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NKA > SEC Filings for NKA > Form 10-Q on 2-Aug-2013All Recent SEC Filings

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

Form 10-Q for NISKA GAS STORAGE PARTNERS LLC


2-Aug-2013

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following information should be read in conjunction with our unaudited consolidated financial statements and accompanying notes included in this report. The following information and such unaudited consolidated financial statements should also be read in conjunction with the consolidated financial statements and related notes, management's discussion and analysis of financial condition and results of operations and other information included our Annual Report on Form 10-K for the fiscal year ended March 31, 2013.

Overview of Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP") requires estimates and judgments to be made regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Our most critical accounting estimates, which involve the judgment of our management, were fully disclosed in our Annual Report on Form 10-K for the fiscal year ended March 31, 2013 and remained unchanged as of June 30, 2013.

Overview of Our Business

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. Niska Partners markets gas storage services of working gas capacity in addition to optimizing storage capacity with its own proprietary gas purchases at each of these facilities. We also operate a natural gas marketing business which is an extension of our propriety optimization activities in Canada.

We earn revenues by leasing storage on a long-term firm ("LTF") contract basis for which we receive monthly reservation fees for fixed amounts of storage, 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 optimization, where we purchase and sell gas on an economically hedged basis in order to improve facility utilization at margins higher than those from third-party contracts. Proprietary optimization activities occur when the Company purchases and sells natural gas for its own account. Our revenues related to our marketing business are included in proprietary optimization activities.

The Company has a total of 225.5 billion cubic feet ("Bcf") of working gas capacity among its facilities, including 8.5 Bcf leased from a third-party pipeline company.

In June 2013 we received approval from the California Public Utilities Commission for an expansion of working gas storage capacity of 25 Bcf at our Wild Goose facility. We plan to release that capacity to our customers by December 2013. When fully available, our total working gas capacity will be 75 Bcf at Wild Goose and 250.5 Bcf across all of our facilities.

We have aggregated all of our activities in one reportable operating segment for financial reporting purposes. Our consolidated financial statements are prepared in accordance with GAAP.

Factors that Impact Our Business

There have been no material changes in the disclosure made in our Annual Report on Form 10-K for the fiscal year ended March 31, 2013 regarding this matter.


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Results of Operations



A summary of financial data for each of the three months ended June 30, 2013 and
2012 is as follows:



                                                             Three Months Ended
                                                                  June 30,
                                                            2013             2012
                                                                 (unaudited)
Consolidated Statement of Earnings (Loss) and
Comprehensive Income (Loss) Data:
Revenues:
Fee-based revenue                                       $      31,471    $     37,061
Optimization, net                                              25,718         (39,848 )
                                                               57,189          (2,787 )
Expenses (income):
Operating                                                      10,444           8,091
General and administrative                                     11,290           9,839
Depreciation and amortization                                  10,333          11,824
Interest                                                       16,206          16,508
Loss on extinguishment of debt                                      -             599
Foreign exchange losses (gains)                                   858            (185 )
Other expense (income)                                            391            (176 )
Income (loss) before income taxes                               7,667         (49,287 )

Income tax benefit                                               (300 )       (11,941 )

Net earnings (loss) and comprehensive income (loss)     $       7,967    $    (37,346 )

Reconciliation of Adjusted EBITDA and Cash Available
for Distribution to Net Earnings (Loss)
Net earnings (loss)                                     $       7,967    $    (37,346 )
Add/(deduct):
Interest expense                                               16,206          16,508
Income tax benefit                                               (300 )       (11,941 )
Depreciation and amortization                                  10,333          11,824
Unrealized risk management (gains) losses                     (20,118 )        51,148
Loss on extinguishment of debt                                      -             599
Foreign exchange losses (gains)                                   858            (185 )
Other expense (income)                                            391            (176 )
Write-down of inventory                                             -          22,281
Adjusted EBITDA                                                15,337          52,712

Less:
Cash interest expense, net                                     15,371          15,594
Income taxes recovered                                              -              (7 )
Maintenance capital expenditures                                   57               -
Other expense (income)                                            391            (176 )
Cash Available for Distribution                         $        (482 )  $     37,301


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Non-GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution

We use the non-GAAP financial measures Adjusted EBITDA and Cash Available for Distribution in this report. A reconciliation of Adjusted EBITDA and Cash Available for Distribution to net earnings, the 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, 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. We believe the adjustments for other income are similar in nature to the traditional adjustments to net earnings used to calculate EBITDA and adjustment for these items results in an appropriate representation of this financial measure. Cash Available for Distribution is defined as Adjusted EBITDA reduced by interest expense (excluding amortization of deferred financing costs and the effects of unrealized gains or losses on interest rate swaps), income taxes paid, maintenance capital expenditures and other income. Adjusted EBITDA and Cash Available for Distribution are used as supplemental financial measures by our management and by external users of our financial statements, such as commercial banks and ratings agencies, to assess:

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

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

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

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.

