay our grantors for our use, or otherwise pay rent owing to the applicable lessor. If we were unable to operate our storage facilities for a prolonged period of time (generally one year) or did not pay the rent or minimum royalty, as applicable, to maintain such storage easements and leases in good standing, we might lose title to our 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, results of operations and ability to pay distributions to our members.
Our financial results are seasonal and generally lower in the second and third quarters of the calendar year, which may require us to borrow money in order to make distributions to our members during these quarters.
Our cash expenditures related to our optimization activities are highest during summer months, and our cash receipts from our optimization activities are highest during winter months. As a result, our results of operations for the summer are generally lower than for the winter. With lower cash flow during the second and third calendar quarters, we may be required to borrow money in order to pay distributions to our members. Any restrictions on our ability to borrow money could restrict our ability to pay the minimum quarterly distributions to our members.
Our risk management policies cannot eliminate all commodity price risk. In addition, any non-compliance with our risk management policies could result in significant financial losses.
While our hedging policies are designed to minimize commodity price risk, some degree of exposure to unforeseen fluctuations in market conditions remains. We have in place risk management systems that are intended to quantify and manage risks, including risks related to our hedging activities such as commodity price risk and basis risk. We monitor processes and procedures to prevent unauthorized trading and to maintain substantial balance between purchases and future sales and delivery obligations. However, these steps may not detect and prevent all violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. There is no assurance that our risk management procedures will prevent losses that would negatively affect our business, financial condition, results of operations and ability to pay distributions to our members. See "Management's Discussion and Analysis of Financial Condition and Results of OperationsRisk Management Policy and Practices."
New derivatives legislation could have an adverse impact on our ability to hedge risks associated with our business and on the cost of our hedging activities.
We use over-the-counter (OTC) derivatives products to hedge commodity risks and, to a lesser extent, our interest rate and currency risks. Recent legislation has been adopted to increase the regulatory oversight of the OTC derivatives markets and impose restrictions on certain derivative transactions, which could affect the use of derivatives in hedging transactions. Final regulations pursuant to this legislation defining which companies will be subject to the legislation have not yet been adopted. If future regulations subject us to additional capital or margin requirements or other restrictions on our trading and commodity positions, they could have an adverse effect on our ability to hedge risks associated with our business and on the cost of our hedging activities.
We may enter into commercial obligations that exceed the physical capabilities of our facilities.
We enter into LTF and STF contracts and proprietary optimization transactions based on our understanding of the injection, withdrawal and working gas storage capabilities of our facilities as well as the expected usage patterns of our customers. If our understanding of the capabilities of our facilities or our expectations of the usage by customers is inaccurate we may be obligated to customers to inject, withdraw or store natural gas in manners which our facilities are not physically able to satisfy. If we are unable to satisfy our obligations to our customers we may be liable for damages, the customers could have the right to terminate their contracts with us, and our reputation and customer relationships may be damaged.
Our operations could be affected by terrorist activities and catastrophic events that could result from terrorism.
In the event that our storage facilities are subject to terrorist activities, such activities could significantly impair our operations and result in a decrease in revenues and additional costs to repair and insure our assets. The effects of, or threat of, terrorist activities could result in a significant decline in the North American economy and the decreased availability and increased cost of insurance coverage. Any of these factors could have a material adverse effect on our business, financial condition, results of operations and ability to pay distributions to our members.
We depend on a limited number of customers for a significant portion of our revenues. The loss of any of these customers could result in a decline in our revenues and cash available to make distributions.
We rely on a limited number of customers for a significant portion of our revenues. The loss of all or a portion of the revenues attributable to our key customers as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations and ability to pay distributions to our members.
Risks Related to Our Structure
Holdco currently controls our manager, which has sole responsibility for conducting our business and managing our operations. Our manager has delegated this responsibility to our board, all of the members of which are appointed by our manager. Our manager and its affiliates, including Holdco, have conflicts of interest with us and limited 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:
absence of such definition. Our Operating Agreement also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under Delaware common law;
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, results of operations and ability to pay distributions to our members.
Holders of our common units have limited voting rights and are not entitled to elect our manager or our directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right to elect our manager or our board on an annual or other continuing basis. Our board, including our independent directors, is chosen entirely by our manager. Unlike publicly-traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. Furthermore, if the unitholders were dissatisfied with the performance of our manager, they have little ability to remove our manager.
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 and subordinated units voting together as a single class is required to remove our manager. Holdco owns 72.9% of our outstanding common and subordinated units. Accordingly, our public unitholders are currently unable to remove our manager without Holdco's consent because Holdco owns sufficient units to be able to prevent the manager's removal.
If our manager is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all subordinated units held by our manager and its affiliates will automatically be converted into common units. If no units held by any holder of subordinated units or its affiliates are voted in favor of that removal, all subordinated units will convert automatically into common units and any existing arrearages on the common units will be extinguished. A removal of our manager under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met the tests specified in our Operating Agreement. Cause is narrowly defined in our Operating Agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our manager liable for actual fraud or willful misconduct in its capacity as our manager. Cause does not include most cases of poor management of the business.
Our manager, or its interest in us, may be transferred to a third party without unitholder consent.
Our manager may transfer its managing member interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our Operating Agreement does not restrict the ability of the owners of our manager from transferring ownership of our manager to a third party. The new owners of our manager would then be in a position to revoke the delegation to our board of the authority to conduct our business and operations
or to replace our directors and officers with their own choices. This effectively permits a "change of control" of the company without unitholder vote or consent.
Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions or for other purposes.
An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other relatively more attractive investment opportunities may cause the trading price of our common units to decline. Therefore, changes in interest rates may affect our ability to issue additional equity to make acquisitions or for other purposes.
It is our policy to distribute a significant portion of our available cash to our members, which could limit our ability to grow and make acquisitions.
Pursuant to our cash distribution policy, we expect that we will distribute a significant portion of our available cash to our members and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy may impair our ability to grow.
In addition, because we intend to distribute a significant portion of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our members.
We may issue additional membership interests without unitholder approval, which would dilute a unitholder's existing ownership interests.
Our Operating Agreement does not limit the number of additional membership interests that we may issue at any time without the approval of our unitholders. Our issuance of additional common units or other membership interests of equal or senior rank may have the following effects:
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 49.3% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than for the conversion of the subordinated units into common units), our manager and its affiliates will own approximately 74.9% 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 34,492,245 common units and 33,804,745 subordinated units outstanding. 16,992,245 of the common units and all of the subordinated units are owned by Holdco. All of the subordinated units will convert into common units at the end of the subordination period. 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.
Tax Risks to Common Unitholders
Our tax treatment depends on our being treated as a partnership for U.S. federal income tax purposes and having no liability for U.S. federal income tax. If the U.S. Internal Revenue Service, or the IRS, were to treat us as a corporation for U.S. federal income tax purposes, then our cash available for distribution to unitholders could be substantially reduced.
The anticipated after tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for U.S. federal income tax purposes. However, it is possible in certain circumstances for a limited liability company such as us to be treated as a corporation for U.S. federal income tax purposes. Although we do not believe that we will be so treated based upon our current operations, a change in our business (or a change in current law) could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate. We may also be liable for state income taxes in addition to federal income taxes. Distributions to unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to them. Because corporate income taxes would be imposed upon us, our cash available for distribution to unitholders could be substantially reduced, likely causing a substantial reduction in the value of our common units.
Our Operating Agreement provides that the adverse impact of any such additional entity-level taxation will be borne by all members.
Notwithstanding our treatment for U.S. federal income tax purposes, we are subject to certain non-U.S. taxes. If a taxing authority were to successfully assert that we have more tax liability than we anticipate or legislation were enacted that increased the taxes to which we are subject, the cash available for distribution to unitholders could be further reduced.
Most of our business operations and subsidiaries are subject to income, withholding and other taxes in the non-U.S. jurisdictions in which they are organized or from which they receive income, reducing the amount of cash available for distribution. In computing our tax obligation in these non-U.S. jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing tax authorities, such as whether withholding taxes will be reduced by the application of certain tax treaties. Upon review of these positions the applicable authorities may not agree with our positions. A successful challenge by a tax authority could result in additional tax being imposed on us, reducing the cash available for distribution to unitholders. In addition, changes in our operations or ownership could result in higher than anticipated tax being imposed in jurisdictions in which we are organized or from which we receive income and further reduce the cash available for distribution. Although these taxes may be properly characterized as foreign income taxes, unitholders may not be able to credit them against their liability for U.S. federal income taxes on their share of our earnings.
Our Operating Agreement provides that the adverse impact of any such additional entity-level taxation will be borne directly or indirectly by all members.
If we were subjected to a material amount of additional entity-level taxation by individual states and localities, it would reduce our cash available for distribution to unitholders.
Changes in current state law may subject us to additional entity-level taxation by individual states and localities, reducing our cash available for distribution to unitholders. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise and other
forms of taxation. Our Operating Agreement provides that the adverse impact of any such additional entity-level taxation will be borne 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.
Our tax treatment as a publicly-traded partnership, as a company with multinational operations as well as the tax treatment of an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present tax treatment of publicly-traded partnerships, companies with multinational operations, or an investment in such entities as Niska Gas Storage Partners LLC is complex and may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the tax laws, treaties and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.
If a tax authority contests the positions we take, the market for our common units may be adversely impacted and the cost of any such contest will reduce our cash available for distribution to unitholders.
The tax authorities may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and a court may not agree with these positions. Any contest with a tax authority may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with a tax authority will be borne by our members because the costs will reduce our cash available for distribution.
Unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders are treated as partners for U.S. federal income tax purposes to whom we allocate taxable income, which could be different in amount than the cash we distribute, unitholders are required to pay any U.S. federal income taxes, Medicare taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If unitholders sell their common units, they will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because for U.S. federal income tax purposes distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them for U.S. federal income tax purposes if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our liabilities, unitholders may incur a tax liability on the sale of their units in excess of the amount of cash they receive.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by a tax-exempt entity, such as employee benefit plans and individual retirement accounts (known as IRAs), or a non-U.S. person raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, is unrelated business taxable income and will be taxable to them. In addition, we expect to withhold taxes from distributions to non-U.S. persons at the highest applicable effective tax rate, and non-U.S. persons are required to file U.S. federal tax returns and pay tax on their shares of our taxable income attributable to our U.S. operations. Tax exempt entities (or those who intend to hold our units through an IRA) and non-U.S. persons should consult a tax advisor before investing in our common units.
We treat each unitholder as having the same tax benefits without regard to the actual common units held. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of taxable income recognized by unitholders as a result of their ownership of our units. It also could affect the amount of gain from a unitholder's sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to that unitholder's tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly- traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although existing publicly-traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Moreover, our method of proration differs from the proposed Treasury
Regulations with respect to allocations of certain items of income and loss. Our counsel has not rendered an opinion regarding the validity of our proration method.
The amount of taxable income or loss allocable to each unitholder depends, in part, upon values that we periodically determine for our outstanding equity interests and our assets in order to comply with federal income tax law. The IRS may challenge our determinations of these values, which could adversely affect the value of our units.
U.S. federal income tax law requires us to periodically determine the value of our assets and to calculate the amount of taxable income or loss allocable to each partner based in part upon these values. We determine these asset values and allocations in part by reference to values that we determine for our outstanding equity interests. The IRS may challenge our valuations and related allocations. A successful IRS challenge to these valuations or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from a unitholder's sale of units and could have a negative impact on the value of units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.
A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, such unitholder would no longer be treated as the owner of those units for tax purposes during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as an owner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder in respect of those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder whose common units are loaned to a short seller. Unitholders desiring to assure their status as owners of units for tax purposes and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from loaning their units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our tax partnership for U.S. federal income tax purposes.
We will be considered to have terminated our tax partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year and may result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred.
Unitholders are likely subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.
In addition to U.S. federal income taxes, unitholders are likely subject to state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in California, Oklahoma and Texas. Each of California and Oklahoma currently imposes a personal income tax on individuals. Many states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is the unitholder's responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.
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 "BusinessOur 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.
Our Limited Liability Company Interests
As of June 8, 2012 we had outstanding 34,492,245 common units, 33,804,745 subordinated units, a 1.98% managing member interest and incentive distribution rights, or IDRs. The common units and subordinated units together represent all of our limited partner interests and 98.02% of our total ownership interests, in each case excluding our IDRs. As discussed below under "Our Cash Distribution PolicyIncentive Distribution Rights," the IDRs represent the right to receive increasing percentages, up to a maximum of 48%, of the cash we distribute from operating surplus (as defined
below) in excess of $0.4025 per unit per quarter. Holdco currently owns approximately 49.26% of our outstanding common units, all of our subordinated units and all of our IDRs.
Our common units, which represent limited liability company interests in us, are listed on the NYSE under the symbol "NKA." Our common units have been traded on the NYSE since May 12, 2010. Prior to that time, there was no public market for our stock. The following table sets forth for the indicated periods the high and low sales prices per unit for our common units on the NYSE:
On June 7, 2012, the closing market price for our common units was $12.06 per unit.
We have gathered tax information from our known unitholders and from brokers/nominees and, based on the information collected, we have approximately 31,600 beneficial unitholders at March 31, 2012.
Cash distributions paid to unitholders for the years ended March 31, 2012 and 2011 were as follows:
We generally make quarterly cash distributions of substantially all of our available cash, generally defined as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as our 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 have made quarterly distribution payments since August 2010.
We are subject to withholding taxes by the Canada Revenue Agency ("CRA") for the portion of our quarterly distributions that are derived from our Canadian operations. Unitholders receive foreign tax credits equal in amount to the amount that we pay to the CRA and can apply these credits against other Canadian sourced income, to the extent that they may have any.
As of June 8, 2012, there were 10 holders of record of our common units. The number of record holders does not include holders of units in "street names" or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.
Our Cash Distribution Policy
Our Operating Agreement contains a policy pursuant to which we pay regular quarterly cash distributions in an aggregate amount equal to substantially all of our available cash. Under the policy, each quarter our board makes a determination of the amount of cash available for distribution to members. Our board determines cash available for distribution to be an amount equal to all cash on hand at the end of the quarter, less reserves for the prudent conduct of our business (including reserves for capital expenditures, operating expenditures and debt service) or for distributions to members in respect of future quarters. Our board's determination of available cash takes into account the need to maintain certain cash reserves to preserve our distribution levels across seasonal and cyclical fluctuations in our business. Our board may determine to reserve or reinvest excess cash in order to permit gradual or consistent increases in quarterly distributions and may borrow to fund distributions in quarters when we generate less available cash than necessary to sustain or grow our cash distributions per unit.
These distributions reflect the board's basic judgment that typically our unitholders will be better served by our distributing our available cash, after expenses and reserves, rather than retaining it. Because we believe we will generally finance any expansion capital investments from external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, we believe that our investors are typically best served by our distributing all of our available cash. Because we are not subject to entity-level U.S. federal income tax, we will have more cash to distribute to unitholders than would be the case if we were subject to such tax.
Managing Member Interest
Our manager is entitled to 1.98% 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 1.98% 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 1.98% managing member interest.
Incentive Distribution Rights
Incentive distribution rights represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Holdco holds the incentive distribution rights but may transfer these rights, subject to restrictions in our Operating Agreement.
If for any quarter:
then additional distributions from operating surplus for that quarter will be made in the following manner:
In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.
To date, the Company has not made any payments with respect to the incentive distribution rights.
