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NFG > SEC Filings for NFG > Form 10-K on 21-Nov-2012All Recent SEC Filings

Show all filings for NATIONAL FUEL GAS CO

Form 10-K for NATIONAL FUEL GAS CO


21-Nov-2012

Annual Report


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

OVERVIEW

The Company is a diversified energy company and reports financial results for four business segments. Refer to Item 1, Business, for a more detailed description of each of the segments. This Item 7, MD&A, provides information concerning:

1. The critical accounting estimates of the Company;

2. Changes in revenues and earnings of the Company under the heading, "Results of Operations;"

3. Operating, investing and financing cash flows under the heading "Capital Resources and Liquidity;"

4. Off-Balance Sheet Arrangements;

5. Contractual Obligations; and

6. Other Matters, including: (a) 2012 and projected 2013 funding for the Company's pension and other post-retirement benefits; (b) disclosures and tables concerning market risk sensitive instruments; (c) rate and regulatory matters in the Company's New York, Pennsylvania and FERC regulated jurisdictions; (d) environmental matters; and (e) new authoritative accounting and financial reporting guidance.

The information in MD&A should be read in conjunction with the Company's financial statements in Item 8 of this report.

For the year ended September 30, 2012 compared to the year ended September 30, 2011, the Company experienced a decrease in earnings of $38.3 million. The earnings decrease is primarily due to the recognition of a gain on the sale of unconsolidated subsidiaries of $50.9 million ($31.4 million after tax) during the quarter ended March 31, 2011 in the All Other category that did not recur during the year ended September 30, 2012. In February 2011, the Company sold its 50% equity method investments in Seneca Energy and Model City for $59.4 million. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. The sale was the result of the Company's strategy to pursue the sale of

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smaller, non-core assets in order to focus on its core businesses, including the development of the Marcellus Shale and the expansion of its pipeline business throughout the Appalachian region. Lower earnings in the Exploration and Production segment, Utility segment and Energy Marketing segment also contributed to the decrease in earnings, partly offset by higher earnings in the Pipeline and Storage segment. For further discussion of the Company's earnings, refer to the Results of Operations section below.

The Company's natural gas reserve base has grown substantially in recent years due to its development of reserves in the Marcellus Shale, a Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York. The Company controls the natural gas interests associated with approximately 775,000 net acres within the Marcellus Shale area, with a majority of the interests held in fee, carrying no royalty and no lease expirations. Natural gas proved developed and undeveloped reserves in the Appalachian region increased from 607 Bcf at September 30, 2011 to 925 Bcf at September 30, 2012. The Company has spent significant amounts of capital in this region related to the development of such reserves. For the year ended September 30, 2012, the Company's Exploration and Production segment had capital expenditures of $630.9 million in the Appalachian region, of which $567.9 million was spent towards the development of the Marcellus Shale. However, while the Company remains focused on the development of the Marcellus Shale, the current low natural gas price environment has caused the Company to reduce its capital spending plans for fiscal 2013. The Company's fiscal 2013 estimated capital expenditures in the Appalachian region are expected to be approximately $405.3 million. Despite the reduction in capital expenditures, forecasted production in the Appalachian region for fiscal 2013 is expected to be in the range of 75 to 85 Bcfe, up from actual production of 63 Bcfe in fiscal 2012.

While the Company's development of its Marcellus Shale acreage in the Exploration and Production segment has slowed, the Company's Pipeline and Storage segment continues to build pipeline gathering and transmission facilities to connect Marcellus Shale production with existing pipelines in the region and is pursuing the development of additional pipeline and storage capacity in order to meet anticipated demand for the large amount of Marcellus Shale production expected to come on-line in the months and years to come. One such project, Empire's Tioga County Extension Project, was placed in service in November 2011. Supply Corporation's Northern Access expansion project is also considered significant. Just like the Tioga County Extension Project, the Northern Access expansion project is designed to receive natural gas produced from the Marcellus Shale and transport it to Canada and the Northeast United States to meet growing demand in those areas. Initial service through the Northern Access expansion project began on November 1, 2012, with full service expected by the end of December 2012. These projects, which are further discussed in the Investing Cash Flow section that follows, have or will involve significant capital expenditures.

From a capital resources perspective, the Company has largely been able to meet its capital expenditure needs for all of the above projects by using cash from operations as well as short-term debt. In addition, the Company's December 2011 issuance of $500.0 million of 4.90% notes due in December 2021 enhanced its liquidity position to meet these needs. On January 6, 2012, the Company replaced its $300.0 million committed credit facility with an Amended and Restated Credit Agreement totaling $750.0 million that extends to January 6, 2017. Going forward, the Company plans to continue its use of short-term debt and expects to issue long-term debt in fiscal 2013 to help meet its capital expenditure needs as well as to replace long-term debt that matures in March 2013.

