UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the Fiscal Year Ended September 30, 2007

 

OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the Transition Period from           to          

 

Commission File Number 1-3880

 

 

(716) 857-7000

Registrant’s telephone number, including area code

 

 

 

Securities registered pursuant to Section 12(g) of the Act:

None

 

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

 

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

 

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 and (2) has been subject to such filing requirements for the past 90 days.  Yes  þ      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 the 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.   þ

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer  þ      Accelerated Filer  o      Non-Accelerated Filer  o      

 

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

 

The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $3,540,898,000 as of March 31, 2007.

 

Common Stock, $1 Par Value, outstanding as of October 31, 2007: 83,473,107 shares.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the registrant’s definitive Proxy Statement for its 2008 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

 

 

Glossary of Terms

 

Frequently used abbreviations, acronyms, or terms used in this report:

 

  National Fuel Gas Companies

 

 

Company The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure

 

Data-Track Data-Track Account Services, Inc.

 

Distribution Corporation National Fuel Gas Distribution Corporation

 

Empire Empire State Pipeline

 

ESNE Energy Systems North East, LLC

 

Highland Highland Forest Resources, Inc.

 

Horizon Horizon Energy Development, Inc.

 

Horizon B.V. Horizon Energy Development B.V.

 

Horizon LFG Horizon LFG, Inc.

 

Horizon Power Horizon Power, Inc.

 

Leidy Hub Leidy Hub, Inc.

 

Model City Model City Energy, LLC

 

National Fuel National Fuel Gas Company

 

NFR National Fuel Resources, Inc.

 

Registrant National Fuel Gas Company

 

SECI Seneca Energy Canada Inc.

 

Seneca Seneca Resources Corporation

 

Seneca Energy Seneca Energy II, LLC

 

Supply Corporation National Fuel Gas Supply Corporation

 

Toro Toro Partners, LP

 

U.E. United Energy, a.s.

 

  Regulatory Agencies

 

 

EPA United States Environmental Protection Agency

 

FASB Financial Accounting Standards Board

 

FERC Federal Energy Regulatory Commission

 

NTSB National Transportation Safety Board

 

NYDEC New York State Department of Environmental Conservation

 

NYPSC State of New York Public Service Commission

 

PaPUC Pennsylvania Public Utility Commission

 

SEC Securities and Exchange Commission

 

  Other

 

 

APB 18 Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock

 

APB 20 Accounting Principles Board Opinion No. 20, Accounting Changes

 

APB 25 Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees

 

Bbl Barrel (of oil)

 

Bcf Billion cubic feet (of natural gas)

 

Bcfe (or Mcfe) — represents Bcf (or Mcf) Equivalent The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. National Fuel uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.

 

Board foot A measure of lumber and/or timber equal to 12 inches in length by 12 inches in width by one inch in thickness.

 

Btu British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.

 

Capital expenditure Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.

 

Cashout revenues A cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas the customer receives in excess of amounts delivered into Supply Corporation’s system by the customer’s shipper.

 

CTA Cumulative Foreign Currency Translation Adjustment

 

Degree day A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.

 

Derivative A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net, and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.

 

Development costs Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.

 

Development well A well drilled to a known producing formation in a previously discovered field.

 

Dth Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.

 

Exchange Act Securities Exchange Act of 1934, as amended

 

Expenditures for long-lived assets Includes capital expenditures, stock acquisitions and/or investments in partnerships.

 

Exploitation Development of a field, including the location, drilling, completion and equipment of wells necessary to produce the commercially recoverable oil and gas in the field.

 

Exploration costs Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.

 

Exploratory well A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.

 

FIN  FASB Interpretation Number

 

FIN 47 FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations — an Interpretation of SFAS 143.

 

FIN 48 FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of SFAS 109.

 

Firm transportation and/or storage The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.

 

GAAP  Accounting principles generally accepted in the United States of America

 

Goodwill An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.

 

Grid The layout of the electrical transmission system or a synchronized transmission network.

 

Heavy oil A type of crude petroleum that usually is not economically recoverable in its natural state without being heated or diluted.

 

Hedging A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.

 

Hub Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.

 

Interruptible transportation and/or storage The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.

 

LIBOR London Interbank Offered Rate

 

LIFO Last-in, first-out

 

Mbbl Thousand barrels (of oil)

 

Mcf Thousand cubic feet (of natural gas)

 

MD&A Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

MDth Thousand decatherms (of natural gas)

 

MMcf Million cubic feet (of natural gas)

 

MMcfe Million cubic feet equivalent

 

NYMEX New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.

 

Order 636 An order issued by FERC entitled “Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission’s Regulations.”

 

Proved developed reserves Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

 

Proved undeveloped reserves Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive.

 

PRP Potentially responsible party

 

PUHCA 1935 Public Utility Holding Company Act of 1935

 

PUHCA 2005 Public Utility Holding Company Act of 2005

 

Reserves The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.

 

Restructuring Generally referring to partial “deregulation” of the utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundled”) of gas commodity service from transportation service for wholesale and large- volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets.

 

SAR Stock-settled stock appreciation right

 

SFAS  Statement of Financial Accounting Standards

 

SFAS 5 Statement of Financial Accounting Standards No. 5, Accounting for Contingencies

 

SFAS 43 Statement of Financial Accounting Standards No. 43, Accounting for Compensated Absences

 

SFAS 69 Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities

 

SFAS 71 Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation

 

 

For the Fiscal Year Ended September 30, 2007

 

CONTENTS

 

This Form 10-K contains “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements included in this Form 10-K at Item 7, MD&A, under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, statements regarding future prospects, plans, performance and capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” and “may” and similar expressions.

 

In 2007, Seneca sold its subsidiary, Seneca Energy Canada Inc. (SECI), which conducted Exploration and Production operations in the provinces of Alberta, Saskatchewan and British Columbia in Canada. At September 30, 2007, the Company had U.S. reserves of 47,586 Mbbl of oil and 205,389 MMcf of natural gas.

 

4. The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation, which markets natural gas to industrial, commercial, public authority and residential end-users in western and central New York and northwestern Pennsylvania, offering competitively priced energy and energy management services for its customers.

 

5. The Timber segment operations are carried out by Highland Forest Resources, Inc. (Highland), a New York corporation, and by a division of Seneca known as its Northeast Division. This segment markets timber from its New York and Pennsylvania land holdings, owns two sawmill operations in northwestern Pennsylvania and processes timber consisting primarily of high quality hardwoods. At September 30, 2007, the Company owned 103,700 acres of timber property and managed an additional 3,105 acres of timber rights.

 

Financial information about each of the Company’s business segments can be found in Item 7, MD&A and also in Item 8 at Note J — Business Segment Information.

 

The Company’s other direct wholly owned subsidiaries are not included in any of the five reportable business segments and consist of the following:

 

 

No single customer, or group of customers under common control, accounted for more than 10% of the Company’s consolidated revenues in 2007.

 

Rates and Regulation

 

The Registrant is a holding company as defined under PUHCA 2005. PUHCA 2005 repealed PUHCA 1935, to which the Company was formerly subject, and granted the FERC and state public utility commissions access to certain books and records of companies in holding company systems. Pursuant to the FERC’s regulations under PUHCA 2005, the Company and its subsidiaries are exempt from the FERC’s books and records regulations under PUHCA 2005.