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


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Revenues

Revenues include fee-based revenue and optimization revenue, net. Fee-based revenue consists of long-term contracts for storage fees that are generated when we lease storage capacity on a term basis and short-term fees associated with specified injections and withdrawals of natural gas. Optimization revenue results from the purchase of natural gas inventory and its forward sale to future periods through financial and physical energy trading contracts, with our facilities being used to store the inventory between acquisition and disposition of the natural gas inventory.

Revenues for the three months ended June 30, 2013 and 2012, respectively, consisted of the following:

                                              Three Months Ended
                                                   June 30,
                                               2013        2012
                                                 (unaudited)

Long-term contract revenue                  $   20,596   $  27,661
Short-term contract revenue                     10,875       9,400
Fee-based revenue                               31,471      37,061

Realized optimization, net                       5,600      33,621
Unrealized risk management gains (losses)       20,118     (51,188 )
Write-down of inventory                              -     (22,281 )
Optimization revenue, net                   $   25,718   $ (39,848 )

Changes in revenue in the quarter were primarily attributable to the following:

LTF Revenues. LTF revenues for the three months ended June 30, 2013 declined by $7.1 million (26%) compared to the three months ended June 30, 2012. This decline was due in part to our decision to allocate 22 Bcf less storage capacity to this strategy than in the previous year. In addition, lower average rates for LTF contracts were obtained in the three months ended June 30, 2013 compared to the three months ended June 30, 2012.

STF Revenues. STF revenues for the three months ended June 30, 2013 increased by $1.5 million (16%) compared to the three months ended June 30, 2012. These increases resulted from more capacity being utilized for this strategy compared to the respective period in the prior year.

Optimization Revenues. Total optimization revenues, increased to $25.7 million from net losses of $39.8 million in fiscal 2013. When evaluating the performance of our optimization business, we focus on our realized optimization margins, excluding the impact of unrealized economic hedging gains and losses and inventory write-downs. For financial reporting purposes, our net 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 all inventory is economically hedged, any inventory write-downs are offset by hedging gains and any unrealized hedging losses are offset by realized gains from the sale of physical inventory. The components of optimization revenues are as follows:

Realized Optimization Revenue, net. Realized optimization of $5.6 million in the current quarter decreased by $28.0 million from $33.6 million in the first quarter of the previous year. This decrease resulted from a significant reduction in realized gains from financial hedges in the three months ended June 30, 2013, compared to the same period last year. During the first quarter of the prior year, we realized substantial gains on financial hedges for proprietary inventories that had been positioned for sale in spring and early summer. These financial gains were not offset by realized physical losses because conditions in the natural gas storage market provided incentives to carry that inventory to future periods. In the three months ended June 30, 2013, we carried significantly less proprietary inventory over year end and therefore had substantially fewer hedges positioned for realization in the first quarter. During the three month period ended June 30, 2013, we realized losses on these financial hedges as a result of increases in natural gas prices relative to the sales contracts that settled during the period. However, these losses were more than offset by gains on physical deliveries, as the natural gas storage markets encouraged us to store proprietary inventories for shorter periods. Typically, the recognition of revenue from proprietary optimization activities is lower in the summer months and higher in the winter months as we purchase inventory in the summer for delivery in later periods. In FY2014, realized


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optimization is expected to reflect patterns of a more typical storage year. The three month period ended June 30, 2013 also included $2.5 million in optimization revenue related to our marketing business, compared to $2.4 million realized during the three month period ended June 30, 2012.

Unrealized Risk Management Gains (Losses). Unrealized risk management gains in the three month period ended June 30, 2013 resulted from increases in the value of financial hedges as a result of natural gas prices decreasing relative to average sales contract prices in future months. In the prior year, unrealized risk management losses resulted from decreases in the value of financial hedges due to increases in natural gas prices relative to the average sales contract prices for the three month period, as well as the realization during the period of significant amounts of previously unrealized gains. The three month period ended June 30, 2013 also included $3.8 million in unrealized risk management losses related to our marketing business, compared to $0.6 million in unrealized risk management gains during the three month period ended June 30, 2012. The unrealized risk management losses in the marketing business in the three month period ended June 30, 2013 resulted from decreases in the value of financial hedges as a result of natural gas prices decreasing relative to average purchase contract prices in future months.

Write-Down of Inventory. During the fourth quarter of fiscal 2012, near-term prices of natural gas fell dramatically. This reduction increased the value of our economic hedges and decreased the value of the proprietary optimization inventory underlying those hedges. Concurrently, the steepening of the forward curve at that time as noted above encouraged us to realize incremental revenues through the repositioning of inventory deliveries from the fourth quarter of fiscal 2012 into future periods in fiscal 2013 or beyond. Natural gas prices continued to fall during the first quarter of fiscal 2013. Consequently, the market value of our inventories fell below the carrying cost by the end of the first quarter and we wrote down our proprietary inventories by $22.3 million to the lower of cost or market value. No write-down occurred in the current period.

