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NKA > SEC Filings for NKA > Form 10-K on 7-Jun-2013All Recent SEC Filings

Show all filings for NISKA GAS STORAGE PARTNERS LLC | Request a Trial to NEW EDGAR Online Pro



Annual Report

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

The historical financial statements included elsewhere in this document reflect the consolidated assets, liabilities and operations of Niska Gas Storage Partners LLC ("Niska Partners" or "Niska") as at March 31, 2013 and 2012, and for of the years ended March 31, 2013, 2012 and 2011. 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 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 capacity on a long and short-term basis for which we receive fees and (ii) 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 225.5 Bcf of working gas capacity among its facilities, including 8.5 Bcf leased from a third party pipeline company. We also operate a natural gas marketing business which is an extension of our proprietary optimization activities in Canada.

During the year ended March 31, 2012, we experienced a substantial decline in realized revenues, particularly in our short-term contracting and optimization activities, compared to amounts realized in fiscal 2011. The revenue decline resulted from a significant decline 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.

During the fourth quarter of fiscal 2012 and into the first quarter of fiscal 2013, these conditions improved somewhat as the seasonal spread widened and modestly higher volatility returned to the natural gas futures market. However, as fiscal 2013 progressed the seasonal spread again narrowed in response to warmer weather in North America during the summer of calendar 2012, significant coal-to-gas switching in response to low natural gas prices and general improvement in North American economic conditions.

We are not able to predict the long-term impact of these factors on our revenues and profitability or the amount or timing of potentially positive developments such as increased demand for natural gas resulting from further long-term switching from coal to natural gas by utilities, continued increases in industrial or consumer demand or exports of Liquefied Natural Gas (LNG) from North America to other continents.

As we enter fiscal 2014, market conditions, including the seasonal spread and natural gas futures price volatility remain uncertain but are reduced compared to our first fiscal quarter of the prior year.

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A summary of financial and operating data for the years ended March 31, 2013, 2012 and 2011:

                                                          Year Ended March 31,
                                                    2013          2012          2011
                                                         (dollars in thousands)
Consolidated Statement of Earnings and
Comprehensive Income Data:
Fee-based revenue                                $   163,325   $   146,053   $   160,538
Optimization, net(1)                                 (22,630 )     122,528        69,537

                                                     140,695       268,581       230,075
Expenses (Income):
Operating                                             32,535        43,978        44,772
General and administrative                            38,562        28,582        34,568
Depreciation and amortization                         50,409        46,131        46,891
Loss on impairment and sale of assets(2)              14,927         5,342             -
Interest                                              67,010        74,630        77,007
Loss on extinguishment of debt                           599         4,861             -
Impairment of goodwill(2)                                  -       250,000             -
Foreign exchange (gains) losses                         (694 )         682          (518 )
Other income                                            (110 )        (166 )         (48 )

Earnings (loss) before income taxes                  (62,543 )    (185,459 )      27,403
Income tax (benefit)/expense:
Current                                               (1,414 )         412         1,213
Deferred                                             (17,528 )     (20,099 )     (31,267 )

                                                     (18,942 )     (19,687 )     (30,054 )

Net earnings (loss) and comprehensive income
(loss)                                           $   (43,601 ) $  (165,772 ) $    57,457

Reconciliation of Adjusted EBITDA to net
(loss) earnings:
Net earnings (loss)                                  (43,601 )    (165,772 )      57,527
Add (deduct):                                                                          -
Interest expense                                      67,010        74,630        77,007
Income tax benefit                                   (18,942 )     (19,687 )     (30,054 )
Depreciation and amortization                         50,409        46,131        46,891
Impairment of goodwill                                     -       250,000             -
Unrealized risk management losses (gains)             89,851       (83,193 )      44,787
Loss on extinguishment of debt                           599         4,861             -
Foreign exchange (gains) losses                         (694 )         682          (518 )
Loss on impairment and sale of assets                 14,927         5,342             -
Other income                                            (110 )        (166 )         (48 )
Inventory impairment writedown                        22,281        23,400             -

Adjusted EBITDA(3)                                   181,730       136,229       195,592
Add (deduct):
Cash interest expense, net(4)                        (63,599 )     (69,856 )     (75,991 )
Income taxes recovered (paid)                            722          (988 )        (474 )
Maintenance capital expenditures                      (1,833 )      (1,858 )      (1,681 )
Other income                                             110           166            48