The Utility segment’s rates, services and other matters are regulated by the NYPSC with respect to services provided within New York and by the PaPUC with respect to services provided within Pennsylvania. For additional discussion of the Utility segment’s rates and regulation, see Item 7, MD&A under the heading “Rate and Regulatory Matters” and Item 8 at Note C-Regulatory Matters.

 

The Pipeline and Storage segment’s rates, services and other matters are currently regulated by the FERC with respect to Supply Corporation and by the NYPSC with respect to Empire. The FERC has authorized Empire to construct and operate additional facilities (the Empire Connector project) and to become a FERC-regulated interstate pipeline company upon placement of those facilities into service, which is currently expected to occur in November 2008. For additional discussion of the Pipeline and Storage segment’s rates and regulation, see Item 7, MD&A under the heading “Rate and Regulatory Matters” and Item 8 at Note C-Regulatory Matters. For further discussion of the Empire Connector project, refer to Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters.”

 

The discussion under Item 8 at Note C-Regulatory Matters includes a description of the regulatory assets and liabilities reflected on the Company’s Consolidated Balance Sheets in accordance with applicable accounting standards. To the extent that the criteria set forth in such accounting standards are not met by the operations of the Utility segment or the Pipeline and Storage segment, as the case may be, the related regulatory assets and liabilities would be eliminated from the Company’s Consolidated Balance Sheets and such accounting treatment would be discontinued.

 

In addition, the Company and its subsidiaries are subject to the same federal, state and local (including foreign) regulations on various subjects, including environmental matters, to which other companies doing similar business in the same locations are subject.

 

The Utility Segment

 

The Utility segment contributed approximately 25.2% of the Company’s 2007 income from continuing operations and 15.1% of the Company’s 2007 net income available for common stock.

 

Additional discussion of the Utility segment appears below in this Item 1 under the headings “Sources and Availability of Raw Materials,” “Competition: The Utility Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

 

The Pipeline and Storage Segment

 

The Pipeline and Storage segment contributed approximately 28.0% of the Company’s 2007 income from continuing operations and 16.7% of the Company’s 2007 net income available for common stock.

 

Supply Corporation has service agreements for all of its firm storage capacity, which totals approximately 68,408 MDth. The Utility segment has contracted for 27,865 MDth or 40.7% of the total firm storage capacity, and the Energy Marketing segment accounts for another 3,888 MDth or 5.7% of the total firm storage capacity. Nonaffiliated customers have contracted for the remaining 36,655 MDth or 53.6% of the total firm storage capacity. A majority of Supply Corporation’s storage and transportation services is performed under contracts that allow Supply Corporation or the shipper to terminate the contract upon six or twelve months’ notice effective at the end of the contract term. The contracts also typically include “evergreen” language designed to allow the contracts to extend year-to-year at the end of the primary term. At the beginning of 2008, 66.9% of Supply Corporation’s total firm storage capacity was committed under contracts that, subject to 2007 shipper or Supply Corporation notifications, could have been terminated effective in 2008. Supply Corporation received one termination notice in 2007, for a 1.5 Bcf storage contract. Termination of that contract will be effective March 31, 2008, and Supply Corporation expects to remarket that capacity for service commencing April 1, 2008, at maximum tariff rates. The strong demand for market-area storage enabled Supply Corporation to eliminate its remaining storage service rate discounts in 2007. Supply Corporation anticipates that, effective April 1, 2008, all of its storage services will be contracted at the maximum tariff rates.

 

Supply Corporation’s firm transportation capacity is not a fixed quantity, due to the diverse weblike nature of its pipeline system, and is subject to change as the market identifies different transportation paths and receipt/delivery

point combinations. Supply Corporation currently has firm transportation service agreements for approximately 2,001 MDth per day (contracted transportation capacity). The Utility segment accounts for approximately 1,093 MDth per day or 54.6% of contracted transportation capacity, and the Energy Marketing and Exploration and Production segments represent another 100 MDth per day or 5.0% of contracted transportation capacity. The remaining 808 MDth or 40.4% of contracted transportation capacity is subject to firm contracts with nonaffiliated customers.

 

At the beginning of 2008, 58.0% of Supply Corporation’s contracted transportation capacity was committed under affiliate contracts that were scheduled to expire in 2008 or, subject to 2007 shipper or Supply Corporation notifications, could have been terminated effective in 2008. Based on contract expirations and termination notices received in 2007 for 2008 termination, and taking into account any known contract additions, contracted transportation capacity with affiliates is expected to decrease 2.5% in 2008. Similarly, 24.3% of contracted transportation capacity was committed under unaffiliated shipper contracts that were scheduled to expire in 2008 or, subject to 2007 shipper or Supply Corporation notifications, could have been terminated effective in 2008. Based on contract expirations and termination notices received in 2007 for 2008 termination, and taking into account any known contract additions, contracted transportation capacity with unaffiliated shippers is expected to increase 2.1% in 2008. Supply Corporation previously has been successful in marketing and obtaining executed contracts for available transportation capacity (at discounted rates when necessary), and expects this success to continue.

 

Empire has service agreements for the 2007-2008 winter period for all of its firm transportation capacity, which totals approximately 565 MDth per day. Empire provides service under both annual contracts (service 12 months per year; contract term one or more years) and seasonal contracts (service during winter or summer only; contract term one or more partial years). Approximately 90.8% of Empire’s firm contracted capacity is under multi-year annual contracts that expire after 2008. Approximately 2.7% of Empire’s firm contracted capacity is under multi-year seasonal contracts that expire after 2008. The remaining capacity, which represents 6.5% of Empire’s firm contracted capacity, is under single season or annual contracts which will expire before the end of 2008. Empire expects that all of this expiring capacity will be re-contracted under seasonal and/or annual arrangements for future contracting periods. The Utility segment accounts for approximately 7.7% of Empire’s firm contracted capacity, and the Energy Marketing segment accounts for approximately 2.0% of Empire’s firm contracted capacity, with the remaining 90.3% of Empire’s firm contracted transportation capacity subject to contracts with nonaffiliated customers.

 

Additional discussion of the Pipeline and Storage segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Pipeline and Storage Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

 

The Exploration and Production Segment

 

The Exploration and Production segment contributed approximately 37.1% of the Company’s 2007 income from continuing operations and 62.4% of the Company’s 2007 net income available for common stock.

 

Additional discussion of the Exploration and Production segment appears below under the headings “Discontinued Operations,” “Sources and Availability of Raw Materials” and “Competition: The Exploration and Production Segment,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

 

The Energy Marketing Segment

 

The Energy Marketing segment contributed approximately 3.8% of the Company’s 2007 income from continuing operations and 2.3% of the Company’s 2007 net income available for common stock.

 

Additional discussion of the Energy Marketing segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Energy Marketing Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

 

The Timber Segment

 

The Timber segment contributed approximately 1.9% of the Company’s 2007 income from continuing operations and 1.1% of the Company’s 2007 net income available for common stock.

 

Additional discussion of the Timber segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Timber Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

 

All Other Category and Corporate Operations

 

The All Other category and Corporate operations contributed approximately 4.0% of the Company’s 2007 income from continuing operations and 2.4% of the Company’s 2007 net income available for common stock.