Limitations on Cash Distributions; Ability to Change Our Cash Distribution Policy
There is no guarantee that unitholders will receive quarterly cash distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including:
to run our business, including capital needs to maintain our storage facilities, to finance our proprietary optimization program and to fund the margin requirements of our hedging instruments.
Sales of Unregistered Securities
On August 24, 2011, we entered into a Common Unit Purchase Agreement with Holdco pursuant to which we issued and sold to Holdco, and Holdco purchased from us, 687,500 common units for a cash purchase price of $16.00 per common unit or $11,000,000 in the aggregate.
Equity Compensation Plan
As of March 31, 2012, we maintain one equity compensation plan that provides for potential issuances of equity securities of the registrant. See "Item 11. Executive CompensationCompensation Discussion and Analysis2010 Long-Term Incentive Plan" for information about our 2010 Long Term Incentive Plan, which became effective at the time of our IPO.
The following table shows selected historical consolidated financial and operating data of Niska Gas Storage Partners LLC for the fiscal years ended March 31, 2012 and 2011, and Niska Predecessor, consisting of the combined financial statements of Niska GS Holdings I, L.P. and Niska GS Holdings II, L.P. for the fiscal years ended March 31, 2010, 2009 and 2008.
The historical consolidated financial data presented for the years ended March 31, 2012 and 2011 and the combined financial data presented for the years ended March 31, 2010, 2009 and 2008 are derived from 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 and combined financial statements, respectively of Niska Gas Storage Partners LLC and Niska Predecessor and the accompanying notes included in Item 8.
Moreover, the table should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in Item 7.
The historical financial statements included elsewhere in this document reflect the consolidated assets, liabilities and operations of Niska Gas Storage Partners LLC ("Niska Partners" or "Niska") as at and for the years ended March 31, 2012 and 2011, and the combined assets, liabilities and earnings of Niska Predecessor as at and for the year ended March 31, 2010. The following discussion of the historical consolidated and combined financial condition and results of operations should be read in conjunction with the historical financial statements and accompanying notes of Niska and Niska Predecessor included elsewhere in this document. In addition, this discussion includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from statements we make. See "Forward-Looking Statements." Factors that could cause actual results to differ include those risks and uncertainties that are discussed in "Risk Factors."
We operate the Countess and Suffield gas storage facilities (collectively, the AECO HubTM) in Alberta, Canada, and the Wild Goose and Salt Plains gas storage facilities in California and Oklahoma, respectively. We market our working gas storage capacity and we optimize our storage capacity with our own proprietary gas purchases at each of these facilities. We earn revenues by (i) leasing storage on a long-term firm ("LTF") contract basis for which we receive monthly reservation fees for fixed amounts of storage, (ii) leasing storage on a short-term firm ("STF") contract basis, where customers
inject and withdraw specified amounts of gas and pay fees on specific dates, and (iii) engaging in optimization, where we purchase and sell gas on an economically hedged basis in order to improve facility utilization at margins higher than those that we receive from third party contracts. The Company has a total of 221.5 Bcf of working gas capacity among its facilities, including 8.5 Bcf leased from a third-party pipeline company.
During the fiscal year ended March 31, 2012, we experienced a substantial decline in realized revenues, particularly in our STF and optimization activities, from amounts realized in fiscal 2011. The revenue decline resulted from a significant reduction in natural gas price volatility and a significant narrowing of the difference between winter and summer prices in the natural gas futures market, sometimes referred to as the seasonal spread. These conditions resulted from a number of factors including, but not limited to, (i) warmer weather patterns across much of North America; (ii) an increase in the supply of non-conventional natural gas (including shale gas); (iii) real or perceived changes in overall supply and demand fundamentals; (iv) increased development in the number and size of natural gas storage facilities; and (v) the development of new pipeline infrastructure. We are not able to predict the long-term impacts of these factors on our revenues and profitability or the amount or timing of potential positive developments such as increased demand for natural gas resulting from coal-to-gas switching by utilities, increased industrial and consumer demand, or exports of Liquefied Natural Gas (LNG) from North America to other continents. However, in the fourth quarter of fiscal 2012, these conditions improved somewhat as the seasonal spread for calendar 2012 widened and modestly higher volatility returned to the natural gas futures market.
As we enter fiscal 2013, market conditions, including the seasonal spread and natural gas futures price volatility, remain uncertain. A relatively warm winter experienced in North America reduced demand for natural gas, which resulted in North American natural gas storage facilities, including the Company's facilities, beginning the year relatively full compared to the prior year.
A summary of financial and operating data for the years ended March 31, 2012, 2011 and 2010:
March 31, 2012, an unrealized risk management loss of $44.8 million for the year ended March 31, 2011 and an unrealized risk management loss of $24.7 million for the year ended March 31, 2010. We had write-downs of inventory of $23.4 million and $3.4 million for the years ended March 31, 2012 and 2010 respectively. Excluding these non-cash items, which do not affect Adjusted EBITDA, our realized optimization revenues were $62.8 million for the year ended March 31, 2012, $114.3 million for the year ended March 31, 2011 and $130.4 million for the year ended March 31, 2010.
The following table sets forth volume utilized by, and revenue and fees/margins derived from, LTF contracts, STF contracts and proprietary optimization transactions for the fiscal years ended March 31, 2012, 2011 and 2010:
Non-GAAP Financial Measure
We use the non-GAAP financial measure Adjusted EBITDA in this report. A reconciliation of Adjusted EBITDA to net earnings, its most directly comparable financial measure as calculated and presented in accordance with GAAP, is shown above.
We define Adjusted EBITDA as net earnings before interest, income taxes, depreciation and amortization, impairment of goodwill, unrealized risk management gains and losses, loss on extinguishment of debt, foreign exchange gains and losses, inventory impairment writedowns, gains and losses on asset dispositions, asset impairments and other income. Adjusted EBITDA is used as a
supplemental financial measure by our management and by external users of our financial statements such as commercial banks and ratings agencies, to assess:
The GAAP measure most directly comparable to Adjusted EBITDA is net earnings. The non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to net earnings. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Adjusted EBITDA should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net earnings and is defined differently by different companies, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
We recognize that the usefulness of Adjusted EBITDA as an evaluative tool may have certain limitations, including:
How We Evaluate Our Operations
We generate substantially all of our revenue through long and short-term contracts for the storage of natural gas for third-party customers and the proprietary optimization of storage capacity that is uncontracted, underutilized or available only on a short-term basis. We evaluate our business on the basis of the following key measures:
Volume and Fees Derived from LTF Contracts
We provide multi-year, multi-cycle storage services to our customers under LTF contracts. The volume weighted average life of our LTF contracts at March 31, 2012 was 2.1 years. Under our LTF contracts, our customers are obligated to pay us monthly reservation fees which are fixed charges owed to us regardless of the actual use by the customer. When a customer utilizes the capacity that is reserved under these contracts, we also collect a variable fee designed to allow us to recover our variable operating costs. Reservation fees comprise over 90% of the revenue generated under LTF contracts and provide a baseline of revenue in excess of our general and administrative and operating costs. We evaluate both the volume and price of our LTF contracting, which can indicate the effectiveness of our marketing efforts as well as the relative attractiveness of LTF contracts in comparison to our other revenue strategies. During periods when market values for storage capacity are higher, we typically will utilize more of our capacity under LTF contracts.
Volume and Fees Derived from STF Contracts
In addition, we provide short term services for customers under STF contracts. Under an STF contract, a customer pays a fixed fee to inject a specified quantity of natural gas on a specified date or dates and to store that gas in our storage facilities until withdrawal on a specified future date or dates. Because STF contracts set forth specified future injection or withdrawal dates, we enter into offsetting transactions to capture incremental value as spot and future natural gas prices fluctuate prior to that activity date. We monitor the volume used for and evaluate the fees generated under our STF contracts. The fees we are able to generate from our STF contracts reflect market conditions (including interest rates) and the effectiveness of our marketing efforts. The capacity utilized for STF contracts depends on, among other things, the total capacity of our storage facilities that is not being utilized for LTF contracts and the contract rates available for STF contracts.
Volume and Margin Derived from Our Proprietary Optimization Activities
When market conditions warrant, we enter into economically hedged transactions with available capacity to achieve margins higher than can be obtained from third-party contracts. Because we 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 deferred into a later period, causing the appearance of cyclicality in our reported revenues and profits.
When evaluating the performance of our optimization business, we focus on our realized optimization margins, excluding the impact of unrealized hedging gains and losses and inventory write-downs. For accounting purposes, our net realized optimization revenues include the impact of unrealized economic hedging gains and losses and inventory write-downs, which cause our reported
revenues to fluctuate from period to period. However, because substantially all inventory is economically hedged, any inventory write-downs are offset by hedging gains and any unrealized hedging losses are offset by gains when the inventory is sold.
Our most significant 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 smaller, fixed component of our operating expenses include salaries and labor, parts and supplies, surface and mineral lease rentals and other general operating costs. These fixed operating expenses are more stable from year to year but can fluctuate due to unforeseen repairs, equipment malfunctions and overhauls of compressors or engines.
General and Administrative Expenses
Our general and administrative expenses primarily consist of employee compensation, legal, accounting and tax fees and our office lease.
Capitalization, Leverage and Liquidity
We regularly monitor our credits metrics. As of March 31, 2012, we had a ratio of total debt to Adjusted EBITDA of 5.8 times, long-term debt to long-term debt plus equity of 48.3%, and a fixed charge coverage ratio of 1.94 to 1.0. During the fiscal year ended March 31, 2012, our credit metrics deteriorated from levels at March 31, 2011 as a result of a significant decline in revenues, net earnings and Adjusted EBITDA. For example, our ratio of total debt to Adjusted EBITDA increased from 4.1 to 5.8 times (4.1 times to 4.8 times when borrowings under our revolving credit facility are excluded), our ratio of long-term debt to long-term debt plus equity increased from 46.6% to 48.3% at March 31, 2012 compared to March 31, 2011, and our ratio of earnings to fixed charges decreased from 2.5 to 1.0 to 1.94 to 1.0 for the fiscal year ended March 31, 2012 compared to the fiscal year ended March 31, 2011. We have undertaken a number of steps to improve these credit metrics, the most important of which was the monetization of excess working capital, principally proprietary inventory, and the repurchase of a portion of our outstanding 8.875% Senior Notes (the "Senior Notes") with the proceeds of the inventory sales. During the fiscal year ended March 31, 2012, we repurchased a total of $156.2 million of our Senior Notes, which will reduce annual interest expense incurred related to the Senior Notes by approximately $13.9 million. We believe that the combination of working capital monetization and corresponding debt repurchases improves our credit metrics without significantly impacting our ability to pursue optimization revenue strategies.
Funding the purchase of proprietary optimization inventory can consume a significant portion of our available working capital. In times of higher natural gas prices, holding large inventories of proprietary gas may cause us to consume a substantial portion of our availability under our credit facilities. We therefore closely monitor the utilization and remaining available capacity under our credit facilities and actively pursue additional STF contracts when we determine it is appropriate to maintain liquidity.
Factors that Impact Our Business
Factors that impact the performance of specific components of our business from period to period include the following:
Market Price for LTF Contracts
The price available in the marketplace when negotiating new or replacement LTF contracts reflects demand and affects the amount of storage capacity utilized for LTF contracts that year, and thus the amount of capacity utilized for STF contracts or proprietary optimization for that year. We may increase the capacity that we use for LTF contracts at times of higher market prices and demand. Lower market prices for LTF contracts may result from lower seasonal spreads or a more competitive environment for storage services.
Gas Storage Capacity Growth
Capacity added in the prior year or added during a year is expected to generate incremental revenue.
When winter gas prices fall below forward prices for the following summer, we may defer the withdrawal of proprietary optimization inventory until the next fiscal year in order to add incremental margin and economic value. This results in the deferral of realized earnings and cash flow from one fiscal year to the next. In some cases, we can mitigate the impact of deferred earnings and cash flow by entering into STF contracts that straddle the two fiscal years.
The variable operating costs of our facilities (mostly comprised of costs associated with fuel or electricity for compressor operations) are affected by the amount and price of energy used to inject and withdraw 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 greater than expected costs in our first quarter and lower than expected costs in our second quarter. A mild winter could lead to less withdrawals in total, and therefore lower overall variable costs. These cost variances would be partially offset by similar variances in contract revenues.
Our cost of capital and the amount of our working capital availability impacts the amount of capacity utilized for proprietary optimization as compared to STF contracts. A higher cost of capital relative to that of our customers or less availability will generally lead to less volume used for proprietary optimization transactions. In general, higher carrying costs for us or our customers result in lower margins for us.
Customer Usage Patterns
Incremental revenue opportunities in the form of STF or proprietary optimization transactions may arise for us if capacity usage by our LTF customers is underutilized or offset by other LTF customers.
Weather extremes and variability directly affect our margins. Very mild years tend to reduce revenue generated under our STF and proprietary optimization strategies, while years with very hot
summers, very cold winters or a number of significant storms tend to increase the revenue generated under those strategies.
Supply Patterns for Natural Gas
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 believe that these factors tend to reduce the absolute price of natural gas along with the associated seasonal spread as well as dampen natural gas price volatility. We are unable to determine or predict the direct impact on our business from these developments.
Our process for the identification of reportable segments involves examining the nature of services offered, the types of customer contracts entered into and the nature of the economic and regulatory environment. Since our inception, we have operated along functional lines in our commercial, engineering and operations teams for operations in Alberta, northern California and the U.S. midcontinent. All functional lines and facilities offer the same services: firm storage contracts, short-term firm services and optimization. All services are delivered using reservoir storage. We measure profitability consistently along all functional lines based on revenues and earnings before interest, taxes, depreciation and amortization, before unrealized risk management gains and losses. We have aggregated our functional lines and facilities into one reportable segment as at and for the fiscal years ended March 31, 2012, 2011 and 2010.
Information pertaining to our LTF, STF and proprietary optimization revenues is presented in the consolidated and combined statements of earnings and comprehensive income. All facilities have the same types of customers: major companies in the energy industry, industrial, commercial, and local distribution companies and municipal energy consumers.
Results of Operations
Fiscal Year Ended March 31, 2012 Compared to Fiscal Year Ended March 31, 2011
As noted above, the fiscal year ended March 31, 2012 was characterized by an environment of low natural gas prices and reduced natural gas price volatility. These factors resulted in narrowed seasonal natural gas storage spreads and more limited revenue opportunities within our optimization and STF strategies. Our revenues and profitability were negatively impacted in fiscal 2012 by a combination of factors that resulted in reduced revenue margins compared to those experienced in prior periods. Notwithstanding these market conditions, we generated $136.2 million of adjusted EBITDA.
Revenue. Our revenue consisted of the following:
The change in revenue was primarily attributable to the following:
inventory is economically hedged financially, any risk management gains (or losses) are offset by future gains (or losses) associated with the sale of proprietary inventory.
Operating expenses of $44.0 million in fiscal 2012 were essentially flat with $44.8 million in operating expenses incurred in the prior year. Fuel and electricity costs were slightly higher ($0.2 million), as electricity price spikes at our Countess facility were offset by generally lower cycling of natural gas at all of our facilities as a result of reduced demand for natural gas. In addition, natural gas prices were lower at our facilities that use natural gas as compressor fuel.