Cash Available for Distribution(3)               $   117,130   $    63,694   $   117,494

Balance Sheet Data (at period end):
Total assets                                       1,524,392     1,803,358     2,061,270
Property, plant and equipment, net of
accumulated depreciation                             918,061       968,128       964,146
Long-term debt(5)                                    657,274       657,177       800,000
Total partners' equity                               597,377       690,390       916,973
Operating Data (unaudited):
Effective working gas capacity (Bcf)(6)                225.5         221.5         204.5
Capacity added during period (Bcf)                       4.0          17.0          19.0
Percent of operated capacity contracted to
third parties(7)                                        74.8 %        62.4 %        71.4 %


Optimization revenue is presented net of cost of goods sold. Net optimization revenues include unrealized risk management gains/losses and write-downs of inventory. We had an unrealized risk management loss of

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$89.9 million for the year ended March 31, 2013, an unrealized risk management gain of $83.2 million for the year ended March 31, 2012 and an unrealized risk management loss of $44.8 million for the year ended March 31, 2011. We had write-downs of inventory of $22.3 million, $23.4 million and $ nil for the years ended March 31, 2013, 2012 and 2011 respectively. Excluding these non-cash items, which do not affect Adjusted EBITDA, our realized optimization revenues were $89.5 million for the year ended March 31, 2013, $62.7 million for the year ended March 31, 2012 and $114.3 million for the year ended March 31, 2011.

Loss on impairment and sale of assets in the fiscal year ended March 31, 2012 relates to an impairment charge on certain non-core assets and to a loss on sale of cushion gas from one of our U.S. facilities. Goodwill impairment in the fiscal year ended March 31, 2012 relates to goodwill in two subsidiaries that was written down from its carrying amounts of $495.6 million to $245.6 million. Loss on impairment and sale of assets in the fiscal year ended March 31, 2013 relates to losses on sales of cushion gas from one of our Canadian facilities and from one of our U.S. facilities.

Adjusted EBITDA and Cash Available for Distribution in fiscal 2013 include the benefits of inventory write-downs of $43.1 million related to inventory impairments recorded in the fourth quarter of fiscal 2012 and the first quarter of fiscal 2013. Excluding these benefits, Adjusted EBITDA would have been $138.6 million and Cash Available for Distribution would have been $74.0 million.

During fiscal 2012, the Company changed its calculation of cash interest expense, net to include the effect of capitalized interest. Accordingly, cash interest expense in fiscal 2013 and 2012 were reduced by $2.9 million and $4.1 million of capitalized interest, respectively. The amount for fiscal 2011 which included capitalized interest of $2.0 million was not restated.

Excludes revolver drawings, which are recorded in current liabilities.

Represents operated and NGPL capacity.

Excludes NGPL leased capacity of 8.5 Bcf.

The following table sets forth volume utilized by, and revenue and fees/margins derived from, LTF contracts, STF contracts and proprietary optimization transactions for the fiscal years ended March 31, 2013, 2012 and 2011:

                                                          Year Ended March 31,
                                                      2013        2012        2011
   Storage Capacity (Bcf) utilized by:
   LTF Contracts                                        126.1       109.4       104.7
   STF Contracts                                         36.1        23.6        35.2
   Proprietary optimization transactions                 63.3        88.5        64.6

   Total                                                225.5       221.5       204.5

   Revenue (in thousands)
   Fee-based contracts
   LTF Contracts                                    $ 108,615   $ 116,244   $ 119,566
   STF Contracts                                       54,710      29,809      40,972

                                                      163,325     146,053     160,538
   Realized proprietary optimization transactions      89,525      62,735     114,324
   Unrealized risk management gains (losses)          (89,874 )    83,193     (44,787 )
   Inventory write-down                               (22,281 )   (23,400 )         -

                                                      (22,630 )   122,528      69,537

   Total                                            $ 140,695   $ 268,581   $ 230,075

   Fees/Margins ($/Mcf)
   LTF Contracts                                    $    0.86   $    1.06   $    1.14
   STF Contracts                                         1.51        1.26        1.16
   Realized proprietary optimization transactions        1.41        0.71        1.77

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Non-GAAP Financial Measure

Adjusted EBITDA

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

We define Adjusted EBITDA as net earnings before interest, income taxes, depreciation and amortization, impairment of goodwill, unrealized risk management gains and losses, loss on extinguishment of debt, foreign exchange gains and losses, inventory impairment write-downs, 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 financial performance of our assets, operations and return on capital without regard to financing methods, capital structure or historical cost basis;

the ability of our assets to generate cash sufficient to pay interest on our indebtedness and make distributions to our equity holders;

repeatable operating performance that is not distorted by non-recurring items or market volatility; and

the viability of acquisitions and capital expenditure projects.