 

Additional discussion of the All Other category and Corporate operations appears below in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

 

Discontinued Operations

 

In August 2007, Seneca sold all of the issued and outstanding shares of SECI. SECI’s operations are presented in the Company’s financial statements as discontinued operations.

 

In July 2005, Horizon B.V. sold its entire 85.16% interest in United Energy, a.s. (U.E.), a district heating and electric generation business in the Czech Republic. United Energy’s operations are presented in the Company’s financial statements as discontinued operations.

 

Additional discussion of the Company’s discontinued operations appears in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

 

Sources and Availability of Raw Materials

 

Natural gas is the principal raw material for the Utility segment. In 2007, the Utility segment purchased 79.6 Bcf of gas for core market demand. Gas purchased from producers and suppliers in the southwestern United States and Canada under firm contracts (seasonal and longer) accounted for 85% of these purchases. Purchases of gas on the spot market (contracts for one month or less) accounted for 15% of the Utility segment’s 2007 purchases. Purchases from Chevron Natural Gas (21%), ConocoPhillips Company (15%) and Total Gas & Power North America Inc. (14%) accounted for 50% of the Utility’s 2007 gas purchases. No other producer or supplier provided the Utility segment with more than 10% of its gas requirements in 2007.

 

Supply Corporation transports and stores gas owned by its customers, whose gas originates in the southwestern, mid-continent and Appalachian regions of the United States as well as in Canada. Empire transports gas owned by its customers, whose gas originates in the southwestern and mid-continent regions of the United States as well as in Canada. Additional discussion of proposed pipeline projects appears below under “Competition: The Pipeline and Storage Segment” and in Item 7, MD&A.

 

The Exploration and Production segment seeks to discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as further described in this report in Item 7, MD&A and Item 8 at Note J-Business Segment Information and Note O-Supplementary Information for Oil and Gas Producing Activities.

 

With respect to the Timber segment, Highland requires an adequate supply of timber to process in its sawmill and kiln operations. Forty-nine percent of the timber processed during 2007 in Highland’s sawmill operations came from land owned by the Company’s subsidiaries, and 51% came from outside sources. Timber cut for gas well drilling locations, access roads, and pipelines constituted an increasing portion of Highland’s timber supply, both from land owned by the Company’s subsidiaries and from outside sources. In addition, Highland purchased approximately 6.5 million board feet of green lumber to augment lumber supply for its kiln operations.

 

The Energy Marketing segment depends on an adequate supply of natural gas to deliver to its customers. In 2007, this segment purchased 53 Bcf of natural gas, of which 51 Bcf served core market demands. The remaining

2 Bcf largely represents gas used in operations. The gas purchased by the Energy Marketing segment originates in either the Appalachian or mid-continent regions of the United States or in Canada.

 

Competition

 

Competition in the natural gas industry exists among providers of natural gas, as well as between natural gas and other sources of energy. The natural gas industry has gone through various stages of regulation. Apart from environmental and state utility commission regulation, the natural gas industry has experienced considerable deregulation. This has enhanced the competitive position of natural gas relative to other energy sources, such as fuel oil or electricity, since some of the historical regulatory impediments to adding customers and responding to market forces have been removed. In addition, management believes that the environmental advantages of natural gas have enhanced its competitive position relative to other fuels.

 

The electric industry has been moving toward a more competitive environment as a result of changes in federal law in 1992 and initiatives undertaken by the FERC and various states. It remains unclear what the impact of any further restructuring in response to legislation or other events may be.

 

The Company competes on the basis of price, service and reliability, product performance and other factors. Sources and providers of energy, other than those described under this “Competition” heading, do not compete with the Company to any significant extent.

 

Competition: The Utility Segment

 

The changes precipitated by the FERC’s restructuring of the natural gas industry in Order No. 636, which was issued in 1992, continue to reshape the roles of the gas utility industry and the state regulatory commissions. In both New York and Pennsylvania, Distribution Corporation has retained substantial numbers of residential and small commercial customers as sales customers. However, for many years almost all the industrial and a substantial number of commercial customers have purchased their gas supplies from marketers and utilized Distribution Corporation’s gas transportation services. Regulators in both New York and Pennsylvania have adopted retail competition programs for natural gas supply purchases by the remaining utility sales customers. To date, the Utility segment’s traditional distribution function remains largely unchanged; however, in New York, the Utility segment has instituted a number of programs to accommodate more widespread customer choice. In Pennsylvania, the PaPUC issued a report in October 2005 that concluded “effective competition” does not exist in the retail natural gas supply market statewide. In 2006, the PaPUC reconvened a stakeholder group to explore ways to increase the participation of retail customers in choice programs. A decision by the PaPUC on retail competition matters remains pending.

 

Competition for large-volume customers continues with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment’s service territories without use of the utility’s facilities (i.e., bypass). In addition, competition continues with fuel oil suppliers and may increase with electric utilities making retail energy sales.

 

The Utility segment competes in its most vulnerable markets (the large commercial and industrial markets) by offering unbundled, flexible services. The Utility segment continues to develop or promote new sources and uses of natural gas or new services, rates and contracts. The Utility segment also emphasizes and provides high quality service to its customers.

 

Competition: The Pipeline and Storage Segment

 

Supply Corporation competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and with other companies providing gas storage services. Supply Corporation has some unique characteristics which enhance its competitive position. Its facilities are located adjacent to Canada and the northeastern United States and provide part of the link between gas-consuming regions of the eastern United States and gas-producing regions of Canada and the southwestern, southern and other continental regions of the United States. This location offers the opportunity for increased transportation and storage services in the future.

Empire competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and upstate New York in particular. Empire is well situated to provide transportation from Canadian sourced gas, and its facilities are readily expandable. These characteristics provide Empire the opportunity to compete for an increased share of the gas transportation markets. As noted above, Empire is constructing the Empire Connector project, which will expand its natural gas pipeline and enable Empire to serve new markets in New York and elsewhere in the Northeast. For further discussion of this project, refer to Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters.”

 

Competition: The Exploration and Production Segment

 

The Exploration and Production segment competes with other oil and natural gas producers and marketers with respect to sales of oil and natural gas. The Exploration and Production segment also competes, by competitive bidding and otherwise, with other oil and natural gas producers with respect to exploration and development prospects.

 

To compete in this environment, Seneca originates and acts as operator on certain of its prospects, seeks to minimize the risk of exploratory efforts through partnership-type arrangements, utilizes technology for both exploratory studies and drilling operations, and seeks market niches based on size, operating expertise and financial criteria.

 

Competition: The Energy Marketing Segment

 

The Energy Marketing segment competes with other marketers of natural gas and with other providers of energy management services. Competition in this area is well developed with regard to price and services from local, regional and, more recently, national marketers.

 

Competition: The Timber Segment

 

With respect to the Timber segment, Highland competes with other sawmill operations and with other suppliers of timber, logs and lumber. These competitors may be local, regional, national or international in scope. This competition, however, is primarily limited to those entities which either process or supply high quality hardwoods species such as cherry, oak and maple as veneer logs, saw logs, export logs or lumber ultimately used in the production of high-end furniture, cabinetry and flooring. The Timber segment sells its products in domestic and international markets.