These expenses decreased by $6.0 million (17%) in fiscal 2012 compared to fiscal 2011 principally due to reduced incentive compensation accruals as a result of lower earnings. Legal, audit and regulatory costs increased by $2.1 million as a result of higher professional fees in the current year.
statements, and recognized a loss of $2.8 million representing the difference between the selling price and the carrying value of the cushion gas. In addition, we wrote down certain pipe inventory at a development project by $2.5 million.
Fiscal Year Ended March 31, 2011 Compared to Fiscal Year Ended March 31, 2010
Revenue. The changes in revenue were primarily attributable to the following:
Earnings before Income Taxes. Earnings before income taxes for the fiscal year ended March 31, 2011 decreased by 77.4% to $27.4 million from $121.1 million for the fiscal year ended March 31, 2010. The decrease in earnings before income taxes was primarily attributable to the decreased revenue discussed above, plus the following:
of cushion gas effectiveness. Through continued monitoring over a series of withdrawal and injection cycles, management is able to better estimate the extent of effectiveness deterioration.
Net Earnings. Net earnings for the fiscal year ended March 31, 2011 increased by 8.1% to $57.5 million from $53.2 million for the fiscal year ended March 31, 2010. The change in net earnings was primarily attributable to lower pre-tax earnings, offset by the following:
Seasonality and Quarterly Fluctuations
Our business is highly seasonal. In general, revenue is highest during our third and fourth fiscal quarters (October through March), during the peak of the natural gas storage winter withdrawal season, when we typically sell most of our optimization inventory to serve the seasonal demand created by the North American residential market which uses natural gas to heat their homes. Revenue is 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. Revenue is substantially higher in the natural gas storage winter months (November through March), when natural gas prices are generally higher and we shift to the storage withdrawal season.
Because we purchase natural gas and build inventories in the summer months and hedge sales forward into the winter months, the peak borrowing on our revolving credit facilities are generally highest in the middle of our third fiscal quarter, while our peak accounts receivable collections typically occur in our fourth fiscal quarter.
The following table illustrates the differences in the recognition of revenue associated with our revenue strategies.
Liquidity and Capital Resources
As noted above, our revenues and profitability were negatively impacted in fiscal 2012 by a combination of factors that resulted in reduced revenue margins compared to those experienced in prior periods. We have responded with a number of actions designed to reduce debt and interest costs and to preserve our liquidity and financial flexibility under these conditions.
Our primary short-term liquidity needs are to pay interest and principal payments under our $400.0 million credit agreement and our Senior Notes, to fund our operating expenses and maintenance capital, to pay for the acquisition of proprietary optimization inventory along with associated margin requirements and to pay quarterly distributions, to the extent declared by our board of directors. We fund these expenditures through a combination of cash on hand, cash from operations and borrowings under our $400.0 million credit agreement. Because we intend to distribute substantially all of our available cash to our unitholders, our growth may not be as fast as the growth of businesses that reinvest their available cash to expand ongoing operations. Moreover, because of constraints in the capital markets or our inability to find and develop organic growth or acquisition opportunities, our future growth may be slower than our historical growth. We expect that we will, in large part, rely upon external financing sources, including bank borrowings and issuances of debt and equity interests, to fund our expansion capital expenditures and potential future acquisitions. To the extent we are unable to finance growth externally; our cash distribution policy could significantly impair our ability to grow. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may affect the available cash that we have to distribute on each unit. Our Operating Agreement does not limit our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional debt by us or our operating subsidiaries would result in increased interest expense, which in turn may also affect the available cash that we have to distribute to our unitholders.
Our principal debt covenant is our fixed charge coverage ratio ("FCCR"), which is included in both our $400.0 million credit agreement and the indenture on our Senior Notes. When our FCCR, which is calculated on a trailing-twelve months basis by dividing Adjusted EBITDA (defined substantially the same as presented herein) by fixed charges, which are measured as interest expense plus the amount of interest capitalized, but giving pro forma credit for the all of the previous twelve months for certain debt purchases and acquisitions, is less than 2.0 to 1.0, we are restricted in our ability to issue new debt. However, this restriction does not impact our ability to access our existing $400.0 million credit facility, or to amend, extend or replace that facility. When our FCCR is below 1.75 to 1.0, we are restricted in our ability to pay distributions. At March 31, 2012, our FCCR was 1.94 to 1.0. If our fixed charge coverage ratio were to be below 1.75 to 1.0, we would be permitted thereafter to pay $75 million of distributions. This $75 million amount is cumulative for all periods that our FCCR is below 1.75 to 1.0. The appropriateness and amount of distributions are determined by our board of directors on a quarterly basis.
Our medium-term and long-term liquidity needs primarily relate to potential debt repurchases, organic expansion opportunities and asset acquisitions. We expect to finance the cost of any expansion projects and acquisitions from borrowings under our existing and possible future credit facilities or a mix of borrowings and additional equity offerings as well as cash on hand and cash from operations. As of March 31, 2012, the Company does not anticipate any expansion projects or acquisitions that would require additional debt or equity financing.
During fiscal 2012, we purchased $156.2 million principal amount of our Senior Notes, reducing the outstanding balance to $643.8 million at March 31, 2012 from the $800.0 million outstanding at March 31, 2011. These purchases of Senior Notes were funded primarily by working capital. We sold approximately $121 million of proprietary inventory in the year ended March 31, 2012. In addition, in August 2011 the Carlyle/Riverstone funds invested $11 million of distributions that had been paid to them in new common units.
We believe that our existing sources of liquidity described above will be sufficient to fund our short-term liquidity needs through the year ending March 31, 2013. Funding of material acquisitions and longer-term liquidity needs will depend on the availability and cost of capital in the debt and equity markets, as well as compliance with our debt covenants. Accordingly, the availability of any such potential funding on economic terms is uncertain.
Historical Cash Flows
Our cash flows are significantly influenced by our level of natural gas inventory, margin deposits and related forward sale contracts or hedging positions at the end of each accounting period and may fluctuate significantly from period to period. In addition, our period-to-period cash flows are heavily influenced by the seasonality of our proprietary optimization activities. For example, we generally purchase significant quantities of natural gas during the summer months and sell natural gas during the winter months. The storage of natural gas for our own account can have a material impact on our cash flows from operating activities for the period we pay for and store the natural gas and the subsequent period in which we receive proceeds from the sale of natural gas. When we purchase and store natural gas for our own account, we use cash to pay for the 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, 2012, 2011, and 2010:
Operating Activities. The variability in net cash provided by operating activities is primarily due to (1) varying market conditions that exist during any given fiscal period, which impacts the margins and fees under each of our LTF, STF and optimization activities; and (2) market conditions at the end of any given fiscal period, which impacts our decision to sell significant volumes of inventory or hold them over a fiscal period end and sell them in the next fiscal period if there is the economic incentive to do so, such as to increase the margins from previous optimization transactions.
We exited the fiscal year ended March 31, 2011 with significant cash balances due to the completion in calendar 2010 of the issuance of $800.0 million of our Senior Notes and our IPO, both of which provided significant net cash injections in our business, along with carryover cash from fiscal 2010, which was highly profitable. During the year ended March 31, 2012, changing business conditions caused us to reevaluate the levels of capital required in the business. As a result, we liquidated a portion of working capital that was determined to be in excess of our needs. Proceeds from this liquidation, which principally represented reductions in proprietary inventory, were used to repurchase a portion of our Senior Notes. For a discussion of changes in cash flow resulting from adjustments to reconcile net earnings to net cash provided by operating activities, please refer to the discussion "Results of Operations."
Changes in non-cash working capital are broken down further as follows:
For the fiscal year ended March 31, 2012, the price of natural gas for the following summer was higher than the economically hedged price of our inventory. We thus chose to carry some of our inventory over the year end and re-hedged its sale to the following fiscal year. This improved our overall return because we were able to capture incremental economic value; however, the new hedges were transacted at prices lower than the cost of our inventory.
Working Capital. Working capital is defined as the amount by which current assets exceed current liabilities. Our working capital ratio is defined as current assets divided by current liabilities. Our working capital is affected by the relationship between unrealized financial risk management hedges which are marked-to-market on a monthly basis, the margin deposits required by our brokers for such gains and losses, proprietary inventory which is stored in our facilities and cash used to fund inventory purchases. Our working capital levels are also affected by our capital spending for maintenance and expansion activity.
As of March 31, 2012, we had net working capital of $135.7 million (working capital ratio of 1.4 to 1.0), representing a significant change compared to net working capital of $272.1 million (working capital ratio of 2.6 to 1.0) at March 31, 2011. The most significant reason for this reduction is the use of working capital to repurchase a portion of our Senior Notes described above.
Investing Activities. Most of the investing activities in each of the fiscal years ended March 31, 2012, 2011 and 2010 were attributed to expansion capital expenditures at our storage facilities. These expenditures, as outlined in "Capital Expenditures," have enabled us to increase our effective working gas capacity by 57.8 Bcf during the three year period. However, maintenance capital expenditures have been consistently modest, ranging between $0.9 million and $1.9 million each year during this same period.
Financing Activities. Net cash provided by/(used in) financing activities consists of debt incurred for the acquisition of assets, periodic optional and mandatory retirements of such debt, advances and repayments made on our previous credit facilities to fund proprietary inventory purchases, contributions of capital from our equity holders to fund expansion capital expenditures and debt retirements and distributions made to our equity holders.
During the fiscal year ended March 31, 2010 we drew $185.1 million from our previous credit facilities to fund proprietary inventory purchases and subsequently repaid $175.0 million when the inventory was sold later in the year. During the same fiscal year, we issued our Senior Notes, which provided net proceeds of approximately $775.4 million after deducting approximately $24.6 million of
fees and expenses. (See "Our 8.875% Senior Notes Due 2018.") Approximately $102.2 million of the net proceeds were used to make a distribution to our equity holders, approximately $75.0 million of the proceeds were used to repay our previous revolving credit facility and approximately $592.5 million of the proceeds were used to repay our previous term loan. In connection with our issuance of Senior Notes and the repayment of our previous credit facility and term loan, we entered into new senior secured asset-based revolving credit facilities, consisting of a U.S. revolving credit facility and a Canadian revolving credit facility (see "Our $400 Million Credit Agreement.")
In fiscal 2010, the holders of our predecessor's Class A units made contributions to the capital of our predecessor totaling $33.0 million in order to fund capital expenditures. During the fiscal year ended March 31, 2010, our predecessor made distributions totaling approximately $129.0 million to its equity holders (inclusive of the $102.2 million distribution made from the proceeds of the Senior Notes).
During the fiscal year ended March 31, 2011 we received proceeds of $333.5 million from our IPO in May of 2010, after deducting fees of $23.4 million. This was offset by distributions totaling $313.3 million made to the owners of Niska Predecessor in connection with our debt and equity offerings, and $64.7 million related to quarterly distributions made to our unitholders during the period.
During the fiscal year ended March 31, 2012 we drew $701.8 million from our credit facilities to fund proprietary inventory purchases and subsequently repaid $551.8 million when the inventory was sold. During the same fiscal year, we repurchased $156.2 million principal amount of our Senior Notes.
Our capital expenditures for the years ended March 31, 2012, 2011 and 2010 were as follows:
Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives. Expansion capital expenditures are made to acquire additional assets to grow our business, to expand and upgrade our facilities and to acquire similar operations or facilities. Cost reduction expenditures are those capital expenditures which increase the effectiveness and/or efficiency of our assets or which enable us to operate at a lower cost.
Under our current plan, we expect to continue to spend between approximately $1.0 million and $2.0 million per year for maintenance capital expenditures to maintain the integrity of our storage facilities and ensure the reliable injection, storage and withdrawal of natural gas for our customers. In
the fiscal year ended March 31, 2012, we spent a total of $52.8 million, excluding $2.9 million of capital expenditures which were accrued at March 31, 2012 to expand the capacity and services of our facilities. Expansions included the addition of 2 Bcf of capacity at our AECO TM facility and 15 Bcf of capacity at our Wild Goose facility. In addition, we acquired two development projects from Carlyle/Riverstone for $5 million. One project, Starks Gas Storage LLC, is a potential salt dome facility located in Louisiana; the other project, Sundance Gas Storage ULC is a joint venture with an energy producer for a potential depleted reservoir facility in Western Alberta. The development potential for each of these facilities is uncertain at this time.
Expansion and cost reduction expenditures for fiscal 2013 are expected to range from $10 million to $15 million and relate principally to enhancing withdrawal capacity and pipeline connections at Wild Goose.
Our 8.875% Senior Notes Due 2018
On March 5, 2010, Niska US and Niska Canada, issued 800,000 units, each unit consisting of $218.75 principal amount of 8.875% Senior Notes due 2018 of Niska US and $781.25 principal amount of 8.875% Senior Notes of Niska Canada.
In this section Niska US and Niska Canada are each referred to individually as an "issuer" and collectively as "the issuers."
The notes are senior unsecured obligations of each issuer, which are: (1) effectively junior to that issuer's secured obligations; (2) equal in right of payment with all existing and future senior unsecured indebtedness of each issuer; and (3) senior in right of payment to any future subordinated indebtedness of each issuer. The notes are fully and unconditionally guaranteed by us and our direct and indirect subsidiaries on a senior unsecured basis, and are: (1) effectively junior to each guarantor's secured obligations; (2) equal in right of payment with all existing and future senior unsecured indebtedness of each guarantor and (3) senior in right of payment to any future subordinated indebtedness of each guarantor.
Interest on our Senior Notes is payable on March 15 and September 15 of each year they are outstanding. The notes will mature on March 15, 2018. Under the indenture governing our Senior Notes, we are required to make principal payments prior to the maturity date except upon certain events of default. In addition, in the event of a change in control or certain asset sales, as those terms are defined in the indenture, we may be required to offer to redeem the notes from our holders.
The indenture governing our Senior Notes limits our ability to pay distributions in respect of, repurchase or pay dividends on our membership interests (or other capital stock) or make other restricted payments. The limitation changes depending on our fixed charge coverage ratio, which is defined as the ratio of our consolidated cash flow to our fixed charges, each as defined in the indenture governing our Senior Notes, and measured for the preceding four quarters.
If our fixed charge coverage ratio is not less than 1.75 to 1.0, we are permitted to make restricted payments if the aggregate restricted payments since the date of closing of our IPO, excluding certain types of permitted payments, are less than the sum of a number of items including, most importantly:
If the fixed charge coverage ratio is less than 1.75 to 1.0, we are permitted to make restricted payments if the aggregate restricted payments since the date of closing of our IPO, excluding certain types of permitted payments, are less than the sum of a number of items including, most importantly:
As of March 31, 2012, the fixed charge coverage ratio was 1.94 to 1.0 and the indenture governing our Senior Notes would have permitted us to distribute approximately $94 million.
The indenture does not prohibit certain types or amounts of restricted payments, including a general basket of $75.0 million of restricted payments.
The indenture governing our Senior Notes contains certain other covenants that, among other things, limit our and certain of our subsidiaries' ability to:
The occurrence of events involving us or certain of our subsidiaries may constitute an event of default under the indenture. Such events include failure to pay interest, principal, or the premium on the notes when due; failure to comply with the merger, asset sale or change of control covenants; certain defaults on other indebtedness; and certain insolvency proceedings. In the case of an event of default, the holders of the notes are entitled to remedies, including the acceleration of payment of the notes by request of the holders of at least 25% in aggregate principal amount of the notes, and any action by the trustee to collect payment of principal, interest or premium in arrears.