The well completion technology referred to as hydraulic fracturing used in conjunction with horizontal drilling continues to be debated. In Pennsylvania, where the Company is focusing its Marcellus Shale development efforts, the permitting and regulatory processes seem to strike a balance between the environmental concerns associated with hydraulic fracturing and the benefits of increased natural gas production. Hydraulic fracturing is a well stimulation technique that has been used for many years, and in the Company's experience, one that the Company believes has little negative impact to the environment. Nonetheless, the potential for increased state or federal regulation of hydraulic fracturing could impact future costs of drilling in the Marcellus Shale and lead to operational delays or restrictions. There is also the risk that drilling could be prohibited on certain acreage that is prospective for the Marcellus Shale. Please refer to the Risk Factors section above for further discussion.

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CRITICAL ACCOUNTING ESTIMATES

The Company has prepared its consolidated financial statements in conformity with GAAP. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company's most critical accounting estimates, which are defined as those estimates whereby judgments or uncertainties could affect the application of accounting policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company's significant accounting policies, refer to Item 8 at Note A - Summary of Significant Accounting Policies.

Oil and Gas Exploration and Development Costs. In the Company's Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.

The Company believes that determining the amount of the Company's proved reserves is a critical accounting estimate. Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full cost method of accounting (on a units-of-production basis). Unproved properties are excluded from the depletion calculation until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.

In addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in oil and gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment charge must be recorded to

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write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. At September 30, 2012, the ceiling exceeded the book value of the Company's oil and gas properties by approximately $55.3 million. The 12-month average of the first day of the month price for crude oil for each month during 2012, based on posted Midway Sunset prices, was $105.09 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during 2012, based on the quoted Henry Hub spot price for natural gas, was $2.83 per MMBtu. (Note - Because actual pricing of the Company's various producing properties varies depending on their location and hedging, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for 2012.) If natural gas average prices used in the ceiling test calculation at September 30, 2012 had been $1 per MMBtu lower, the book value of the Company's oil and gas properties would have exceeded the ceiling by approximately $173.9 million, which would have resulted in an impairment charge. If crude oil average prices used in the ceiling test calculation at September 30, 2012 had been $5 per Bbl lower, the ceiling would have exceeded the book value of the Company's oil and gas properties by approximately $10.3 million which would not have resulted in an impairment charge. If both natural gas and crude oil average prices used in the ceiling test calculation at September 30, 2012 were lower by $1 per MMBtu and $5 per Bbl, respectively, the book value of the Company's oil and gas properties would have exceeded the ceiling by approximately $221.3 million, which would have resulted in an impairment charge. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation.

It is difficult to predict what factors could lead to future impairments under the SEC's full cost ceiling test. As discussed above, fluctuations in or subtractions from proved reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time.

In accordance with the current authoritative guidance for asset retirement obligations, the Company records an asset retirement obligation for plugging and abandonment costs associated with the Exploration and Production segment's crude oil and natural gas wells and capitalizes such costs in property, plant and equipment (i.e. the full cost pool). Under the current authoritative guidance for asset retirement obligations, since plugging and abandonment costs are already included in the full cost pool, the units-of-production depletion calculation excludes from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.

As discussed above, the full cost method of accounting provides a ceiling to the amount of costs that can be capitalized in the full cost pool. In accordance with current authoritative guidance, the future cash outflows associated with plugging and abandoning wells are excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation.

Regulation. The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting principles for certain types of rate-regulated activities provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company's regulatory assets and liabilities, refer to Item 8 at Note C - Regulatory Matters.

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Accounting for Derivative Financial Instruments. The Company, in its Exploration and Production segment, Energy Marketing segment, and Pipeline and Storage segment, uses or has used a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments are categorized as price swap agreements and futures contracts. In accordance with the authoritative guidance for derivative instruments and hedging activities, the Company accounted for these instruments as effective cash flow hedges or fair value hedges. Gains or losses associated with the derivative financial instruments are matched with gains or losses resulting from the underlying physical transaction that is being hedged. To the extent that the derivative financial instruments would ever be deemed to be ineffective based on the effectiveness testing, mark-to-market gains or losses from the derivative financial instruments would be recognized in the income statement without regard to an underlying physical transaction.

The Company uses both exchange-traded and non exchange-traded derivative financial instruments. The Company follows the authoritative guidance for fair value measurements. As such, the fair value of such derivative financial instruments is determined under the provisions of this guidance. The fair value of exchange traded derivative financial instruments is determined from Level 1 inputs, which are quoted prices in active markets. The Company determines the fair value of non exchange-traded derivative financial instruments based on an internal model, which uses both observable and unobservable inputs other than quoted prices. These inputs are considered Level 2 or Level 3 inputs. All derivative financial instrument assets and liabilities are evaluated for the probability of default by either the counterparty or the Company. Credit reserves are applied against the fair values of such assets or liabilities. Refer to the "Market Risk Sensitive Instruments" section below for further discussion of the Company's derivative financial instruments.