 

Seasonality

 

Variations in weather conditions can materially affect the volume of gas delivered by the Utility segment, as virtually all of its residential and commercial customers use gas for space heating. The effect that this has on Utility segment margins in New York is mitigated by a WNC, which covers the eight-month period from October through May. Weather that is more than 2.2% warmer than normal results in a surcharge being added to customers’ current bills, while weather that is more than 2.2% colder than normal results in a refund being credited to customers’ current bills.

 

Volumes transported and stored by Supply Corporation may vary materially depending on weather, without materially affecting its revenues. Supply Corporation’s allowed rates are based on a straight fixed-variable rate design which allows recovery of fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed to recover only the variable costs associated with actual transportation or storage of gas.

 

Volumes transported by Empire may vary materially depending on weather, which can have a moderate effect on its revenues. Empire’s allowed rates currently are based on a modified fixed-variable rate design, which allows recovery of most fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed to recover variable costs associated with actual transportation of gas, to recover return on equity, and to recover income taxes. When Empire becomes a FERC-regulated interstate pipeline company (which is currently expected to occur in November 2008), Empire’s allowed rates, like Supply Corporation’s, will be based on a

straight fixed-variable design. Under that rate design, weather-related variations in transportation volumes will not materially affect revenues.

 

Variations in weather conditions materially affect the volume of gas consumed by customers of the Energy Marketing segment. Volume variations have a corresponding impact on revenues within this segment.

 

The activities of the Timber segment vary on a seasonal basis and are subject to weather constraints. Traditionally, the timber harvesting season occurs when timber growth is dormant and runs from approximately September to March. The operations conducted in the summer months typically focus on pulpwood and on thinning lower-grade or lower value trees from timber stands to encourage the growth of higher-grade or higher value trees.

 

Capital Expenditures

 

A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading “Investing Cash Flow.”

 

Environmental Matters

 

A discussion of material environmental matters involving the Company is included in Item 7, MD&A under the heading “Environmental Matters” and in Item 8, Note H — Commitments and Contingencies.

 

Miscellaneous

 

The Company and its wholly owned or majority-owned subsidiaries had a total of 1,952 full-time employees at September 30, 2007. Excluding the 23 employees the Company had in its Canadian operations at SECI, this is a decrease of approximately one percent from the 1,970 employees in the Company’s U.S. operations at September 30, 2006.

 

Agreements covering employees in collective bargaining units in New York are scheduled to expire in February 2008. The Company has reached new agreements with the local leadership of those collective bargaining units, and the members of each collective bargaining unit have either approved their respective new agreement or are scheduled to vote on their respective new agreement in December 2007. The new agreements provide for an effective date of February 2008 and an expiration date of February 2013. Certain agreements covering employees in collective bargaining units in Pennsylvania are scheduled to expire in April 2009, and other agreements covering employees in collective bargaining units in Pennsylvania are scheduled to expire in May 2009.

 

The Utility segment has numerous municipal franchises under which it uses public roads and certain other rights-of-way and public property for the location of facilities. When necessary, the Utility segment renews such franchises.

 

The Company makes its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, available free of charge on the Company’s internet website, www.nationalfuelgas.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. The information available at the Company’s internet website is not part of this Form 10-K or any other report filed with or furnished to the SEC.

 

Executive Officers of the Company as of November 15, 2007 (except as otherwise noted)(1)

 

 

 

 

 

As a holding company, National Fuel depends on its operating subsidiaries to meet its financial obligations.

 

National Fuel is a holding company with no significant assets other than the stock of its operating subsidiaries. In order to meet its financial needs, National Fuel relies exclusively on repayments of principal and interest on intercompany loans made by National Fuel to its operating subsidiaries and income from dividends and other cash flow from the subsidiaries. Such operating subsidiaries may not generate sufficient net income to pay upstream dividends or generate sufficient cash flow to make payments of principal or interest on such intercompany loans.

 

National Fuel is dependent on bank credit facilities and continued access to capital markets to successfully execute its operating strategies.

 

In addition to its longer term debt that is issued to the public under its indentures, National Fuel relies upon shorter term bank borrowings and commercial paper to finance a portion of its operations. National Fuel is dependent on these capital sources to provide capital to its subsidiaries to allow them to acquire, maintain and develop their properties. The availability and cost of these credit sources is cyclical and these capital sources may not remain available to National Fuel or National Fuel may not be able to obtain money at a reasonable cost in the future. National Fuel’s ability to borrow under its credit facilities and commercial paper agreements depends on National Fuel’s compliance with its obligations under the facilities and agreements. In addition, all of National Fuel’s short-term bank loans are in the form of floating rate debt or debt that may have rates fixed for very short periods of time. At present, National Fuel has no active interest rate hedges in place to protect against interest rate fluctuations on short-term bank debt. In addition, the interest rates on National Fuel’s short-term bank loans and the ability of National Fuel to issue commercial paper are affected by its debt credit ratings published by Standard & Poor’s Ratings Service, Moody’s Investors Service and Fitch Ratings Service. A ratings downgrade could increase the interest cost of this debt and decrease future availability of money from banks, commercial paper purchasers and other sources. National Fuel believes it is important to maintain investment grade credit ratings to conduct its business.

 

National Fuel’s credit ratings may not reflect all the risks of an investment in its securities.

 

National Fuel’s credit ratings are an independent assessment of its ability to pay its obligations. Consequently, real or anticipated changes in the Company’s credit ratings will generally affect the market value of the specific debt instruments that are rated, as well as the market value of the Company’s common stock. National Fuel’s credit ratings, however, may not reflect the potential impact on the value of its common stock of risks related to structural, market or other factors discussed in this Form 10-K.

 

National Fuel’s need to comply with comprehensive, complex, and sometimes unpredictable government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.

 

While National Fuel generally refers to its Utility segment and its Pipeline and Storage segment as its “regulated segments,” there are many governmental regulations that have an impact on almost every aspect of National Fuel’s businesses. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, which may affect its business in ways that the Company cannot predict.

 

In its Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC and the PaPUC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or if Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover increased costs (including costs that may be incurred in connection with governmental investigations or

proceedings or mandated infrastructure inspection, maintenance or replacement programs), earnings may decrease.

 

In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have sought to establish competitive markets in which customers may purchase supplies of gas from marketers, rather than from utility companies. In June 1999, the Governor of Pennsylvania signed into law the Natural Gas Choice and Competition Act. The Act revised the Public Utility Code relating to the restructuring of the natural gas industry, to permit consumer choice of natural gas suppliers. The early programs instituted to comply with the Act have not resulted in significant change, and many residential customers currently continue to purchase natural gas from the utility companies. In October 2005, the PaPUC concluded that “effective competition” does not exist in the retail natural gas supply market statewide. The PaPUC has reconvened a stakeholder group to explore ways to increase the participation of retail customers in choice programs. In New York, in August 2004, the NYPSC issued its Statement of Policy on Further Steps Toward Competition in Retail Energy Markets. This policy statement has a similar goal of encouraging customer choice of alternative natural gas providers. In 2005, the NYPSC stepped up its efforts to encourage customer choice at the retail residential level, and customer choice activities increased in Distribution Corporation’s New York service territory. In April 2007, the NYPSC, noting that the retail energy marketplace in New York is established and continuing to expand, commenced a review to determine if existing programs initially designed to promote competition had outlived their usefulness and whether the cost of programs currently funded by utility rate payers should be shifted to market competitors. Increased retail choice activities, to the extent they occur, may increase Distribution Corporation’s cost of doing business, put an additional portion of its business at regulatory risk, and create uncertainty for the future, all of which may make it more difficult to manage Distribution Corporation’s business profitably.