Prior to March 15, 2013, the issuers may redeem up to 35% of the aggregate principal amount of the notes at a premium, plus accrued and unpaid interest with net cash proceeds of certain equity offerings. Prior to March 15, 2014, the issuers may redeem some or all of the notes at a make-whole premium, as set forth in the offering memorandum. After March 15, 2014, the issuers may redeem some or all of the notes at a premium that decreases over time until maturity.
As noted above, during the fiscal year ended March 31, 2012, we repurchased on the open market $156.2 million principal amount of the Senior Notes.
Our $400 Million Credit Agreement
Concurrently with the issuance of our Senior Notes, Niska US and the AECO Partnership entered into new senior secured asset-based revolving credit facilities, consisting of a U.S. revolving credit facility and a Canadian revolving credit facility. References in this report to "our new credit facilities" or "our $400.0 million credit agreement" refer to the credit agreement and credit facilities, respectively, of the AECO Partnership and Niska US. These new revolving credit facilities provide for revolving loans and letters of credit in an aggregate principal amount of up to $200.0 million for each of the U.S. revolving credit facility and the Canadian revolving credit facility. Subject to certain conditions, each of
the revolving credit facilities may be expanded up to $100.0 million in additional commitments, and the commitments in each facility may be reallocated on terms and according to procedures to be determined. Loans under the U.S. revolving facility will be denominated in U.S. dollars and loans under the Canadian revolving facility may be denominated, at our option, in either U.S. or Canadian dollars. Royal Bank of Canada is the administrative agent and collateral agent for the revolving credit facilities. Each revolving credit facility matures on March 5, 2014.
Borrowings under our revolving credit facilities are limited to a borrowing base calculated as the sum of specified percentages of eligible cash equivalents, eligible accounts receivable, the net liquidating value of hedge positions in broker accounts, eligible inventory, issued but unused letters of credit, and certain fixed assets minus the amount of any reserves and other priority claims. Borrowings will bear interest at a floating rate, which (1) in the case of U.S. dollar loans can be either LIBOR plus an applicable margin or, at our option, a base rate plus an applicable margin, and (2) in the case of Canadian dollar loans can be either the bankers' acceptance rate plus an applicable margin or, at our option, a prime rate plus an applicable margin. The credit agreement provides that we may borrow only up to the lesser of the level of our then current borrowing base and our committed maximum borrowing capacity, which is currently $400.0 million. Our borrowing base was $406.5 million as of June 1, 2012.
Our obligations under our $400.0 million credit agreement are guaranteed by us and all of our direct and indirect wholly owned subsidiaries (subject to certain exceptions) and secured by a lien on substantially all of our and our direct and indirect subsidiaries' current and fixed assets (subject to certain exceptions). Certain fixed assets are required to be part of the collateral only to the extent such fixed assets are included in the borrowing base under the respective revolving credit facility. The aggregate borrowing base under both revolving credit facilities includes $150.0 million (the "PP&E Amount") due to a first-priority lien on fixed assets granted to the lenders. The PP&E Amount will be reduced on a dollar-for-dollar basis upon the release of fixed assets having a value in excess of $50.0 million from such liens.
The following fees are applicable under each revolving credit facility: (1) an unused line fee of 0.75% per annum, based on the unused portion of the respective revolving credit facility; (2) a letter of credit participation fee on the aggregate stated amount of each letter of credit equal to the applicable margin for LIBOR loans or bankers' acceptance loans, as applicable; and (3) certain other customary fees and expenses of the lenders and agents. We are required to make prepayments under our revolving credit facilities at any time when, and to the extent that, the aggregate amount of the outstanding loans and letters of credit under such revolving credit facility exceeds the lesser of the aggregate amount of commitments in respect of such revolving credit facility and the applicable borrowing base.
Our $400.0 million credit agreement contains customary covenants, including, but not limited to, restrictions on our and our subsidiaries' ability to merge and consolidate with other companies, incur indebtedness, grant liens or security interests on assets subject to security interests under the credit agreement, make acquisitions, loans, advances or investments, pay distributions, sell or otherwise transfer assets, optionally prepay or modify terms of any subordinated indebtedness or enter into transactions with affiliates. Our new revolving credit facilities require the maintenance of a fixed charge coverage ratio of 1.1 to 1.0 at the end of each fiscal quarter when excess availability under both revolving credit facilities is less than 15% of the aggregate amount of availability under both revolving credit facilities. Such fixed charge coverage ratio will be tested at the end of each quarter until such time as average excess availability exceeds 15% for thirty consecutive days.
Our $400.0 million credit agreement contains limitations on our ability to pay distributions in respect of, repurchase or pay dividends on our membership interests (or other capital stock) or make other restricted payments. These limitations are substantially similar to those contained in the indenture governing our Senior Notes described above, except that the credit agreement does not contain a general basket of $75.0 million of restricted payments. As of March 31, 2012, our $400.0 million credit agreement would have permitted us to distribute approximately $94 million.
Our $400.0 million credit agreement provides that, upon the occurrence of certain events of default, our obligations thereunder may be accelerated and the lending commitments terminated. Such events of default include payment defaults to the lenders, material inaccuracies of representations and warranties, covenant defaults, cross-defaults to other material indebtedness, including our Senior Notes, voluntary and involuntary bankruptcy proceedings, material money judgments, material events relating to pension plans, certain change of control events and other customary events of default.
As of June 1, 2012, we had borrowings of $134.0 million outstanding under our revolving credit facilities and had $21.3 million in letters of credit issued. We and our subsidiaries were in compliance with all covenant requirements under our credit facilities at June 1, 2012.
The following table summarizes by period the payments due for our estimated contractual obligations as of March 31, 2012:
Off-Balance Sheet Arrangements
In accordance with GAAP, there is no carrying value recorded for a credit facility until we borrow from the facility. In the future we may use off-balance sheet arrangements such as undrawn credit facility commitments, including letters of credit, to finance portions of our capital and operating needs. See "Contractual Obligations" for more information.
On January 1, 2010, Wild Goose entered into an operating lease for compression and other equipment related to the development of an expansion project. The primary term of the operating lease was extended until July 2019, although there is an early purchase option which Wild Goose can
exercise after three years. At the end of either term, Wild Goose can purchase the leased equipment from the operating lease counterparty at fair market value. The table above indicates all payments required under the primary term of the operating lease.
During the year ended March 31, 2012, we determined that the significant reduction in natural gas price volatility and the continued narrow seasonal spread were impairment indicators. We made this determination because these factors had a material negative effect on our current financial performance and our expected performance in future years. Accordingly, we performed an impairment test which resulted in a charge of $250 million related to the goodwill valuation of our AECO HubTM and NGPL reporting units.
We determined the fair value of the AECO HubTM 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 estimates of revenue, expenses and volumes, (ii) long-term natural gas volatility and seasonal spreads, (iii) long-term average exchange rate 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 determined above, (ii) recent transaction multiples based on anticipated cash flows and (iii) the similarity of comparable transactions to our facilities. Specifically, we used experience and budgeted amounts to estimate cycling volumes and expenses, future summer to winter spreads reflecting a longer term outlook, and extrinsic values consistent with those achieved in the business to estimate future revenue. These values used to estimate future revenues were lower than the seasonal storage spread and extrinsic values used in the test performed at March 31, 2011. We also used a comparable transaction multiple consistent with recent transactions for depleted reservoir storage facility acquisitions, which are comparable to our owned facilities.
Significant assumptions that we made in measuring the fair value of the assets and liabilities include (1) the replacement cost, depreciation and obsolescence and useful lives of property, plant and equipment and (2) the present value of incremental cash flows attributable to certain intangible assets.
Critical Accounting Estimates and Policies
The historical financial statements included elsewhere in this document have been prepared in accordance with GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management's judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the application of GAAP, including revenue recognition, the valuation of risk management assets and liabilities, inventory and goodwill. These estimates affect, among other items, valuing identified intangible assets, evaluating impairments of long-lived assets, depreciation of cushion gas, establishing estimated useful lives for long-lived assets, estimating revenues and expense accruals, assessing income tax expense and the requirement for a valuation allowance against the deferred income tax asset and valuing asset retirement obligations.
Our assessment of each of the four revenue recognition criteria as they relate to our revenue producing activities is as follows:
Persuasive evidence of an arrangement exists. Our customary practices are to enter into a written contract, executed by both the customer and us.
Delivery. Delivery is deemed to have occurred at the time the natural gas is delivered and title is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent that we retain our inventory, delivery occurs when the inventory is subsequently sold and title is transferred to the third party purchaser.
The fee is fixed or determinable. We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. The fees are generally due on the 25th of the month following the delivery or services rendered. For other arrangements, the amount of revenue is determinable when the sale of the applicable product has been completed upon delivery and transfer of title.
Collectability is reasonably assured. Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers' financial position (e.g. cash position and credit rating) and ability to pay. If collectability is not considered reasonably assured at the outset of an arrangement in accordance with our credit review process, revenue is recognized when the fee is collected.
Revenue from our LTF contracts consists of monthly storage fees and fuel and commodity charges for injections and withdrawals. LTF contract revenue is accrued on a monthly basis in accordance with the terms of the customer contracts. Customer charges for injections and withdrawals are recorded in the month of injection or withdrawal.
STF contract revenue consists of fees for injections and withdrawals, which include fuel and commodity charges. One half of the fees are earned at the time of injection by the customer and one-half of the fees are charged at the time of withdrawal by the customer.
Energy trading contracts resulting in the delivery of a commodity where we are the principal in the transaction are recorded as proprietary optimization revenues or purchases at the time of physical delivery. Realized and unrealized gains and losses on financial energy trading contracts are included in proprietary optimization revenue. See Note 14 to our consolidated financial statements included elsewhere in this document.
Fair Value of Risk Management Assets and Liabilities
Niska Partners uses natural gas derivatives and other financial instruments to manage its exposure to changes in natural gas prices, foreign exchange, and interest rates. These financial assets and liabilities, which are recorded at fair value on a recurring basis, are included into one of three categories based on a fair value hierarchy.
The fair value of our derivative and risk management contracts are recorded as a component of risk management assets and liabilities, which are classified as current or non-current assets or liabilities based upon the anticipated settlement date of the contracts. The determination of the fair value of these derivative and physical contracts reflects the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In the determination of fair value, we consider various factors, including closing foreign exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Although the fair value of our risk management assets and liabilities may fluctuate, such fluctuations will always be offset by equivalent changes in the value of our physical inventory and purchases. Our policy is for our inventory and purchases always to be economically hedged, within small tolerances permitted under our risk management policies, so we are not exposed economically to the risk of fluctuating commodity prices. We do not speculate on changes in the price of the commodity, rather we only lock in margins when they are available in the market. See "BusinessOur OperationsProprietary Optimization." For further analysis regarding our sensitivities to fluctuations in the price of natural gas, see
"Management's Discussion and Analysis of Financial Condition and Results of OperationQuantitative and Qualitative Disclosures about Market RisksCommodity Price Risks."
Our inventory is natural gas injected into storage and held for resale. Inventory is valued at the lower of average cost or market. 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 requires judgment which considers fair market values in the periods to which inventory is economically hedged and also considers the appropriateness and amount of a normal margin compared to selling price in those periods.
Long-term inventory represents non-cycling working gas. We injected non-cycling working gas to increase pressure within the reservoirs to allow us to market higher cycling contracts or previously un-saleable gas from an underutilized reservoir that can be sold into the market when we add mechanical compression to the reservoir. This mechanical compression allows us to access to natural gas that was previously required to maintain pressure within the reservoir. Long-term inventory is carried at cost and is subject to an annual test for impairment.
Cushion Gas Effectiveness
Certain volumes of natural gas defined as Cushion Gas are required for maintaining a minimum field pressure. Cushion Gas is considered a component of the facility and as such is not amortized because it is expected to ultimately be recovered and sold. Cushion Gas is monitored to ensure that it provides effective pressure support. In the event that natural gas moves to another area of the reservoir where it does not provide effective pressure support, charges against Cushion Gas are included in depreciation in an amount equal to the estimated volumes that have migrated.
Impairment of Long-Lived Assets
We evaluate whether events or circumstances have occurred that indicate that long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected undiscounted future cash flows. In the event that the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset's carrying value over its fair value is recorded.
Goodwill and Other Intangible Assets
We account for business acquisitions using the purchase method of accounting and accordingly the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of the net assets acquired is attributed to goodwill.
Goodwill is not amortized and is re-evaluated on an annual basis or more frequently if events or changes in circumstances indicate that the asset might be impaired.
Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the business climate, legal factors, operating performance indicators, competition, sale or disposition of a significant portion of the business or other factors. The performance of the test involves a two-step process. The first step of the
impairment test involves comparing the fair values of the applicable reporting units with their aggregate carrying values, including goodwill. If the carrying amount exceeds the fair value of the reporting unit, we perform the second step of the goodwill impairment test to determine the amount of impairment loss. The second step of the goodwill impairment test involves comparing the implied fair value of the affected reporting unit's goodwill with the carrying value of that goodwill.
Determining the fair value of a reporting unit is judgmental in nature and requires the use of significant estimates and assumptions. These assumptions are dependent on several subjective factors including the timing of future cash flows and future growth rates. The fair value of our reporting units is determined based on a weighting of multiples of potential earnings approaches which is classified under Level 3 fair value measurement under FASB ASC 820. The multiples of earnings approach estimates fair value by applying multiples of potential earnings, working gas capacity, and cyclability of similar entities. Results using the multiples of potential earnings and the multiples of gas capacity and cyclability are given equal weighting when determining the valuation using this approach. The future operating projections are based on consideration of past performance and the projections and assumptions used in our current operating plans and adjusted for market participant assumptions as appropriate. We then assign a weighting to the multiple or earnings to derive the fair value of the reporting unit.
These types of analyses contain uncertainties because they require management to make assumptions and apply judgment to estimate economic factors and the profitability of future business strategies and industry conditions. A reduction in volatility and the narrowing of seasonal natural gas storage spreads beginning in fiscal 2011 compressed short-term firm and realized optimization margins compared to those experienced in prior fiscal years. During fiscal 2012, we determined that the significant reduction in natural gas price volatility and the continued narrow seasonal spread were goodwill impairment indicators. We made this determination because these factors had a material negative effect on our current financial performance and our expected performance in future years. Accordingly, we performed a goodwill impairment test and as a result recorded a goodwill impairment charge of $250 million. If narrow seasonal spreads and low volatility continue to persist, these conditions could impact the Company's intermediate and long-term forecast of revenues and profitability and, therefore, future valuations of goodwill.
Intangible assets representing customer contracts are amortized over their useful lives. These assets are reviewed for impairment as impairment indicators arise. When such events or circumstances are present, the recoverability of long-lived assets is assessed by determining whether the carrying value will be recovered through the expected undiscounted future cash flows. In the event that the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset's carrying value over its fair value is recorded. Pipeline rights of way are formal agreements granting rights of way into perpetuity and are not subject to amortization but are subject to an annual impairment test.
We are not taxable entities. Income taxes on their income are the responsibility of the individual partners and have accordingly not been recorded in the consolidated financial statements. Niska Partners has corporate subsidiaries, which are taxable corporations subject to Canadian federal and provincial income taxes, which are included in the consolidated financial statements.
Income taxes on the Canadian corporate subsidiaries are provided based on the asset and liability method, which results in deferred income tax assets and liabilities arising from temporary differences. Temporary differences are differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. This method requires the effect of tax rate changes on current and accumulated deferred income taxes
to be reflected in the period in which the rate change was enacted. The asset and liability method also requires that deferred income tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized.