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

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

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

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

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

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

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

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

How We Evaluate Our Operations

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

volume and margin derived from our proprietary optimization activities;

operating, general and administrative expenses;

Adjusted EBITDA;

capitalization and leverage; and

borrowing base revolver availability, liquidity, and compliance with debt covenants.

Volume and Fees Derived from Fee-based Contracts

We provide fee-based natural gas storage services to our customers under long-term firm (LTF) and short-term firm (STF) contracts. When a customer enters into a LTF contract, the customer is obligated to pay us monthly reservation fees for a fixed amount of storage which is usable by the customer at their option subject to contractual limits. These fees are fixed regardless of the actual use by the customer, but we also collect a variable fee when the services are actually used in order to allow us to recover our variable operating costs. The volume-weighted average life of our LTF contracts at March 31, 2013 was 2.0 years. Reservation fees comprise over 90% of the revenue generated under LTF contracts and provide a baseline of revenue in excess of our operating and general and administrative costs. We also provide fee-based services under short-term firm (STF) contracts, where a customer pays a fixed fee to inject a specified quantity of gas on a specified date or dates and to 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 can enter into offsetting transactions to capture incremental value as spot and future natural gas prices fluctuate prior to that activity date.

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

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.

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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.

Operating Expenses

Our most significant variable operating expenses are fuel and electricity costs. These operating expenses vary significantly based upon the amount of natural gas we inject or withdraw throughout the year and the price of the energy commodity at the time of purchase. Variable operating expenses are partially offset by the variable fees we collect from our LTF contracts. The fixed component of our operating expenses include salaries and labor, parts and supplies, surface and mineral lease rentals and other general operating costs. These fixed operating expenses are more stable from year to year but can fluctuate due to unforeseen repairs, 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 credit metrics. Our most important credit metric is our fixed charge coverage ratio, or FCCR, which is contained in the Indenture to our 8.875% Senior Notes and our $400.0 million Revolving Credit Agreement. The FCCR measures our Adjusted EBITDA divided by fixed charges, both of which are defined in the Indenture and credit agreement. As discussed below, when our FCCR is below 2.0 times, we are restricted in our ability to issue new debt. When our FCCR is below 1.75 times, we are restricted in our ability to pay distributions. We also monitor our ratio of long-term and total debt to Adjusted EBITDA and our ratio of debt to debt plus equity. While these metrics are not included in our Indenture or credit agreement, they are common metrics used to measure the credit-worthiness of companies, including those similar to us.

As of March 31, 2013, we had a FCCR of 2.6 to 1, a ratio of total debt to Adjusted EBITDA of 4.0 times, a ratio of long-term debt to Adjusted EBITDA of 3.6 times and a ratio of long-term debt to long-term debt plus equity of 52.4%. When the benefits of inventory write-downs are removed from Adjusted EBITDA, FCCR would have been 2.0 to 1.0, the ratio of total debt to Adjusted EBITDA would have been 5.3 times and the ratio of long-term debt to Adjusted EBITDA would have been 4.7 times. These amounts compare to an FCCR of 1.94 to 1.0, a ratio of total debt to Adjusted EBITDA of 5.8 times (4.8 times using long-term debt only) and a ratio of long-term debt to long-term debt plus equity 51.9%. In fiscal 2012 and 2013 we undertook a number of steps to improve these credit metrics, including the monetization of excess working capital, principally proprietary inventory, the repurchase in fiscal 2012 of a portion of our outstanding Senior Notes and, in fiscal 2013, the amendment and

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extension of our $400.0 million revolving credit agreement which provided for lower interest rates under this credit facility.

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 available capacity under our credit facility. Accordingly, we 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 Fee-based Contracts

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

Gas Storage Capacity Growth

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

Carried Inventory

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

Variable Costs

The variable operating costs of our facilities (mostly comprised of costs associated with fuel or electricity for compressor operations) are affected by the amount and price of energy used to inject and withdraw 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.

Carrying Costs

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

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Customer Usage Patterns

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


Weather extremes and variability directly affect our margins. Very mild . . .

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