 

In its Pipeline and Storage segment, National Fuel is subject to the jurisdiction of the FERC with respect to Supply Corporation, and to the jurisdiction of the NYPSC with respect to Empire. (The FERC has authorized Empire to construct and operate additional facilities (the Empire Connector project). When Empire completes construction and commences operations of the Empire Connector, Empire will at that time become a FERC-regulated pipeline company.) The FERC and the NYPSC, among other things, approve the rates that Supply Corporation and Empire, respectively, may charge to their natural gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. State commissions can also petition the FERC to investigate whether Supply Corporation’s rates are still just and reasonable, and if not, to reduce those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to reduce the rates it charges its natural gas transportation and/or storage customers, or if Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation’s or Empire’s earnings may decrease.

 

National Fuel’s liquidity, and in certain circumstances, its earnings, could be adversely affected by the cost of purchasing natural gas during periods in which natural gas prices are rising significantly.

 

Tariff rate schedules in each of the Utility segment’s service territories contain purchased gas adjustment clauses which permit Distribution Corporation to file with state regulators for rate adjustments to recover increases in the cost of purchased gas. Assuming those rate adjustments are granted, increases in the cost of purchased gas have no direct impact on profit margins. Nevertheless, increases in the cost of purchased gas affect cash flows and can therefore impact the amount or availability of National Fuel’s capital resources. National Fuel has issued commercial paper and used short-term borrowings in the past to temporarily finance storage inventories and purchased gas costs, and although National Fuel expects to do so in the future, it may not be able to access the markets for such borrowings at attractive interest rates or at all. Distribution Corporation is required to file an accounting reconciliation with the regulators in each of the Utility segment’s service territories regarding the costs of purchased gas. Due to the nature of the regulatory process, there is a risk of a disallowance of full recovery of these costs during any period in which there has been a substantial upward spike in these costs. Any material disallowance of purchased gas costs could have a material adverse effect on cash flow and earnings. In addition, even when Distribution Corporation is allowed full recovery of these purchased gas costs, during periods when natural gas prices are significantly higher than historical levels, customers may

have trouble paying the resulting higher bills, and Distribution Corporation’s bad debt expenses may increase and ultimately reduce earnings.

 

Uncertain economic conditions may affect National Fuel’s ability to finance capital expenditures and to refinance maturing debt.

 

National Fuel’s ability to finance capital expenditures and to refinance maturing debt will depend upon general economic conditions in the capital markets. The direction in which interest rates may move is uncertain. Declining interest rates have generally been believed to be favorable to utilities, while rising interest rates are generally believed to be unfavorable, because of the levels of debt that utilities may have outstanding. In addition, National Fuel’s authorized rate of return in its regulated businesses is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, National Fuel’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, National Fuel’s ability to earn its authorized rate of return may be adversely impacted.

 

Decreased oil and natural gas prices could adversely affect revenues, cash flows and profitability.

 

National Fuel’s exploration and production operations are materially dependent on prices received for its oil and natural gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, gathering and processing oil and natural gas. Oil and natural gas prices can be volatile and can be affected by: weather conditions, including natural disasters; the supply and price of foreign oil and natural gas; the level of consumer product demand; national and worldwide economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents; political conditions in foreign countries; the price and availability of alternative fuels; the proximity to, and availability of capacity on transportation facilities; regional levels of supply and demand; energy conservation measures; and government regulations, such as regulation of natural gas transportation, royalties, and price controls. National Fuel sells most of its oil and natural gas at current market prices rather than through fixed-price contracts, although as discussed below, National Fuel frequently hedges the price of a significant portion of its future production in the financial markets. The prices National Fuel receives depend upon factors beyond National Fuel’s control, including the factors affecting price mentioned above. National Fuel believes that any prolonged reduction in oil and natural gas prices would restrict its ability to continue the level of exploration and production activity National Fuel otherwise would pursue, which could have a material adverse effect on its revenues, cash flows and results of operations.

 

National Fuel has significant transactions involving price hedging of its oil and natural gas production as well as its fixed price purchase and sale commitments.

 

In order to protect itself to some extent against unusual price volatility and to lock in fixed pricing on oil and natural gas production for certain periods of time, National Fuel periodically enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may at any time cover as much as approximately 80% of National Fuel’s expected energy production during the upcoming 12-month period. These contracts reduce exposure to subsequent price drops but can also limit National Fuel’s ability to benefit from increases in commodity prices. In addition, the Energy Marketing segment enters into certain hedging arrangements, primarily with respect to its fixed price purchase and sales commitments and its volumes of gas stored underground. National Fuel’s Pipeline and Storage segment enters into hedging arrangements with respect to certain sales of efficiency gas, and the All Other category has hedging arrangements in place with respect to certain volumes of landfill gas committed for sale.

 

Under the applicable accounting rules, the Company’s hedging arrangements are subject to quarterly effectiveness tests. Inherent within those effectiveness tests are assumptions concerning the long-term price differential between different types of crude oil, assumptions concerning the difference between published natural gas price indexes established by pipelines in which hedged natural gas production is delivered and the reference price established in the hedging arrangements, assumptions regarding the levels of production that will be achieved and, with regard to fixed price commitments, assumptions regarding the creditworthiness of certain customers and their forecasted consumption of natural gas. Depending on market conditions for natural

gas and crude oil and the levels of production actually achieved, it is possible that certain of those assumptions may change in the future, and, depending on the magnitude of any such changes, it is possible that a portion of the Company’s hedges may no longer be considered highly effective. In that case, gains or losses from the ineffective derivative financial instruments would be marked-to-market on the income statement without regard to an underlying physical transaction. Gains would occur to the extent that hedge prices exceed market prices, and losses would occur to the extent that market prices exceed hedge prices.

 

Use of energy commodity price hedges also exposes National Fuel to the risk of non-performance by a contract counterparty. These parties might not be able to perform their obligations under the hedge arrangements.

 

It is National Fuel’s policy that the use of commodity derivatives contracts comply with various restrictions in effect in respective business segments. For example, in the Exploration and Production segment, commodity derivatives contracts must be confined to the price hedging of existing and forecast production, and in the Energy Marketing segment, commodity derivatives with respect to fixed price purchase and sales commitments must be matched against commitments reasonably certain to be fulfilled. Similar restrictions apply in the Pipeline and Storage segment and the All Other category. National Fuel maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose National Fuel to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of oil and natural gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.

 

You should not place undue reliance on reserve information because such information represents estimates.