Recent Accounting Pronouncements
Please refer to Note 3 of the Notes to our Consolidated Financial Statements and "Recent Accounting Pronouncements".
The adoption of the standards which are now in effect did not have a material impact on our financial statements or related disclosures. We do not expect the adoption of new standards to have a material impact on our financial statements or related disclosures.
The term "market risks" refers to the risk of loss arising from changes in commodity prices, currency exchange rates, interest rates, counterparty credit and liquidity. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
Commodity Price Risk
To mitigate exposure to changes in commodity prices, we enter into purchases and sales of natural gas inventory and concurrently match the volumes in these transactions with offsetting forward contracts or other hedging transactions.
Derivative contracts used to manage market risk generally consist of the following:
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, 2012, 68.7 Bcf of natural gas inventory was economically hedged, representing 99.5% of our total current inventory. However, because inventory is recorded at the lower of cost or market, not fair value, if the price of natural gas increased by $1.00 per Mcf the value of that inventory would increase by $68.7 million, but the fair value or mark-to-market value of our hedges would decrease by $68.4 million, due to 0.5% (0.3 Bcf) of that inventory that was not economically hedged. Conversely, if
the price of natural gas declined by $1.00 per Mcf, the value of that inventory would decrease by $68.7 million while the fair value of our hedges would increase by only $68.3 million, due to the non-economically hedged position. Long-term inventory and fuel gas used for operating our facilities are not offset. Total volumes of long-term inventory and fuel gas at March 31, 2012 are 3.4 Bcf and 0.0 Bcf, respectively.
Although the intent of our risk-management strategy is to protect our margins and manage our liquidity risk on related margin deposit requirements, we do not qualify any of our derivatives for hedge accounting. Changes in the fair values of these derivatives receive mark-to-market treatment in current earnings and result in greater potential for earnings volatility. This accounting treatment is discussed further under Note 2 of the Notes to our Consolidated Financial Statements and "Critical Accounting Estimates and Policies."
Currency Exchange Risk
Our cash flow relating to our Canadian operations is reported in the U.S. dollar equivalent of such amounts measured in Canadian dollars. Monetary assets and liabilities of our Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period.
Because a portion of our Canadian business is conducted in Canadian dollars, we use certain financial instruments to minimize the risks of changes in the exchange rate. These instruments include forward swaps or spot swaps buying or selling U.S. dollars. Options may also be used in the future. All of the financial instruments utilized are placed with large brokers and financial institutions.
At March 31, 2012, we had forward currency exchange contracts for a notional value of $115.4 million. The value of the forward currency contracts at March 31, 2012 and 2011 was a liability of $0.3 million and $6.3 million respectively, and is recorded in derivative assets and derivative liabilities accounts on the consolidated balance sheets. These contracts expire on various dates between April 1, 2012 and August 1, 2014 and are for the exchange of $115.6 million Canadian dollars into $115.4 million U.S. dollars.
Interest Rate Risk
We are exposed to interest rate risk due to variable interest rates under our $400.0 million credit agreement. All such borrowings under our credit facilities bear interest at different rates. As of March 31, 2012, we had 150.0 million in borrowings outstanding under our revolving credit facilities. The credit facilities currently provide an interest rate on borrowings between 5.25% and 6.50%, 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.
Counterparty Credit Risk
Counterparty credit risk is the risk of financial loss if a customer fails to perform its contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. Credit risk associated with trade accounts receivable is mitigated by the high percentage of investment grade customers, collateral support of receivables and our ability to take ownership of customer-owned natural gas stored in its facilities in the event of non-payment.
Margin deposits, or letters of credit in lieu of deposits, are required on derivative instruments utilized to manage our counterparty credit risk. As commodity prices increase or decrease, the fair value of our derivative instruments changes thereby increasing or decreasing our margin deposit requirements. Rising commodity prices or an expectation of rising prices could increase the cash needed to manage our commodity price exposure and thereby increase our liquidity requirements, limit amounts available to us through borrowing and reduce the volume of natural gas we may purchase. Exchange traded futures and options have minimal credit exposure as the exchanges guarantee every contract will be margined on a daily basis. In the event of any default, our account on the exchange would be absorbed by other clearing members. Because every member posts an initial margin, the exchange can protect the exchange members if or when a clearing member defaults.
Liquidity risk is the risk that we will not be able to meet our financial obligations as they become due. Our approach to managing liquidity risk is to contract a substantial part of our facilities to generate constant cash flow and to ensure that they always have sufficient cash and credit facilities to meet their obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to reputation.
Fair Value Measurement
The fair values of the derivative instruments are based on quoted market prices obtained from NYMEX or ICE and from various sources such as independent reporting services, industry publications and brokers. These quotes are compared to the contract price of the instrument, which approximates the gain or loss that would have been realized if the contracts had been closed out at a specified time. We utilize observable market data when available, or models that utilize observable market data when determining fair value.
Risk Management Policy and Practices
We have in place risk management practices that are intended to quantify and manage risks facing our business. These risks include, but are not limited to, market, credit, foreign exchange, operational, and liquidity risks. Our hedging practices mitigate our exposure to commodity price and foreign exchange risks. Strict open position limits are enforced, and physical inventory is offset with forward hedges. Our counterparty strategy ensures we have a strong mix of quality customers. We have models in place to monitor and manage operational and liquidity risks.
The Risk Management Committee, or RMC, is comprised of members of our management team. The RMC provides oversight of our commercial activities. The committee reviews the adequacy of controls to ensure compliance with the risk policy. Our RMC meets weekly to review and respond to risks facing our business. The RMC 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 Commercial and Marketing groups and reports through our chief financial officer.
Optimization activities can only be executed by employees authorized to transact under the risk policy. All commercial personnel are annually required to read and certify that they will adhere to the principles purported within the policy. Each person authorized to make transactions is subject to internal volume limits. Counterparties are subject to credit limits as approved by our credit department.
Our commercial and risk functions operate independently to ensure proper segregation of duties. Critical deal information for every transaction is entered into our deal capture systems and confirmed with counterparties.
Despite the policies, procedures and controls described above, there can be no assurance that our risk management systems will prevent losses that would negatively affect our business, results of operations, cash flows and financial condition. See "Risk FactorsRisks Inherent in Our BusinessOur 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-45 of this Annual Report on Form 10-K and are incorporated herein by reference.
(a) Disclosure Controls and Procedures.
Our principal executive officer (CEO) and principal financial officer (CFO) undertook an evaluation of our disclosure controls and procedures as of the end of the period covered by this report. The CEO and CFO have concluded that our controls and procedures were effective as of March 31, 2012. For purposes of this section, the term "disclosure controls and procedures" means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
(b) Management's Report on Internal Control over Financial Reporting.
Management's report on internal control over financial reporting is set forth on page F-2 of this Annual Report on Form 10-K and is incorporated herein by reference.
(c) Attestation Report of the Registered Public Accounting Firm.
The attestation report of our registered public accounting firm with respect to internal controls over financial reporting on page F-3 of this Annual Report on Form 10-K and is incorporated herein by reference.
(d) Changes in Internal Control Over Financial Reporting.
During the quarter ended March 31, 2012, we implemented a new accounting system designed to improve the effectiveness and efficiency of our accounting and financial reporting processes. Although this implementation changed certain specific activities within the accounting function, it did not significantly affect the overall controls and procedures followed by the Company in establishing internal controls over financial reporting. Other than this accounting system implementation, 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.
Management of Niska Gas Storage Partners LLC
Our manager has sole responsibility for conducting our business and for managing our operations. Pursuant to our Operating Agreement, our manager has delegated the power to conduct our business and manage our operations to our board. Our manager may revoke this delegation and resume control of our business at any time. Our manager and our board are not elected by our unitholders and will not be subject to re-election on a regular basis in the future. As long as the delegation of authority is in effect, our manager will appoint all members to our board. Unitholders will not be entitled to elect our directors or directly or indirectly participate in our management or operation. Our Operating Agreement provides that our manager must act in "good faith" when making decisions on our behalf.
Whenever our manager makes a determination or takes or declines to take an action in its individual, rather than representative, capacity or in its sole discretion, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us or any member, and our manager is not required to act in good faith or pursuant to any other standard imposed by our Operating Agreement or under the Delaware Act or any other law. Examples include the exercise of its limited call rights, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation. Actions of our manager which are made in its individual capacity or in its sole discretion will be made by a majority of the owners of our manager.
In selecting and appointing directors to our board, our manager does not apply a formal diversity policy or set of guidelines. However, when appointing new directors, our manager considers each individual director's qualifications, skills, business experience and capacity to serve as a director, as described below for each director, and the diversity of these attributes for the board as a whole.
Directors and Executive Officers
Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal by the member of our manager. Our executive officers serve at the discretion of our board.
There are no family relationships among any of the directors or executive officers. The following table shows information as of June 8, 2012, regarding our current directors and executive officers.
Simon DupéréMr. Dupéré is our President and Chief Executive Officer and a member of our board. Mr. Dupéré previously served as the Interim President & Chief Executive Officer from July, 2011 until April 24, 2012. Mr. Dupéré has also served as our Chief Operating Officer from September 2006 until June 7, 2012. He continues to be in charge of our field and facility operations, engineering and geoscience, including our existing operations at our four natural gas storage facilities and our expansion and development efforts. He has 25 years of active experience in the natural gas industry. Prior to joining us, Mr. Dupéré was the President and Chief Executive Officer at Intragaz Inc., a natural gas storage company engaged in the development and operation of two gas storage projects in Quebec. Mr. Dupéré has a Bachelor of Science in Physics Engineering from Laval University in Quebec City, Quebec.
Vance E. PowersMr. 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.
Rick J. StaplesMr. Staples is our Executive Vice President, 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. Prior to joining us in 2006, Mr. Staples served as Director of Gas Storage with TransCanada Pipelines Ltd. from 2001 to 2006. Mr. Staples graduated from the University of Alberta with a degree in Mechanical Engineering. Mr. Staples also graduated from the Queens Executive program (Queens School of Business) in 1997.
Jason A. DubchakMr. 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.
Jason S. KulskyMr. Kulsky is our Vice President, Business Development, and has held that title since May 2006. Mr. Kulsky previously served with the natural gas storage division of EnCana Corporation and its predecessor, Alberta Energy Company Ltd., most recently serving as Manager, Business Development, prior to joining us. Mr. Kulsky is a Chartered Financial Analyst and has a Bachelor of Commerce (Finance) degree from the University of Calgary and an engineering diploma from SAIT Polytechnic.
Darin T. OlsonMr. Olson is our Vice President, Finance and has served in that role since January 1, 2011. Mr. Olson also served as our Chief Financial Officer from May 2006 to January 1, 2011. Prior to joining us, he was the Controller of Seminole Canada Gas Company from 2002 to 2006. For the ten prior years, Mr. Olson worked in a variety of positions in the natural gas and public accounting industries. Mr. Olson is a Chartered Accountant and has a Bachelor of Commerce degree from the University of Calgary.
Deborah M. FretzMs. Fretz is a member of our board and serves as the interim non-executive Chairman. She also serves on both the audit and compensation committees. Ms. Fretz served as President, Chief Executive Officer and director of Sunoco Logistics Partners L.P. ("Sunoco Logistics") from October 2001 to July 1, 2010. Sunoco Logistics is a publicly-traded master limited partnership formed in 2001 to acquire, own and operate a geographically diverse group of crude oil and refined products pipelines, terminals and storage facilities in eleven states. Revenues were $10 billion, with 1,400 employees and interests in 10,000 miles of pipelines and 31 million barrels of storage capacity. Prior to the IPO of Sunoco Logistics Partners, Ms. Fretz held several executive management roles for Sunoco, Inc., the last as Vice President Mid-Continent Refining, Marketing and Logistics which included Sunoco's Lubricant business as well as the MidAmerica refining and marketing business until April, 2012. In February, 2012, Ms. Fretz was elected to the board of Alpha Natural Resources (NYSE:ANR), a major U.S. coal supplier of both thermal and metallurgical coal worldwide and has served on the audit and compensation committees since May, 2012. From December 1993 to April, 2012, Ms. Fretz served as a board member of GATX Corp., a Chicago-based transportation services firm, where she was Chair of the compensation committee and was formerly Lead Director.
As a result of her service to Sunoco Logistics, Ms. Fretz gained extensive experience in overseeing the strategy, operations, and governance of major public companies. Ms. Fretz was also selected to serve as a director of our board due to her valuable knowledge of the energy industry. Ms. Fretz's experience has also given her knowledge of the unique issues related to operating publicly-traded
limited partnerships, which are similar to us. We believe this background and skill set makes Ms. Fretz well-suited to serve as a member of our board.
James G. JacksonMr. Jackson is a member of our board and serves on both the audit and compensation committees. Mr. Jackson has been the Chief Financial Officer of BreitBurn GP, LLC, the general partner of BreitBurn Energy Partners L.P. (NASDAQ:BBEP) since July 2006 and an Executive Vice President since October 2007. Before joining BreitBurn, Mr. Jackson served as a Managing Director of Merrill Lynch & Co.'s Global Markets and Investment Banking Group. Mr. Jackson joined Merrill Lynch in 1992 and was elected Managing Director in 2001. Previously, Mr. Jackson was a Financial Analyst with Morgan Stanley & Co. from 1986 to 1989 and was an Associate in the Mergers and Acquisitions Group of the Long-Term Credit Bank of Japan from 1989 to 1990. Mr. Jackson obtained a B.S. in Business Administration from Georgetown University and an M.B.A. from the Stanford Graduate School of Business.
Mr. Jackson's knowledge and experience with BreitBurn Energy Partners L.P. and BreitBurn GP, LLC, has provided him with valuable experience and familiarity with master limited partnerships and, more specifically, the natural gas business. These skills coupled with his broad investment banking, 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 JonesMr. Jones is a member of our board, the board of directors of our manager and the board of supervisors of Niska Holdings, which is our parent. Mr. Jones is currently a Managing Director of Riverstone Holdings LLC where he served as a Principal from 2007 to 2010. Mr. Jones has been with Riverstone since 2001. Mr. Jones currently serves on the boards of directors of Foresight Reserves, L.P., or Foresight, Targe Energy, LLC, or Targe, and Penn Virginia Resource Partners, L.P., or PVR Partners, and he previously served on the boards of directors of Buckeye and Mainline Management.
Mr. Jones has worked closely with us since our inception. Mr. Jones's experience in evaluating the financial performance and operations of companies in our industry, as well as his leadership skills and business acumen, provide him with the necessary skills to serve as a member of our board. In addition, Mr. Jones's work with Foresight, Buckeye, Targe and MainLine Management has given him both an understanding of the broader energy business and of the unique issues related to operating publicly-traded limited partnerships, which are similar to us.
Stephen C. MutherMr. 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.
George A. O'BrienMr. O'Brien is a member of our board and the board of directors of our manager and also serves on the compensation committee as Chairman. Mr. O'Brien has served as a director of Enviva, L.P. since May 2010 and as Executive Vice President since February 2012. He previously has served as an independent director of Magellan GP, LLC, and general partner of Magellan Midstream Partners, L.P., or Magellan, a publicly-traded company that is engaged in the transportation, storage and distribution of refined petroleum products, from December 2003 until November 2009. Mr. O'Brien was President and CEO of Pacific Lumber Company from August 2006 until July 2008. From 1988 until 2005, he worked for International Paper where he served as Senior Vice President of Forest Products responsible for its forestry, wood products, minerals and specialty chemicals businesses. Other responsibilities during his tenure at International Paper included corporate development, CFO of its New Zealand subsidiary, CEO of the New Zealand pulp, paper and tissue businesses and Vice President of Corporate Development. In January 2007, Pacific Lumber Company filed for voluntary reorganization under Chapter 11 of the United States Bankruptcy Code. Pacific Lumber successfully emerged from Chapter 11 in July, 2008. Mr. O'Brien has an agreement with Riverstone, pursuant to which he has agreed to serve on the boards of several Carlyle/Riverstone Funds' portfolio companies including Enviva, L.P.