Pension and Other Post-Retirement Benefits. The amounts reported in the Company's financial statements related to its pension and other post-retirement benefits are determined on an actuarial basis, which uses many assumptions in the calculation of such amounts. These assumptions include the discount rate, the expected return on plan assets, the rate of compensation increase and, for other post-retirement benefits, the expected annual rate of increase in per capita cost of covered medical and prescription benefits. The Company utilizes a yield curve model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year's anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments. The expected return on plan assets assumption used by the Company reflects the anticipated long-term rate of return on the plan's current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan's target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets. Changes in actuarial assumptions and actuarial experience, including deviations between actual versus expected return on plan assets, could have a material impact on the amount of pension and post-retirement benefit costs and funding requirements experienced by the Company. However, the Company expects to recover a substantial portion of its net periodic pension and other post-retirement benefit costs attributable to employees in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization, subject to applicable accounting requirements for rate-regulated activities, as discussed above under "Regulation."

Changes in actuarial assumptions and actuarial experience could also have an impact on the benefit obligation and the funded status related to the Company's pension and other post-retirement benefits and could impact the Company's equity. For example, the discount rate was changed from 4.50% in 2011 to 3.50% in 2012. The change in the discount rate from 2011 to 2012 increased the Retirement Plan projected benefit obligation by $118.8 million and the accumulated post-retirement benefit obligation by $65.6 million. Other examples include actual versus expected return on plan assets, which has an impact on the funded status of the plans, and actual versus expected benefit payments, which has an impact on the pension plan projected benefit obligation and the accumulated post-retirement benefit obligation. For 2012, the actual return on plan assets exceeded the expected return, which improved the funded status of the Retirement Plan

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($51.3 million) as well as the VEBA trusts and 401(h) accounts ($34.6 million). The actual versus expected benefit payments for 2012 caused a decrease of $2.4 million to the accumulated post-retirement benefit obligation. In calculating the projected benefit obligation for the Retirement Plan and the accumulated post-retirement obligation, the actuary takes into account the average remaining service life of active participants. The average remaining service life of active participants is 8 years for the Retirement Plan and 7 years for those eligible for other post-retirement benefits. For further discussion of the Company's pension and other post-retirement benefits, refer to Other Matters in this Item 7, which includes a discussion of funding for the current year, and to Item 8 at Note H - Retirement Plan and Other Post Retirement Benefits.

RESULTS OF OPERATIONS

EARNINGS

2012 Compared with 2011

The Company's earnings were $220.1 million in 2012 compared with earnings of $258.4 million in 2011. The decrease in earnings of $38.3 million is primarily the result of lower earnings in the All Other category, Exploration and Production segment, Utility segment and Energy Marketing segment. Higher earnings in the Pipeline and Storage segment and a lower loss in the Corporate category partly offset these decreases. In the discussion that follows, all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by the following events in 2012 and 2011:

2012 Events

The elimination of Supply Corporation's other post-retirement regulatory liability of $12.8 million recorded in the Pipeline and Storage segment, as specified by Supply Corporation's rate case settlement; and

A natural gas impact fee imposed by the Commonwealth of Pennsylvania in 2012 on the drilling of wells in the Marcellus Shale by the Exploration and Production segment. This fee included $4.0 million related to wells drilled prior to 2012. See further discussion of the impact fee that follows under the heading "Exploration and Production."

2011 Event

A $50.9 million ($31.4 million after tax) gain on the sale of unconsolidated subsidiaries as a result of the Company's sale of its 50% equity method investments in Seneca Energy and Model City.

2011 Compared with 2010

The Company's earnings were $258.4 million in 2011 compared with earnings of $225.9 million in 2010. The Company had earnings from discontinued operations of $6.8 million in 2010 but did not have any earnings from discontinued operations in 2011. The Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana in September 2010. Accordingly, all financial results for those operations, which were part of the All Other category, have been presented as discontinued operations. The Company's earnings from continuing operations were $258.4 million in 2011 and $219.1 million in 2010. The increase in earnings from continuing operations of $39.3 million was primarily the result of higher earnings in the Exploration and Production segment and the All Other category. The increase in the All Other category was due to the gain on sale of the Company's 50% equity method investments in Seneca Energy and Model City. The Utility segment also contributed to the increase in earnings. Lower earnings in the Pipeline and Storage segment and a higher loss in the Corporate category slightly offset these increases. Earnings from continuing operations and discontinued operations were also impacted by the following event in 2010:

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2010 Event

A $6.3 million gain on the sale of the Company's landfill gas operations, which was completed in September 2010. This amount is included in earnings from discontinued operations.

Earnings (Loss) by Segment



                                                       Year Ended September 30
                                                 2012           2011           2010
                                                             (Thousands)
   Utility                                     $  58,590      $  63,228      $  62,473
   Pipeline and Storage                           60,527         31,515         36,703
   Exploration and Production                     96,498        124,189        112,531
   Energy Marketing                                4,169          8,801          8,816

   Total Reported Segments                       219,784        227,733        220,523
   All Other                                       6,868         38,502          3,396
   Corporate                                      (6,575 )       (7,833 )       (4,786 )

   Total Earnings from Continuing Operations     220,077        258,402        219,133
   Earnings from Discontinued Operations               -              -          6,780

   Total Consolidated                          $ 220,077      $ 258,402      $ 225,913
. . .
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