Operating Expenses



Operating expenses for the three months ended June 30, 2013 and 2012 consisted
of the following:



                                   Three Months Ended
                                        June 30,
                                    2013         2012
                                      (unaudited)

Lease costs and property taxes   $     3,625    $ 3,548
Fuel and electricity                   3,551      1,905
Salaries and benefits                  1,821      1,434
Maintenance                              826        649
General operating costs                  621        555
Total operating expenses         $    10,444    $ 8,091

Operating expenses for the quarter ended June 30, 2013 increased by $2.4 million (29%) compared to the quarter ended June 30, 2012. A 57% increase in cycled volumes resulting in increased fuel and power consumption, combined with high power prices led to an increase of $1.6 million in fuel and electricity costs compared to the same period in the prior year.

General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2013 and 2012 consisted of the following:


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                                                          Three Months Ended
                                                               June 30,
                                                         2013             2012
                                                              (unaudited)

Compensation costs                                   $       7,077    $      5,920
General costs, including office and information
technology costs                                             1,208           1,339
Legal, audit and regulatory costs                            3,005           2,580
Total general and administrative expenses            $      11,290    $      9,839

General and administrative expenses for the quarter ended June 30, 2013 increased by $1.5 million (15%) compared to the quarter ended June 30, 2012. Compensation costs increased principally as a result of higher incentive compensation accruals principally related to long-term compensation plans.

Depreciation and Amortization Expense

Depreciation and amortization expense for the quarter ended June 30, 2013 decreased by $1.5 million (13%) compared to the quarter ended June 30, 2012. The decrease for the three month period was primarily attributable to a reduction in cushion gas migration at one of our facilities ($2.4 million), offset by additional depreciation from equipment purchased as part of our capacity expansion ($0.9 million).

Interest Expense



                                          Three Months Ended
                                               June 30,
                                           2013         2012
                                             (unaudited)

Interest on senior notes                $    14,284   $ 14,284
Interest on revolving credit facility           806      2,561
Amortization of deferred charges                835        908
Other interest                                  281        377
                                             16,206     18,130

Less: Capitalized interest                        -      1,622
Total interest expenses                 $    16,206   $ 16,508

Interest expense for the three months ended June 30, 2013 decreased by $0.3 million (2%) compared to the three months ended June 30, 2012 as a result of lower utilization of the revolving credit facility, offset by an absence of capitalized interest due to the completion of a project at our Wild Goose facility in fiscal 2013.

Loss on Extinguishment of Debt

We amended and restated our $400 million Credit agreement on June 29, 2012. The write-off of a portion of deferred financing costs associated with the prior agreement resulted in a loss on debt extinguishment of $0.6 million in the prior period.

Income Taxes

Income tax benefit was $0.3 million for the three months ended June 30, 2013 compared to a benefit of $11.9 million for the same period of the prior year. Income tax benefit in the current three month period is primarily due to the Canadian subsidiaries recognizing aggregate losses for tax purposes in the period.


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The effective tax rate for the three months ended June 30, 2013 differs from the U.S. statutory federal rate of 35% primarily due to the recognition of losses in taxable entities which have a lower statutory rate.

Liquidity and Capital Resources

Sources and Uses of Liquidity

Our primary short-term liquidity needs are to pay interest and principal payments under our $400 million Credit Agreement and interest payments on our 8.875% Senior Notes due 2018 (the "Senior Notes"), to fund our operating expenses and maintenance capital expenditures, 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 million Credit Agreement.

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.

Our principal debt covenant is our fixed charge coverage ratio ("FCCR"), which is included in both our $400 million Credit Agreement and the indenture on our Senior Notes. When our FCCR, which is calculated on a trailing-twelve month 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 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 June 30, 2013, our FCCR was 2.1 to 1.0. If our fixed charge coverage ratio were to fall 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.

In order to enhance our financial flexibility, in June 2012 we amended and restated our $400 million Credit Agreement. The new agreement is substantially the same as the prior agreement, except that the maturity has been extended from March 5, 2014 to June 29, 2016, and pricing has been improved due to a more favorable pricing grid based on leverage levels and the elimination of a floor of 150 basis points on LIBOR-based borrowings. At June 30, 2013, we had $11.0 million in borrowings, $25.4 million committed in support of letters of credit and $363.6 million of unutilized capacity related to our credit facility.

We believe that our existing sources of liquidity described above will be sufficient to fund our short-term liquidity needs through the upcoming twelve month period. 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.

Management does not believe that the operation of its existing business is impacted by the availability of capital for expansion projects or acquisitions.


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Cash Flows from Operations and Investing Activities



The following table summarizes our sources and uses of cash for the three months
ended June 30, 2013 and 2012, respectively:



                                                            Three Months Ended
                                                                 June 30,
                                                           2013             2012
                                                                (unaudited)
Operating Activities:
Net earnings (loss)                                    $       7,967    $    (37,346 )
Adjustments to reconcile net earnings (loss) to net
cash provided by operating activities:
Unrealized foreign exchange losses (gains)                       980             (83 )
Deferred income tax benefit                                     (300 )       (11,934 )
Unrealized risk management (gains) losses                    (20,118 )        51,148
Depreciation and amortization                                 10,333          11,824
Deferred charges amortization                                    835             908
. . .
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