 

This Form 10-K contains estimates of National Fuel’s proved oil and natural gas reserves and the future net cash flows from those reserves that were prepared by National Fuel’s petroleum engineers and audited by independent petroleum engineers. Petroleum engineers consider many factors and make assumptions in estimating National Fuel’s oil and natural gas reserves and future net cash flows. These factors include: historical production from the area compared with production from other producing areas; the assumed effect of governmental regulation; and assumptions concerning oil and natural gas prices, production and development costs, severance and excise taxes, and capital expenditures. Lower oil and natural gas prices generally cause estimates of proved reserves to be lower. Estimates of reserves and expected future cash flows prepared by different engineers, or by the same engineers at different times, may differ substantially. Ultimately, actual production, revenues and expenditures relating to National Fuel’s reserves will vary from any estimates, and these variations may be material. Accordingly, the accuracy of National Fuel’s reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.

 

If conditions remain constant, then National Fuel is reasonably certain that its reserve estimates represent economically recoverable oil and natural gas reserves and future net cash flows. If conditions change in the future, then subsequent reserve estimates may be revised accordingly. You should not assume that the present value of future net cash flows from National Fuel’s proved reserves is the current market value of National Fuel’s estimated oil and natural gas reserves. In accordance with SEC requirements, National Fuel bases the estimated discounted future net cash flows from its proved reserves on prices and costs as of the date of the estimate. Actual future prices and costs may differ materially from those used in the net present value estimate. Any significant price changes will have a material effect on the present value of National Fuel’s reserves.

 

Petroleum engineering is a subjective process of estimating underground accumulations of natural gas and other hydrocarbons that cannot be measured in an exact manner. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Future economic and operating conditions are uncertain, and changes in those conditions could cause a revision to National Fuel’s future reserve estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas, and the assumed effects of regulations by

governmental agencies. Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves: the quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the production and operating costs incurred, the amount and timing of future development and abandonment expenditures, and the price received for the production.

 

The amount and timing of actual future oil and natural gas production and the cost of drilling are difficult to predict and may vary significantly from reserves and production estimates, which may reduce National Fuel’s earnings.

 

There are many risks in developing oil and natural gas, including numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures. The future success of National Fuel’s Exploration and Production segment depends on its ability to develop additional oil and natural gas reserves that are economically recoverable, and its failure to do so may reduce National Fuel’s earnings. The total and timing of actual future production may vary significantly from reserves and production estimates. National Fuel’s drilling of development wells can involve significant risks, including those related to timing, success rates, and cost overruns, and these risks can be affected by lease and rig availability, geology, and other factors. Drilling for oil and natural gas can be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements, and shortages or delays in the delivery of equipment and services can delay drilling operations or result in their cancellation. The cost of drilling, completing, and operating wells is often uncertain, and new wells may not be productive or National Fuel may not recover all or any portion of its investment. Without continued successful exploitation or acquisition activities, National Fuel’s reserves and revenues will decline as a result of its current reserves being depleted by production. National Fuel cannot assure you that it will be able to find or acquire additional reserves at acceptable costs.

 

Financial accounting requirements regarding exploration and production activities may affect National Fuel’s profitability.

 

National Fuel accounts for its exploration and production activities under the full cost method of accounting. Each quarter, on a country-by-country basis, National Fuel must compare the level of its unamortized investment in oil and natural gas properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses quarter-end spot prices for oil and natural gas (as adjusted for hedging). If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be “impaired,” and the full cost accounting rules require that the investment must be written down to the calculated net present value. Such an instance would require National Fuel to recognize an immediate expense in that quarter, and its earnings would be reduced. National Fuel’s Exploration and Production segment last recorded an impairment charge under the full cost method of accounting in 2006. Because of the variability in National Fuel’s investment in oil and natural gas properties and the volatile nature of commodity prices, National Fuel cannot predict when in the future it may again be affected by such an impairment calculation.

 

Environmental regulation significantly affects National Fuel’s business.

 

National Fuel’s business operations are subject to federal, state, and local laws and regulations relating to environmental protection. These laws and regulations concern the generation, storage, transportation, disposal or discharge of contaminants into the environment and the general protection of public health, natural resources, wildlife and the environment. Costs of compliance and liabilities could negatively affect National Fuel’s results of operations, financial condition and cash flows. In addition, compliance with environmental laws and regulations could require unexpected capital expenditures at National Fuel’s facilities. Because the costs of complying with environmental regulations are significant, additional regulation could negatively affect National Fuel’s business. Although National Fuel cannot predict the impact of the interpretation or enforcement

of EPA standards or other federal, state and local regulations, National Fuel’s costs could increase if environmental laws and regulations become more strict.

 

The nature of National Fuel’s operations presents inherent risks of loss that could adversely affect its results of operations, financial condition and cash flows.

 

National Fuel’s operations in its various segments are subject to inherent hazards and risks such as: fires; natural disasters; explosions; geological formations with abnormal pressures; blowouts during well drilling; collapses of wellbore casing or other tubulars; pipeline ruptures; spills; and other hazards and risks that may cause personal injury, death, property damage, environmental damage or business interruption losses. Additionally, National Fuel’s facilities, machinery, and equipment may be subject to sabotage. Any of these events could cause a loss of hydrocarbons, environmental pollution, claims for personal injury, death, property damage or business interruption, or governmental investigations, recommendations, claims, fines or penalties. As protection against operational hazards, National Fuel maintains insurance coverage against some, but not all, potential losses. In addition, many of the agreements that National Fuel executes with contractors provide for the division of responsibilities between the contractor and National Fuel, and National Fuel seeks to obtain an indemnification from the contractor for certain of these risks. National Fuel is not always able, however, to secure written agreements with its contractors that contain indemnification, and sometimes National Fuel is required to indemnify others.

 

Insurance or indemnification agreements when obtained may not adequately protect National Fuel against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, the imposition of fines, penalties or mandated programs by governmental authorities, the failure of a contractor to meet its indemnification obligations, or the failure of an insurance company to pay valid claims could result in substantial losses to National Fuel. In addition, insurance may not be available, or if available may not be adequate, to cover any or all of these risks. It is also possible that insurance premiums or other costs may rise significantly in the future, so as to make such insurance prohibitively expensive.

 

Due to the significant cost of insurance coverage for named windstorms in the Gulf of Mexico, National Fuel determined that it was not economical to purchase insurance to fully cover its exposures related to such storms. It is possible that named windstorms in the Gulf of Mexico could have a material adverse effect on National Fuel’s results of operations, financial condition and cash flows.

 

Hazards and risks faced by National Fuel, and insurance and indemnification obtained or provided by National Fuel, may subject National Fuel to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines or penalties against National Fuel or be resolved on unfavorable terms, the result of which could have a material adverse effect on National Fuel’s results of operations, financial condition and cash flows.

 

National Fuel may be adversely affected by economic conditions.

 

Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity could adversely affect National Fuel’s revenues and cash flows or restrict its future growth. Economic conditions in National Fuel’s utility service territories also impact its collections of accounts receivable.