As a result of his service to Magellan and International Paper, Mr. O'Brien gained extensive experience in overseeing the strategy, operations, and governance of major public companies. Mr. O'Brien was also selected to serve as a director of our board due to his valuable financial expertise, including extensive experience with capital markets transactions and knowledge of the energy industry. Mr. O'Brien's experience has also given him knowledge of the unique issues related to operating publicly-traded limited partnerships, which are similar to us. We believe this background and skill set makes Mr. O'Brien well-suited to serve as a member of our board
David F. PopeMr. Pope is a member of our board. Mr. Pope was our former President and Chief Executive Officer from June 2006 to July 2011. Prior to his role at Niska Holdings, Mr. Pope served as the President of Seminole Canada Gas Company since 2002, and prior to that has held various positions in the natural gas industry since 1980. In 1992, Mr. Pope began his employment with Enron Corporation after it acquired Canadian Gas Marketing, a company Mr. Pope founded in 1989. He worked for Enron Corporation as Vice President of its gas marketing and trading group from 1992 until March 2001, nine months' prior to Enron Corporation's filing of a voluntary petition for a Chapter 11 reorganization with the U.S. Bankruptcy Court in December of 2001. Mr. Pope has served as a director of GEP Midstream Finance Corp., or GEP Midstream, since 2008 and is a former director of Gibson Energy ULC, or Gibson Energy. Mr. Pope has a Bachelor of Engineering in Chemical Engineering from McGill University and has worked in the natural gas industry for his entire career.
As a result of his professional background, we believe Mr. Pope brings to us significant strategic and financial skills and significant operational experience. Combined with his over 30 years of experience in the natural gas industry and deep knowledge of our business, these attributes make Mr. Pope well-suited to serve on our board.
William H. Shea, Jr.Mr. Shea is a member of our board and the board of directors of our manager and also serves on the compensation committee. Mr. Shea has served as a director of Penn Virginia Resource Partners L.P. and Chief Executive Officer of Penn Virginia Resource Partners, L.P.
since March 2010. Previously, Mr. Shea served as the Chairman of Buckeye GP LLC, the general partner of Buckeye Partners, L.P., a refined petroleum products pipeline partnership from May 2004 to July 2007, as President and Chief Executive Officer of Buckeye GP LLC from September 2000 to July 2007 and as President and Chief Operating Officer of Buckeye GP LLC from July 1998 to September 2000. From August 2006 to July 2007, Mr. Shea served as Chairman of MainLine Management LLC, the general partner of Buckeye GP Holdings, L.P., and as President and Chief Executive Officer of MainLine Management LLC from May 2004 to July 2007. Mr. Shea also serves as a director of Kayne Anderson Energy Total Return Fund, Inc. and Kayne Anderson MLP Investment Company. Mr. Shea has an agreement with Riverstone, pursuant to which he has agreed to serve on the boards of Carlyle/Riverstone Funds' portfolio companies.
Mr. Shea's experiences as an executive with both Penn Virginia and Buckeye, energy companies that operate across a broad spectrum of sectors, including coal, natural gas gathering and processing and refined petroleum products transportation, have given him valuable knowledge about our industry. In addition, Mr. Shea has valuable experience overseeing the strategy and operations of publicly-traded partnerships, which are similar to us. As a result of this experience and resulting skills set, we believe Mr. Shea is an asset to our board.
Andrew W. WardMr. Ward is a member of our board, the board of directors of our manager and the board of supervisors of Niska Holdings, which is our parent. Mr. Ward has served as a member of the board of supervisors of Niska Holdings since May 2006. He is currently a Managing Director of Riverstone Holdings LLC where he served as a Principal from March 2002 to December 2004. Mr. Ward currently serves on the board of directors of Gibson Energy, GEP Midstream and Penn Virginia Resource Partners, L.P. and has previously served on the boards of directors of Buckeye GP LLC, or Buckeye, the general partner of Buckeye Partners, L.P., a refined petroleum products pipeline partnership and MainLine Management LLC, or MainLine Management, the general partner of Buckeye GP Holdings L.P.
Mr. Ward has served as a director since our inception. Mr. Ward's experience in evaluating the financial performance and operations of companies in our industry, combined with his leadership skills and business acumen, makes him a valuable member of our board. In addition, Mr. Ward's work with Gibson Energy, GEP Midstream, Buckeye and MainLine Management has given him both an understanding of the midstream sector of the energy business and of the unique issues related to operating publicly-traded limited partnerships, which are similar to us.
Our Independent Directors
Our board has determined that Deborah M. Fretz, Stephen C. Muther and James G. Jackson are independent directors under the listing standards of the NYSE. Our board considered all relevant facts and circumstances and applied the independence guidelines of the NYSE in determining that neither of these directors has any material relationship with us, our management, our general partner or its affiliates or our subsidiaries.
We hold regularly scheduled meetings of our independent directors. In accordance with our Corporate Governance Guidelines, Ms. Fretz will preside over meetings of our independent directors.
The procedure by which any interested party may communicate directly with an independent director is set forth in our Corporate Governance Guidelines, which is available on our website.
Our board has established an audit committee to assist it in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee is comprised of Ms. Fretz, Mr. Muther and Mr. Jackson. Our audit
committee is fully independent as defined in the listing standards of the NYSE. Our audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the audit committee.
We have designated Ms. Fretz, Mr. Muther and Mr. Jackson as audit committee financial experts. Mr. Muther has been appointed the Chairman of the audit committee.
Compensation Committee; Compensation Committee Interlocks and Insider Participation
As a controlled company that is listed on the NYSE, we are not required to have a compensation committee. In order to conform to best governance practices, however, our board has established a compensation committee to, among other things, oversee the compensation plans described below. The compensation committee establishes and reviews general policies related to our compensation and benefits. The compensation committee has the responsibility to determine and approve, or make recommendations to the board with respect to, the compensation and benefits of our board and executive officers.
The compensation committee is composed of Mr. O'Brien, Mr. Shea, Mr. Muther, Mr. Jackson and Ms. Fretz. Mr. O'Brien has been appointed the Chairman of the compensation committee. Ms. Fretz, Mr. Muther and Mr. Jackson 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). None of our executive officers served as a director or member of a compensation committee of another entity that has or has had an executive officer who served as a member of our board during 2011, 2010 or 2009.
Whenever a conflict arises between our manager or its affiliates, on the one hand, and us or any unaffiliated member, on the other, our board will resolve that conflict. Our board may establish a conflicts committee to review specific matters that our board refers to it. Our board may, but is not required to, seek the approval of such resolution from the conflicts committee. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. Such a committee would consist of a minimum of two members, none of whom can be officers or employees of our manager or directors, officers or employees of its affiliates (other than us and our subsidiaries) and each of whom must meet the independence standards for service on an audit committee established by the NYSE and the SEC. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our manager of any duties it may owe us or our unitholders.
If our board does not seek approval from the conflicts committee, and the board determines that the resolution or course of action taken with respect to the conflict of interest is either (1) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (2) fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us, then it will be presumed that, in making its decision, our board acted in good faith, and in any proceeding brought by or on behalf of us or any member, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Reimbursement of Expenses of Our Manager
Our manager does not receive any management fee or other compensation for providing management services to us. Our manager will be reimbursed for any expenses incurred on our behalf. There is no limit on the amount of expenses for which our manager may be reimbursed.
In connection with the earlier acquisition of our assets on May 12, 2006, our predecessor agreed to pay Carlyle/Riverstone an annual management fee of $1.0 million, plus the reimbursement of certain costs and expenses for its services. We are no longer subject to this obligation to Carlyle/Riverstone.
Code of Ethics
We have adopted a Code of Business Conduct and Ethics that applies to all of our officers, directors and employees.
Available on our website at http://www.niskapartners.com are copies of our Audit Committee Charter, our Compensation Committee Charter, our Code of Business Conduct and Ethics and our Corporate Governance Guidelines, all of which also will be provided to unitholders without charge upon their written request to Niska Gas Storage Partners LLC, 1001 Fannin Street, Suite 2500, Houston, TX 77002, Attention: General Counsel.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act requires our officers and directors, and persons who own more than ten percent of a registered class of our equity securities, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the Securities and Exchange Commission. Officers, directors and greater-than-ten-percent shareowners are required by regulations promulgated by the Securities and Exchange Commission to furnish us with copies of all Forms 3, 4 and 5 they file.
Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to us during fiscal 2012 and upon a review of Forms 5 and amendments thereto furnished to us with respect to fiscal 2012, 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 2012.
Significant Differences in Corporate Governance Standards
Because Holdco controls more than 50% of the voting power for the election of our directors, we are a controlled company within the meaning of NYSE rules, which exempt controlled companies from the following corporate governance requirements:
that are subject to board approval and producing a report on executive compensation to be included in an annual proxy statement or Form 10-K filed with the SEC;
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.
In reliance on these exemptions, our board is not comprised of a majority of independent directors, nor do we maintain a nominating/corporate governance committee.
Directors, Executive Officers and Corporate GovernanceDirectors and Executive Officers: Actions Taken Following the Fiscal Year Ended March 31, 2012
On April 24, 2012, Simon Dupéré was appointed as the President and Chief Executive Officer of Niska and was also appointed to the board of directors. Rick Staples was promoted to Executive Vice President on April 24, 2012 from his previous position as Senior Vice President, Commercial Operations.
On June 7, 2012 Mr. Dupéré relinquished his title as Chief Operating Officer.
Compensation Discussion and Analysis
This section describes the objectives and elements of our compensation program for the fiscal year ended March 31, 2012 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 prior fiscal year, as well as for certain elements of compensation paid to the named executive officers for the fiscal years ending on March 31, 2010 and March 31, 2011. The "named executive officers" for the 2012 fiscal year, along with the title that each officer held during the 2012 fiscal year, were as follows:
Mr. Pope served as our President and Chief Executive Officer from April 1, 2011 until July 1, 2011, at which time Mr. Dupéré was appointed as our Interim President and Chief Executive Officer. Mr. Dupéré was then appointed as our President and Chief Executive Officer effective April, 24, 2012. Mr. Pope has remained a member of our board following his resignation as our President and Chief Executive Officer. As a member of our board, Mr. Pope receives the same compensation as our
directors who are not officers, employees or paid consultants and advisors of our manager or its affiliates.
Our manager and our board, as its delegate, manages our operations and activities and makes decisions on our behalf. Our board has established a compensation committee that, while our board has delegation powers from our manager to oversee our operations, will determine and set compensation practices, or make recommendations to the full board regarding compensation matters that the board has reserved final authority over, as applicable. The compensation of each of our named executive officers for the fiscal year ending March 31, 2012 was determined and implemented solely by our compensation committee.
The objectives of our executive compensation program are to:
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.
Setting Executive Compensation
Our board, and the compensation committee of our board, each holds the authority to engage an outside compensation consultant if it appears at any time that such assistance would be appropriate. On September 15, 2010, Cogent Compensation Partners ("Cogent") was formally engaged by our compensation committee to review our overall compensation structure, including short term and long term compensation. Our board, 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. Cogent reviewed the most recent list of peer companies that we were using to determine if Cogent agreed that the group was appropriate for our use in evaluating compensation. The peer group that we and Cogent determined to be appropriate for us during the 2012 fiscal year includes companies in the United States market for which we believe we compete for executive talent in the energy sector. The peer group (the "Peer Group") includes the following companies:
The compensation program established by the compensation committee, in conjunction with Cogent, for fiscal 2012 was implemented on April 1, 2011. The elements of that compensation plan are discussed below.
Elements of Compensation. The primary elements of our named executive officers' compensation, other than the officer's base salary, are a combination of cash bonus awards and long-term equity-based compensation awards. For the fiscal year ended March 31, 2012, the compensation for our named executive officers consisted of the following key elements:
Base Salary. 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, and is 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.
During the portion of the 2012 fiscal year that Mr. Pope served as our President and Chief Executive Officer, Mr. Pope's employment was governed by an employment agreement. Mr. Pope's original employment agreement was entered into with Niska Gas Storage, and subsequently amended by an agreement that placed his employment with AECO Gas Storage Partnership (by its managing partner Niska Gas Storage Canada ULC) in 2009. Following our IPO and certain corporate restructuring events, we entered into a modified employment agreement with Mr. Pope to clarify his position as the President and Chief Executive Officer of Niska Partners Management ULC and all of its subsidiaries, including Niska Gas Storage Partners LLC. On March 29, 2011, Mr. Pope entered into a new employment agreement effective April 1, 2011. Mr. Pope's compensation pursuant to the new employment agreement included an annual base salary of not less than $550,000 Canadian dollars (approximately $554,190 in US dollars using the exchange rate in effect on March 31, 2012), payable in semi-monthly installments. This base salary was determined based upon the scope of Mr. Pope's responsibilities and commensurate with Mr. Pope's position as Chief Executive Officer.
Mr. Dupéré's base salary for the 2012 fiscal year was initially set at $370,000 Canadian dollars to reflect his position as Chief Operating Officer which he held until June 7, 2012. No changes were made to his base salary in connection with his appointment as our Interim President and Chief Executive Officer on July 1, 2011. Effective April 24, 2012, we entered into an employment agreement with Mr. Dupéré in connection with his appointment as President and Chief Executive Officer. This employment agreement established his base salary for the 2013 fiscal year at $505,000 Canadian dollars (approximately $508,847 in US dollars using the exchange rate in effect on March 31, 2012), which reflects the increased responsibilities that Mr. Dupéré assumed in his new position.
On March 24, 2011, our board, on the recommendation of the compensation committee, approved changes to certain employees and executives' base salaries. These changes became effective on April 1, 2011 and were a result of a review of comparable market salaries conducted by the compensation committee and Cogent over the course of fiscal year 2011. The changes were made to bring the base salary compensation in-line with similarly-situated market comparables and in particular, pubic limited partnerships, including the Peer Group.
On April 24, 2012, the board of directors increased the annual base salaries of two of our named executive officers. Vance E. Powers' annual base salary was increased to $290,000 U.S. dollars, effective as of April 24, 2012. Also effective April 24, 2012, the board increased Rick J. Staples' annual base salary to $315,000 CDN (approximately $317,400 in US dollars using the exchange rate in effect on March 31, 2012), reflecting an increase consistent with other executives in the market who perform the same functions and duties as Mr. Staples.
Discretionary Bonus Awards. A significant portion of the compensation of our named executive officers consists of an annual cash bonus. While base salaries offer an important retention element by providing a guaranteed income stream to our employees, we hope to 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. On March 24, 2011, our board approved a short term incentive bonus plan applicable to our employees, including our named executive officers, for the 2012 fiscal year (the "STI"). The STI provides annual bonuses based upon the achievement of company performance targets and individual performance targets for employees who participate in the plan. The targets are established by the compensation committee each year.
While the ultimate amount of any cash bonus paid to our named executive officers under the STI is determined at the discretion of our board, the bonuses are originally structured around target amounts for each employee, as well as individual and company goals. We communicate a target annual bonus amount to our employees as a certain percentage of their base salary at the beginning of their employment, clearly noting that individual or company performance may significantly impact the relationship of that target annual amount to what is actually paid out in bonuses. For the 2012 fiscal year, the target bonus amounts for Messrs. Pope, Dupéré, Powers, Staples, Dubchak and Olson were $554,190; $279,613; $125,000; $211,600; $125,952 and $110,838, respectively. Individual performance goals will depend on an employee's unit or particular function within a unit, while company performance has historically been tied to Adjusted EBITDA. We believe that paying a bonus tied to our Adjusted EBITDA aligns the interests of our executives and employees with those of our unitholders and motivates them to provide a high level of performance for us. A portion of the bonuses are accrued, but not paid, pending the results of the fiscal year end audit and subsequent audit adjustments. Thus, while those portions are accrued for the year in which they are earned, they are not paid until the following fiscal year.
Following a determination of the amount of the available bonus pool, a series of meetings occurs prior to the board's final determination of individual amounts owed to employees under the bonus plan. The managers or supervisors of various business units first meet with our Chief Executive Officer to discuss the individual performance of employees that have worked directly under such managers. The Chief Executive Officer then compiles this information and meets with our compensation committee, where he makes recommendations regarding the allotment of the bonus pool based on either ranges of amounts or a specific amount he believed are appropriate for the year. The compensation committee will then meet with our board to pass on its recommendations, which may or may not have been in line with the recommendations of Chief Executive Officer, as the compensation committee feels appropriate. The board will then make the final determination of specific amounts to be paid to each employee, including our named executive officers. While the Chief Executive Officer provides recommendations regarding the potential bonus awards for the remainder of the named executive officers, the board makes all final decisions regarding bonuses, if any, to be paid to the named executive offices, including the Chief Executive Officer. The board's determination regarding any individual award may be based solely on the targets and performance measures that have been
used as guidelines for that year, or it may take into consideration extraordinary circumstances or past awards of compensation to the individual.
For the 2012 fiscal year STI, the Adjusted EBITDA Target comprised eighty percent (80%) of the company performance component. The compensation committee may make adjustments to the Adjusted EBITDA Target throughout the year. The remaining twenty percent (20%) of the company STI component for the 2012 fiscal year was comprised of the following non-financial measures: (1) 5% based on maintaining the historical total recordable incident rate; (2) 5% based on lost time incidents (not exceeding 10% of the historical average of the first four years of the Company's operation); and (3) 10% based on no missed deliveries outside of declared maintenance periods or force majeure events. The payment of the STI is based on the aggregate level of achievement of the company's Adjusted EBITDA Target and the non-financial measures for the fiscal year, subject also to the company's payment of the minimum quarterly cash distribution that the company has set for its common and subordinated units. If we achieved 75% to 120% of the company performance measures for the year, the payout of the company component of the STI would generally range from 50% to 200%, respectively.
In accordance with the process described above, Mr. Dupéré made recommendations regarding bonus amounts for the named executive officers to the compensation committee for fiscal year 2012. The compensation committee and our board determined that while the Company had failed to achieve the minimum level of the Adjusted EBITDA that would permit a payment under the STI, the 2012 fiscal year had presented numerous challenges, many of which were outside of the control of management. In addition, executive officers had exerted maximum effort to realize the financial results that were achieved. Accordingly, the board determined to exercise its discretion and to pay a portion of the STI bonuses. Each named executive officer, other than Mr. Pope who was no longer an employee at the end of the 2012 fiscal year, was awarded 60% of the target bonus amount that was established for the 2012 fiscal year. The amount that has been approved for each named executive officer for the 2012 fiscal year is detailed in the Summary Compensation Table below, although payments will not be provided to the applicable named executive officers until June 15, 2012.
Long Term Equity-Based Incentives
Phantom Unit Performance Plan (the "PUPP"). The PUPP is a cash-based long term phantom unit plan for our employees and certain directors that we adopted on March 24, 2011. A principal purpose of the PUPP is to further align the interests of participants in the PUPP, including our named executive officers, with the interest of our unit holders by providing certain employees and directors with a phantom unit award. A phantom unit is a notional unit granted under the PUPP that represents the right to receive a cash payment equal to the fair market value of a unit of our common units (a "Unit"), following the satisfaction of certain time periods and/or certain performance criteria.
The PUPP 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 phantom unit award, subject to the terms and conditions required by the PUPP, and grants phantom units to eligible participants at such times as the compensation committee may determine 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.
Phantom unit awards under the PUPP become vested upon the date or dates on which the compensation committee sets forth in the award agreement and subject to such performance conditions as the compensation committee may assign to the particular phantom unit award. Unless the compensation committee specifies otherwise within the award agreement, phantom units are be granted unvested and subject to both time and performance conditions. Following the initial grants that we made under the PUPP, the default time period over which a phantom unit will vest is three years from
the date of grant, and the performance measure will be based upon DCF and TUR, as defined below, compared to the Peer Group. However, in order to provide continuity and transition between the compensation program which existed prior to fiscal 2012 and the current program, the initial grants of phantom units for our named executive officers were grossed up to 167% of the typical target amount for each recipient and will vest 2/3 after one year and 1/3 after two years (in order that 100% of the target number will vest in one year and 2/3 of the target number initially granted (together with an additional 1/3 of a subsequent grant assuming the PUPP is administered as expected). "DCF" is defined within the PUPP as distributed cash flow from a trust, partnership or corporation calculated based on the appreciation in the distributed cash flow per Unit or any other applicable publicly traded security during the performance period. "TUR" is defined within the PUPP as the total unitholder return of a trust, partnership or corporation, calculated based on the appreciation in the price of a Unit or other applicable traded security during the performance period. The DCF and TUR metrics will be calculated based on our percentile ranking during the applicable performance period compared to a peer group that will be determined by the compensation committee from time to time. Provided that we have satisfied our minimum quarterly distribution targets for the underlying Units, the phantom units will typically vest in accordance with the following performance criteria:
The PUPP participants must also generally be providing services to us or one of our affiliates in order for their phantom unit to become vested. The compensation committee will have authority to provide for accelerated vesting provisions in the event of a termination of employment or a change in control. Generally, in the event of a PUPP participant's death, disability, retirement, or termination of employment without cause, unvested phantom units will vest on a pro rata basis by taking into account the number of days of actual service provided to us or one of our affiliates versus the number of days in the entire vesting period for the award. Where the phantom units are subject to performance criteria, a "target" level of performance will be applied upon any acceleration of vesting, such that a maximum of 100% of the phantom units originally granted will become vested. Where vesting of the phantom units are based solely on time, the phantom units will also vest on a pro rata basis calculated by the number of days of service provided to us or one of our affiliates from the grant date to the vesting date. Unless otherwise provided in an individual award agreement, if we incur a change in control, and the holder is also terminated for certain reasons, the phantom units will also receive accelerated vesting, with any performance-based vesting provisions being accelerated at the "target" performance level.
The phantom units will also be granted with distribution equivalent rights. During the period the phantom unit is outstanding, any distribution that we pay to Unit holders generally will also be credited to the phantom unit holder in the form of additional phantom units. The number of additional phantom units to be credited to a PUPP participant's account will be determined by dividing the full amount of the distribution we would have made to the phantom unit holder if the phantom units were non-restricted Units, by the fair market value of a Unit on the payment date of any distribution.
In the event that a PUPP participant is subject solely to the United States securities and tax laws rather than Canadian tax or securities laws, the PUPP also contains a schedule of certain provisions that will apply to those participants in lieu of certain provisions within the main body of the PUPP document.
Each of our named executive officers received two separate grants of phantom units pursuant to the PUPP during the 2012 fiscal year. One grant was a time-based award with three year vesting. The time-based grant was a one-time discretionary grant that was provided for retention purposes. The second grant was the annual equity-based award that we expect to grant on an annual basis. This grant was a performance-based grant where approximately 2/3 of the award was scheduled to vest on March 31, 2012, and approximately 1/3 of the award is scheduled to vest on March 31, 2013, subject to the satisfaction of the performance and service requirements. The board set a long-term incentive target for each named executive officer's performance-based phantom unit award that was based upon a percentage of the officer's base salary. Messrs. Dupéré, Staples, Powers, Dubchak, and Olson had a target percentage of base salary of 150%, 125%, 90%, 90% and 60%, respectively, for the 2012 performance-based grants. The minimum quarterly distribution target for the underlying Units is $0.35 per quarter or $1.40 per year. We used the Peer Group described above to measure our TUR and DCF targets.
Upon reviewing the performance of the company for the 2012 fiscal year against its peer group, based on the criteria listed above, the board determined that the company did not meet its threshold targets for the first tranche of the phantom units granted during the 2012 year, and therefore, the units that were scheduled to vest at the end of the 2012 fiscal year will not vest and will be forfeited by the named executive officers. The remaining tranche of the 2012 performance-based grants may still vest in the 2013 year.
Niska Predecessor Class B and Class C Units. In 2006, Niska Predecessor issued Class B units to some of our employees, including the named executive officers then employed by us, and Class C units to Mr. Pope pursuant to the terms of his employment agreement and Niska Predecessor's partnership agreements. The Class B and Class C units represented profits interest in Niska Holdings, and entitle the holders to share in distributions by Niska Holdings once the Class A units in Niska Predecessor have received distributions equal to their contributed capital plus an 8% rate of return. As of March 31, 2012, the risk of forfeiture had lapsed on all of the Class B and Class C units upon the completion of the time limitations or the achievement of the performance conditions associated with the units as applicable and certain of our named executive officers continue to hold these vested units and may receive certain profits interests with respect to these awards, and Mr. Pope received certain settlement payments with respect to these units upon his resignation from employment. No further grant of the Class B or Class C units, however, occurred during the prior fiscal year or will occur in the future.
2010 Long Term Incentive Plan. We adopted the 2010 Long Term Incentive Plan in connection with our IPO. 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 shares of our common units to Canadian citizens, this plan is largely reserved for grants of awards to our US citizen employees, consultants and directors. At this time, no awards to any employee have been made pursuant to the 2010 Long Term Incentive Plan.
Other Compensation Items
Health and Welfare Benefits. All of our regular full-time employees, including our named executive officers, receive certain health and welfare benefits. The benefits include a health and dental plan, a short- and long-term disability plan, basic and optional life insurance, and basic and optional accidental death and dismemberment insurance coverage (with the exception of Mr. Powers). Pursuant to his employment agreement, Mr. Pope was entitled to receive an annual allowance of $6,000 in order to cover additional health care expenses not directly provided or paid for by us. We continue to be the owner and beneficiary of a life insurance policy on the life of Mr. Pope and we also continue to be responsible for fully funding the policy such that Mr. Pope will receive an annual retirement amount of US$250,000.00 for a period of 10 years upon reaching the age of 65 or a pre-retirement death benefit of US$1,500,000.00 in the event Mr. Pope dies prior to reaching the age of 65. We also made payments on Mr. Pope's behalf for a Critical Illness policy that was previously established by Mr. Pope's prior employer and continued by us during Mr. Pope's employment. Mr. Pope assumed the funding obligation with respect to that policy following his resignation. Mr. Powers receives health and dental benefits only, which are funded by us.
Retirement and Pension Benefits. Our registered retirement savings plan, or RRSP Plan/Non-Registered Employee Savings Plan, provides Canadian resident employees with an opportunity to participate in a retirement savings plan. This type of retirement plan is a Canadian retirement plan with features similar to a 401(k) plan or an individual retirement account administered in the United States. Our employees, including our named executive officers (other than Mr. Powers), are allowed to contribute their own funds, and we will regardless of an employee's contributions, contribute 8% of an employee's base salary into such RRSP Plan contributions as well as discretionary contributions from us on their behalf from time to time. Mr. Pope's previous employment agreement stated that he would receive an annual contribution from us of 8% of his annual base salary each year into the plan, and Mr. Dupéré's new employment agreement provides for the same contribution amount by us. Mr. Powers, a U.S. citizen, participates in a U.S. 401(k) Plan which allows Mr. Powers to contribute his own funds and the Company provides an 11% contribution to his 401(k) Plan.
Perquisites. We provide our named executive officers with certain perquisites that we believe are in line with industry standards as well as peer companies within our geographic region, and which are necessary to remain competitive with regard to overall executive compensation. Our named executives (other than Mr. Powers) received additional payments to be applied to expenses for home computers, club membership (including industry organizations) and other personal expenses, as well as a monthly automobile allowance and paid parking at our office facilities. Commencing April 24, 2012, as part of his employment agreement, Mr. Dupéré's perquisites were eliminated except for an allowance for parking.
Severance and Change in Control Benefits. Mr. Pope was the only named executive officer who had an agreement with us that contained severance provisions during the 2012 fiscal year. The phantom unit awards granted to each named executive officer also contain change of control provisions. Canadian citizens may be entitled to certain severance benefits under the common law, therefore, to establish clarity with regard to our severance obligations, we have chosen to maintain a formal employment agreement with our chief executive officer that contains negotiated severance benefits. With respect to the PUPP awards, we have provided severance and change in control protections in order to serve as a retention tool. 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 this benefit to our executive officers in order to remain competitive in attracting and retaining skilled professionals in our industry.
Tax and Securities Issues. We maintain an insider trading policy that is applicable to our directors and employees, including our named executive officers. 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.
Actions Taken Following the Fiscal Year Ended March 31, 2012
We entered into an employment agreement with Mr. Dupéré on April 24, 2012. The employment agreement supersedes any previous employment agreements or arrangements by and between Mr. Dupéré and us. The term of the employment agreement is for an indefinite period of time, and may be terminated at the discretion of Mr. Dupéré or us, with or without cause.
In addition to the base salary described above, Mr. Dupéré's employment agreement provides him with a one-time grant of 82,850 phantom common units (the "Phantom Grant"). Mr. Dupéré is entitled to participate in our annual bonus plans, long-term incentive plans, retirement plans and health and welfare benefit and insurance plans. The target annual cash bonus for the 2013 year established for Mr. Dupéré is equal to 100% of his annual base salary, while the target annual long-term performance-based incentive award for the 2013 year established for Mr. Dupéré is equal to 200% of his annual base salary. Mr. Dupéré will also receive five weeks of vacation each year.
The Phantom Grant will be granted pursuant to the PUPP. The Phantom Grant will be subject to a three year vesting restriction that will lapse on April 24, 2015, unless Mr. Dupéré's employment terminates earlier due to an Involuntary Termination (as defined below). Any other termination of Mr. Dupéré's employment during the vesting period will result in a forfeiture of the Phantom Grant. Each phantom unit is granted with a dividend equivalent right that will be paid, or forfeited, at the same time as the underlying Unit is settled, or forfeited, as applicable. The Phantom Grant will be settled in cash. Mr. Dupéré may not transfer, assign or otherwise alienate his rights with respect to the phantom units during the vesting period.
The employment agreement also addresses the potential severance and change in control benefits that Mr. Dupéré may receive upon a termination of his employment in certain situations. These potential benefits are described in greater detail below under the "Potential Payments Upon Termination or Change in Control" section below.
Report of the Compensation Committee
In light of the foregoing, as required by Item 407(e)(5) of Regulation S-K, our compensation committee has reviewed and discussed the Compensation Discussion and Analysis with our management and, based on such review and discussions, has recommended to the board of directors that the Compensation Discussion and Analysis be included in this annual report.
the Compensation Committee:
The following tables, footnotes and the above narratives provide information regarding the compensation, benefits and equity holdings in Niska Gas Storage Partners LLC for the named executive officers.