 

 

None

 

 

General Information on Facilities

 

The net investment of the Company in property, plant and equipment was $2.9 billion at September 30, 2007. Approximately 62% of this investment was in the Utility and Pipeline and Storage segments, which are primarily located in western and central New York and northwestern Pennsylvania. The Exploration and Production segment, which has the next largest investment in net property, plant and equipment (34%), is primarily located in California, in the Appalachian region of the United States, in Wyoming, and in the Gulf Coast region of Texas, Louisiana, and Alabama. The remaining net investment in property, plant and equipment consisted of the Timber segment (3%) which is located primarily in northwestern Pennsylvania, and All Other and Corporate operations (1%). During the past five years, the Company has made additions to property, plant and equipment in order to expand and improve transmission and distribution facilities for both retail and transportation customers. Net property, plant and equipment has increased $33.7 million, or 1.2%, since 2002. During 2007, the Company sold SECI, Seneca’s wholly owned subsidiary that operated in Canada. The net property, plant and equipment of SECI at the date of sale was $107.7 million. In addition, during 2005, the Company sold its majority interest in U.E., a district heating and electric generation business in the Czech Republic. The net property, plant and equipment of U.E. at the date of sale was $223.9 million.

 

The Utility segment had a net investment in property, plant and equipment of $1.1 billion at September 30, 2007. The net investment in its gas distribution network (including 14,813 miles of distribution pipeline) and its service connections to customers represent approximately 53% and 33%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2007.

 

The Pipeline and Storage segment had a net investment of $681.9 million in property, plant and equipment at September 30, 2007. Transmission pipeline represents 33% of this segment’s total net investment and includes 2,495 miles of pipeline required to move large volumes of gas throughout its service area. Storage facilities represent 24% of this segment’s total net investment and consist of 32 storage fields, four of which are jointly owned and operated with certain pipeline suppliers, and 441 miles of pipeline. Net investment in storage facilities includes $89.8 million of gas stored underground-noncurrent, representing the cost of the gas required to maintain pressure levels for normal operating purposes as well as gas maintained for system balancing and other purposes, including that needed for no-notice transportation service. The Pipeline and Storage segment has 28 compressor stations with 75,404 installed compressor horsepower that represent 14% of this segment’s total net investment in property, plant and equipment.

 

The Exploration and Production segment had a net investment in property, plant and equipment of $982.7 million at September 30, 2007.

 

The Timber segment had a net investment in property, plant and equipment of $89.9 million at September 30, 2007. Located primarily in northwestern Pennsylvania, the net investment includes two sawmills, 103,700 acres of land and timber, and 3,105 acres of timber rights.

 

The Utility and Pipeline and Storage segments’ facilities provided the capacity to meet the Company’s 2007 peak day sendout, including transportation service, of 1,743 MMcf, which occurred on February 5, 2007. Withdrawals from storage of 779.3 MMcf provided approximately 44.7% of the requirements on that day.

 

Company maps are included in exhibit 99.2 of this Form 10-K and are incorporated herein by reference.

 

Exploration and Production Activities

 

The Company is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, in Wyoming, and in the Gulf Coast region of Texas, Louisiana, and Alabama. Also, Exploration and Production operations were conducted in the provinces of Alberta, Saskatchewan and British Columbia in Canada, until the sale of these properties on August 31, 2007. Further discussion of the sale of the Canadian oil and gas properties is included in Item 8, Note-I-Discontinued Operations. Further discussion of oil and gas producing activities is included in Item 8, Note O-Supplementary Information for Oil and Gas Producing Activities. Note O sets forth proved developed

and undeveloped reserve information for Seneca. Seneca’s proved developed and undeveloped natural gas reserves decreased from 233 Bcf at September 30, 2006 to 205 Bcf at September 30, 2007. This decrease is attributed primarily to the sale of the Canadian gas properties (40.1 Bcf) and production of 26.3 Bcf. These decreases were partially offset by extensions and discoveries of 34.6 Bcf, primarily in the Appalachian region (29.7 Bcf). Seneca’s proved developed and undeveloped oil reserves decreased from 58,018 Mbbl at September 30, 2006 to 47,586 Mbbl at September 30, 2007. This decrease is attributed to revisions of previous estimates (5,963 Mbbl), primarily occurring in California, production (3,450 Mbbl) and the sale of the Canadian oil properties (1,458 Mbbl). Seneca’s proved developed and undeveloped natural gas reserves decreased from 238 Bcf at September 30, 2005 to 233 Bcf at September 30, 2006. This decrease is attributed primarily to production and downward reserve revisions related primarily to the Canadian properties. These decreases were partially offset by extensions and discoveries. The downward reserve revisions were largely a function of a significant decrease in gas prices during the fourth quarter of 2006. Seneca’s proved developed and undeveloped oil reserves decreased from 60,257 Mbbl at September 30, 2005 to 58,018 Mbbl at September 30, 2006. This decrease is attributed mostly to production.

 

Seneca’s oil and gas reserves reported in Item 8 at Note O as of September 30, 2007 were estimated by Seneca’s geologists and engineers and were audited by independent petroleum engineers from Netherland, Sewell & Associates, Inc. Seneca reports its oil and gas reserve information on an annual basis to the Energy Information Administration (EIA), a statistical agency of the U.S. Department of Energy. The oil and gas reserve information reported to the EIA showed 211 Bcf and 59,246 Mbbl of gas and oil reserves, respectively, which differs from the reserve information summarized in Item 8 at Note O. The reasons for this difference are as follows: (a) reserves are reported to the EIA on a calendar year basis, while reserves disclosed in Item 8 at Note O are shown on a fiscal year basis; (b) reserves reported to the EIA include only properties operated by Seneca, while reserves disclosed in Item 8 at Note O included both Seneca operated properties and non-operated properties in which Seneca has an interest; and (c) reserves are reported to the EIA on a gross basis verses the reserves disclosed in Item 8 at Note O, which are reported on a net revenue interest basis.

 

The following is a summary of certain oil and gas information taken from Seneca’s records. All monetary amounts are expressed in U.S. dollars.

 

 

 

As of September 30, 2007, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 23,332 acres in 2008 (12,707 net acres), 38,741 acres in 2009 (23,219 net acres), 23,038 acres in 2010 (11,491 net acres), and 536,256 acres thereafter (490,306 net acres).

 

 

 

 

described above will not be material to the consolidated financial condition, results of operations, or cash flow of the Company. No assurances can be given, however, as to the ultimate outcomes of those matters, and it is possible that the outcomes could be material to the consolidated financial condition, results of operations or cash flow of the Company.

 

For a discussion of various environmental and other matters, refer to Part II, Item 7, MD&A and Item 8 at Note H — Commitments and Contingencies.

 

In addition to the matters disclosed above, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service, and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor to have a material adverse effect on the financial condition of the Company.

 

 

 

 

 

 

 

OVERVIEW

 

The Company is a diversified energy company consisting of five reportable 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

 

 

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

 

The event that had the most significant earnings impact in 2007, and the main reason for the significant earnings increase over 2006, was the Company’s sale of SECI, Seneca’s wholly owned subsidiary that operated in Canada. SECI was engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in the provinces of Alberta, Saskatchewan and British Columbia in Canada. This sale resulted in a $120.3 million gain, net of tax. The decision to sell SECI was based on lower than expected returns from the Canadian oil and gas properties combined with difficulty in finding significant new reserves. As a result of the decision to sell SECI, the Company began presenting all SECI operations as discontinued operations in September 2007. Also contributing to the increase in earnings over 2006 was the non-recurrence of impairment charges of $68.6 million related to the Exploration and Production segment’s Canadian oil and gas assets recognized during 2006 under the full cost method of accounting, which is discussed below under Critical Accounting Estimates. Seneca intends to continue its exploration and development activities in the Gulf of Mexico, in California and in Appalachia, subject to regular re-evaluation of its efforts and opportunities in each region.