Summary Compensation for Years Ended March 31, 2012, 2011 and 2010
The year "2010" refers to the fiscal year of April 1, 2009 through March 31, 2010, and the year "2011" refers to the fiscal year of April 1, 2010 through March 31, 2011, the year "2012" refers to the fiscal year of April 1, 2011 through March 31, 2012. Compensation to our named executive officers was paid primarily in Canadian dollars, but is reported in U.S. dollars in the tables that follow. An exchange rate of 0.952 U.S. dollars was used for 2010 amounts for each Canadian dollar (the exchange rate reported by the Bank of Canada on December 31, 2009) and 0.9836 U.S dollars for each Canadian dollar was used for the 2011 amounts of each Canadian dollar (the exchange rate reported by the Bank of Canada on March 31, 2011), and 1.0076 U.S dollars for each Canadian dollar was used for the 2012 amounts of each Canadian dollar (the average exchange rate for the period as reported by the Bank of Canada). The only exception to this rule is for our Chief Financial Officer, Vance E. Powers, who is a U.S. resident and paid in U.S. dollars.
executive officer upon the settlement of an award. Pursuant to SEC rules, the amounts shown exclude the effect of estimated forfeitures and are based upon the probable outcome of the performance conditions associated with the phantom unit awards at the grant date, although we know that a portion of the phantom units that were subject to performance-based conditions in 2012 have already been forfeited without value. The "probable" outcome at the date of grant was not the "maximum" possible payout under the awards. The "maximum" amounts would have been as follows: Mr. Pope, $7,019,740; Mr. Dupéré, $2,774,985; Mr. Powers, $1,249,987; Mr. Staples $1,866,694 Mr. Dubchak, $1,249,987; and Mr. Olson, $880,019. Additional details regarding the calculation of our unit-based phantom awards are included in Note 3 of the Notes to our Consolidated Financial Statements. Although the phantom unit awards are reported in the "Unit Awards" column above, the portion of the awards that are still outstanding will be settled, if at all, in cash payments rather than actual common units. All of Mr. Pope's phantom units were forfeited upon his resignation from employment without value. The number of performance-based and time-based phantom units that each of our named executive officers held as of the date of this filing, and the current value of those awards, are reflected below:
Grants of Plan-Based Awards
We granted phantom unit awards to each of our named executive officers during the fiscal year ended March 31, 2012.
Narrative Description to Summary Compensation Table and Grants of Plan-Based Awards
While an amount was reported in the Unit Awards column for Mr. Pope in the Summary Compensation Table above, upon his resignation he forfeited the phantom units granted to him in 2012 and he did not actually receive the $3,509,870 reported above.
While Mr. Dupéré's employment relationship is currently governed by an employment agreement, his employment relationship with us during the 2012 was not governed by a formal employment agreement. Like the other named executive officers, however, Mr. Dupéré's phantom unit awards were governed by the PUPP and the individual award agreement that was provided to him at the time of the grant of the awards. Certain terms of the PUPP and the individual award agreements that govern the phantom unit awards have been described above within the compensation discussion and analysis. Specific details regarding the potential acceleration of vesting or the settlement of the awards upon certain terminations of employment or a change in control are contained in the "Potential Payments Upon Termination or Change in Control" below.
Outstanding Equity Awards as of Fiscal Year-End March 31, 2012
Option Exercises and Stock Vested
The named executive officers did not hold any options that were exercised or any unit awards that vested during the year ended March 31, 2012.
We do not maintain or sponsor a pension plan for our named executive officers.
Nonqualified Deferred Compensation
We do not maintain or sponsor a nonqualified deferred compensation plan for our named executive officers.
Potential Payments Upon Termination or Change in Control
PUPP. The phantom units that we granted to each of our named executive officers during the 2012 fiscal year contain certain termination and change in control benefits. The PUPP participants must generally be providing services to us or one of our affiliates in order for their award to become vested, but in the event of a PUPP participant's death, disability, retirement, or termination of employment without cause (each term as defined below) 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. Because one of the phantom unit awards granted to each of the named executive officers in 2012 is also subject to performance criteria, a "target" level of performance will be applied upon any acceleration of vesting to performance-based awards, such that a maximum of 100% of the phantom units originally granted will become vested. If we incur a change in control the phantom units will also receive accelerated vesting, with any performance-based vesting provisions being accelerated at the "target" performance level, if 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.
The PUPP defines a "disability" as a participant's inability, due to illness, disease, affliction, mental or physical disability or a similar cause, to perform his or her duties for any consecutive twelve month period or for any eighteen month period, or a court's declaration of the participant's incompetence. A "retirement" is defined as a normal or early retirement pursuant to any applicable retirement plan maintained by us at the time of the retirement. A "change in control" generally will be deemed to have occurred upon (1) the acquisition by any person or group, other than us or one of our affiliates, of ownership of fifty percent (50%) or more of the outstanding shares of Niska Gas Storage Management LLC (a Delaware limited liability company and our "Manager"); or (2) a sale or other disposition of all of substantially all of our assets (or those of our affiliates) to any person other than one of our affiliates. However, the following transactions will not be deemed to result in our change in control: (a) acquisitions by investors in the manager for financing purposes; (b) an underwriter temporarily holding equity interests pursuant to a public offering of those interests; (c) any transfer of assets to an entity that is controlled by us; or (d) an acquisition by any employee benefit plan maintained by us, the manager or an affiliate of either us or the manager. A "constructive dismissal" for a Canadian citizen shall be defined pursuant to the common law, which includes a material change to the executive's title, responsibilities, reporting relationship or compensation, where the termination must occur within the 45 day period following the event that gave rise to the constructive dismissal. A "constructive dismissal" for a U.S. citizen will generally be defined as our material change to the participant's title, responsibilities, reporting relationship or compensation which we do not remedy within a 30 day period of being put on notice of the condition, and where the executive then terminates within a 30 day period following our cure period.
The table below shows the value of the acceleration of the phantom units that each officer would have received upon a termination of employment that occurred on March 31, 2012. For purposes of the table below we have assumed that our common units were valued at $9.54 (the closing price of a common unit on March 30, 2012, the last applicable trading day before the end of the fiscal year). The
actual amount that any named executive officer could receive with respect to his phantom units, however, could only be determined upon an actual termination of employment.
Mr. Pope's Resignation. When Mr. Pope resigned effective July 1, 2011, he received a cash settlement payment of $5,684,075 USD for his 179,953 Class C units that were outstanding at the time of his retirement. Pursuant to the terms of Mr. Pope's Class C units, a termination of employment triggered a cash settlement for the awards. The proceeds from this sale of Class C units were funded by Niska Holdings L.P., rather than us. Mr. Pope also signed a general release in our favor in connection with his receipt of the settlement.
Mr. Dupéré's Employment Agreement. We did not have an employment agreement with Mr. Dupéré during the 2012 fiscal year. Upon his appointment on April 24, 2012, we entered into an employment agreement appointing him as President and Chief Executive Officer. The agreement contains certain potential severance and change in control benefits. The Phantom Grant described above will be subject to a three year vesting schedule that will generally lapse on April 24, 2015. If his termination occurs prior to that date due to an Involuntary Termination, he will receive pro-rata accelerated vesting for the Phantom Grant. Other terminations of employment will result in a forfeiture of the award. An "Involuntary Termination" means a termination by us without "cause," or by Mr. Dupéré for "good reason." "Cause" is generally defined in the employment agreement as any action that would entitle us to terminate him without notice or payment in lieu of notice under the common law, including, without limitation, (1) fraud, misappropriation of our property, embezzlement, malfeasance, misfeasance or nonfeasance that is willful or grossly negligent; (2) Mr. Dupéré's willful allowance of a conflict of interest between himself and his duties to us; or (3) Mr. Dupéré's breach of
any material covenants or obligations under his employment agreement. A "good reason" event means any of the following without Mr. Dupéré's consent: (a) our requirements that Mr. Dupéré perform duties inconsistent with his position; (b) a material reduction of Mr. Dupéré's annual base salary; (c) our relocation of Mr. Dupéré's primary work location by over 50 miles; (d) our failure to permit Mr. Dupéré to participate in incentive compensation plans or employment benefit programs that are similar to those described within his employment agreement.
Upon Mr. Dupéré's termination from us for "cause," or Mr. Dupéré's resignation, retirement, death or disability, Mr. Dupéré will not receive any further compensation or benefits pursuant to the employment agreement, and he would forfeit his Phantom Grant if such a termination occurred during the first three years of the term of his employment agreement. In the event that Mr. Dupéré's employment is terminated due to an Involuntary Termination during the first three years of Mr. Dupéré's employment agreement, he will receive a lump sum cash payment equal to two times his then-current annual base salary, less any statutory withholding obligations, and pro-rata vesting acceleration for his Phantom Grant based upon the number of days that Mr. Dupéré was employed during the three year period. If Mr. Dupéré's Involuntary Termination occurs following the first three years of the employment agreement, he would receive a lump sum cash payment equal to two times his then-current annual base salary, less any statutory withholding obligations. In the event that Mr. Dupéré's Involuntary Termination occurs on or during the two year period following a change in control, Mr. Dupéré will receive a lump sum cash payment equal to two times his then-current annual base salary (less any statutory withholding obligations), the accelerated vesting of all equity-based compensation awards held on the date of Mr. Dupéré's termination of employment, and the pro-rata payment of his annual bonus for the year in which the termination occurs.
The employment agreement contains standard restrictive covenants. Mr. Dupéré's non-competition restrictions will extend for a twelve month period following Mr. Dupéré's termination of employment, and his solicitation provision will cover a six month period following his termination of employment. In the event that any incentive-based compensation is paid to Mr. Dupéré during his employment with us, and any law, government regulation or stock exchange listing requires us to recover any necessary portion of that payment from Mr. Dupéré, we will be entitled to recover the grant or payment.
Our compensation committee has reviewed our compensation policies as generally applicable to our employees and believes that our policies do not encourage excessive and unnecessary risk-taking, and that the level of risk that they do encourage is not reasonably likely to have a material adverse effect on us.
Our compensation philosophy and culture support the use of base salary, certain performance-based compensation that are generally uniform in design and in operation throughout our organization and with all levels of employees. These compensation policies and practices are centrally designed and administered, and are substantially identical between our business divisions. In addition, the following specific factors, in particular, reduce the likelihood of excessive risk-taking:
Officers, employees or paid consultants and advisors of our manager or its affiliates who also serve as our directors will not receive additional compensation for their service as our directors. Directors who are not officers, employees or paid consultants and advisors of our manager or its affiliates ("Eligible Directors") receive an annual cash retainer of $50,000 and common units with a market value equal to $50,000 at the time of the award. The board chairperson receives an additional fee of $62,500 and common units with a market value equal to $62,500 at the time of the award. In addition, Eligible Directors receive $1,500 for each board and committee meeting that they attend. The Chairperson of the audit committee receives an additional annual fee of $15,000. Directors serving as the Chairperson of our other committees will receive an additional annual fee of $10,000. Directors also receive reimbursement for out-of-pocket expenses associated with attending meetings of the board or committees and director and officer liability insurance coverage. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.
Mr. Dupéré joined our board in connection with his appointment as our Chief Executive Officer, but he did not serve on the board during the 2012 fiscal year. Other board members that served on our board during the 2012 (E. Bartow Jones, George A. O'Brien, William H. Shea, and Andrew W. Ward) were not paid any compensation by us for their services to our board, as they are appointed and compensated by Riverstone.
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 and Deferrals. The Deferred Plan is based on a calendar year plan year. However, the initial plan year was a short plan year that began August 10, 2011 and ended December 31, 2011. 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 full 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) the Participant's termination 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. For the initial short plan year through March 15, 2012, we chose to give all Participants an investment crediting rate equal to 5% on all deferred amounts. On March 15, 2012, the plan administrator chose benchmark mutual funds with Morgan Stanley as the investment option for the Deferred Plan. As a result, since March 15, 2012, growth realized in the accounts has been and will be in line with the Morgan Stanley benchmark mutual funds chosen by the plan administrator.
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 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 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 to 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 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 following table sets forth the beneficial ownership of our units by:
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 March 31, 2012, subject to community property laws where applicable.
Certain Relationships and Related Party Transactions
On August 24, 2011, we entered into a Common Unit Purchase Agreement with Holdco pursuant to which we issued and sold to Holdco, and Holdco purchased from us, 687,500 common units for a cash purchase price of $16.00 per common unit or $11,000,000 in the aggregate.
Holdco owns 16,304,745 common units and 33,804,745 subordinated units, representing approximately 74.1% of our units and the incentive distribution rights. In addition, our manager owns a 2% managing member interest in us.
On December 20, 2011, we purchased the net assets of Starks Gas Storage LLC, Coastal Bend Gas Storage LLC, and Sundance Gas Storage ULC from Holdco and from R/C Sundance Cooperatief U.A. for consideration of $5.0 million.
During the year ended March 31, 2012, we purchased certain Class B units of Niska Holdings Canada from certain non-executive officers and employees of Niska Partners for $2.2 million.
Agreements with Affiliates
During the year ended March 31, 2012, we entered into various agreements that effected our formation transactions, including the transfer of assets to, and the assumption of liabilities by, us and our subsidiaries. These agreements were not the result of arm's-length negotiations and the terms of these agreements were not necessarily at least as favorable to the parties to these agreements as the terms which could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with our formation transactions, including the expenses associated with transferring assets to our subsidiaries were paid from the proceeds of our IPO.
On March 5, 2010, our subsidiary, AECO Partnership, entered into a services agreement with certain affiliates of Holdco pursuant to which it would provide employees to manage certain development projects for Holdco or its affiliates in return for a service fee that is to be agreed upon between the parties from time to time. AECO Partnership subsequently assigned its rights and obligations under the services agreement to Niska Gas Storage Management ULC. The initial term of the services agreement expired on March 31, 2012, at which point it was automatically renewed for an additional one-year term. The current term will expire on March 31, 2013, at which point it will automatically renew for an additional one-year term unless it is terminated.
Registration Rights Agreement
Under our Operating Agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other company securities proposed to be sold by our manager or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our manager. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.
In addition, we have entered into a registration rights agreement with Holdco. A copy of the form of registration rights agreement is filed as an exhibit to this report and is incorporated herein by reference. Pursuant to the registration rights agreement, we will be required to file a registration statement to register the common units and subordinated units issued to Holdco and the common units issuable upon the conversion of the subordinated units upon request of Holdco. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates of Holdco and, in certain circumstances, to third parties.
Policies Relating to Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our manager and its affiliates (including Holdco), on the one hand, and us and our unaffiliated members, on the other hand. Our directors and officers have fiduciary duties to manage our manager in a manner beneficial to its owners. At the same time, our manager has a fiduciary duty to manage us in a manner beneficial to our unitholders. Our Operating Agreement contains provisions that specifically 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 2012, 2011 and 2010:
Our audit committee has adopted an audit committee charter, which is available on our website, which requires the audit committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The audit committee does not delegate its pre-approval responsibilities to management or to an individual member of the audit committee.
(a) (1) Financial Statements
See "Index to the Consolidated Financial Statements" set forth on Page F-1.
(2) Financial Statement Schedules
All schedules are omitted because they are not applicable or the required information is presented in the financial statements or notes thereto.