 

The Company spent $247.6 million on capital expenditures related to continuing operations during 2007, with approximately 59% being spent in the Exploration and Production segment. This was in line with the Company’s expectations. As mentioned above, Seneca will continue its exploration and development activities in Appalachia, in California and in the Gulf of Mexico. In Appalachia, drilling will be accelerated. Seneca intends to commence drilling of 280 wells for shallow tight sand targets in fiscal 2008, a 20% increase over the 233 such wells drilled in 2007. In addition, Seneca anticipates continued drilling in the deeper Marcellus Shale formation in Appalachia with its joint venture partner, EOG Resources, Inc. Seneca expects that as many as eighteen Marcellus Shale wells will be drilled on its acreage in 2008, ten of which are expected to be horizontal wells. In the Gulf of Mexico, Seneca’s strategy will be to follow a focused drilling plan in the specific areas where the Company has expertise and past success.

 

The Company took a significant step forward this year regarding the Empire Connector project. In June 2007, Empire signed a firm transportation service agreement with KeySpan Gas East Corporation, thereby obligating Empire to provide transportation service that will require construction of the Empire Connector project. Construction of the Empire Connector began in September 2007 and 20 miles will be completed by December 2007. The Company expects to complete the project by November 1, 2008. The total cost to the Company of the Empire Connector project is estimated at $177 million, after giving effect to sales tax

exemptions. The Company expects the expansion of the Pipeline and Storage segment to remain a major strategic priority. Supply Corporation has verified that there is substantial market interest in transporting gas produced in the Rocky Mountain area to the Northeast. In order to serve this anticipated demand, Supply Corporation has proposed a new 324-mile pipeline that would commence at Clarington, Ohio, the proposed terminus of the Rockies Express pipeline, and extend to the Millennium Pipeline under construction at Corning, New York. From Corning, Rocky Mountain gas will be able to get to the New York City area and to New England. The proposed pipeline would be designed to move approximately 550 to 750 MDth of gas per day, as well as accommodate volumes from local production areas. These projects are discussed further in the Capital Resources and Liquidity and Rates and Regulatory Matters sections that follow.

 

The Company is currently evaluating the appropriateness of establishing a Master Limited Partnership (MLP) for its pipeline and storage assets, and another MLP for certain of its exploration and production assets. If this evaluation determined that the MLP structure is sound and in the shareholders’ interest, the Company would pursue the MLP structure for the appropriate Company assets. Potential impediments to establishing MLPs include: (a) the low tax basis of our pipeline and storage assets, which substantially mitigates the tax advantages of an MLP structure; (b) the highly integrated operations of the Company’s Pipeline and Storage and Utility business segments; and (c) the sustainability of an exploration and production MLP given the natural decline curve of production from all oil and gas properties. As a result, new long-lived reserves must be constantly added to an exploration and production MLP in order to sustain the MLP’s cash distributions. Acquisitions of long-lived reserves could be very costly given the significant premiums that are currently being paid for long-lived reserves.

 

The Company also began repurchasing outstanding shares of common stock during fiscal 2006 under a share repurchase program authorized by the Company’s Board of Directors. The program authorizes the Company to repurchase up to an aggregate amount of 8 million shares. Through September 30, 2007, the Company had repurchased 3,834,878 shares for $133.2 million under this program, including 1,308,328 shares for $48.1 million during the year ended September 30, 2007. These matters are discussed further in the Capital Resources and Liquidity section that follows.

 

On January 29, 2007, the Company commenced a rate case in the New York jurisdiction of the Utility segment by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by $52.0 million annually. The Company explained in the filing that its request for rate relief is necessitated by decreased revenues resulting from customer conservation efforts and increased customer uncollectibles, among other things. The rate filing also includes a proposal for an aggressive efficiency and conservation initiative with a revenue decoupling mechanism designed to render the Company indifferent to throughput reductions resulting from conservation. In September 2007, the NYPSC issued an order approving the Company’s conservation program, and the administrative law judge assigned to the proceeding issued a recommended decision, which recommends a rate increase designed to provide additional annual revenues of $2.5 million as well as a bill surcharge that would collect up to $10.8 million to recover expenses arising from the conservation program. The recommended decision also recommends approval of the unopposed revenue decoupling mechanism. The NYPSC is not bound to accept the recommended decision. This matter is discussed more fully in the Rate and Regulatory Matters section that follows.

 

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 a country-by-country basis 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 current market prices of oil and gas (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 or subtractions to 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 must be recorded to 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. Because of the decline in the price of natural gas during the third and fourth quarters of 2006, the book value of the Company’s Canadian oil and gas properties exceeded the ceiling at both June 30, 2006 and September 30, 2006. Consequently, SECI recorded impairment charges of $62.4 million ($39.5 million after-tax) in the third quarter of 2006 and $42.3 million ($29.1 million after-tax) in the fourth quarter of 2006. These impairment charges are now included in the loss from discontinued operations for 2006 due to the sale of SECI during 2007.

 

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

Upon the adoption of SFAS 143 on October 1, 2002, the Company recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and capitalized such costs in property, plant and equipment (i.e. the full cost pool). Prior to the adoption of SFAS 143, plugging and abandonment costs were accounted for solely through the Company’s units-of-production depletion calculation. An estimate of such costs was added to the depletion base, which also included capitalized costs in the full cost pool and estimated future expenditures to be incurred in developing proved reserves. With the adoption of SFAS 143, plugging and abandonment costs are already included in capitalized costs and the units-of-production depletion calculation has been modified to exclude from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.

 

Prior to the adoption of SFAS 143, in calculating the full cost ceiling, the Company reduced the future net cash flows from proved oil and gas reserves by the estimated plugging and abandonment costs. Such future net cash flows would then be compared to capitalized costs in the full cost pool, with any excess capitalized costs being expensed. With the adoption of SFAS 143, since the full cost pool now includes an amount associated with plugging and abandoning the wells, the calculation of the full cost ceiling has been changed so that future net cash flows from proved oil and gas reserves are no longer reduced by the estimated plugging and abandonment costs.

 

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 SFAS 71, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows the Company to defer expenses and income on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratesetting process in a period different from the period in which they would have been reflected in the income statement by an unregulated company. These deferred regulatory assets and liabilities are then flowed through the income statement in the period in which the same amounts are reflected in 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.

 

Accounting for Derivative Financial Instruments.   The Company, in its Exploration and Production segment, Energy Marketing segment, Pipeline and Storage segment and All Other category, uses 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, no cost collars and futures contracts. The Company, in its Pipeline and Storage segment, previously used an interest rate collar to limit interest rate fluctuations on certain variable rate debt. In accordance with the provisions of SFAS 133, the Company accounted for these instruments as effective cash flow hedges or fair value hedges. In 2007, the Company discontinued hedge accounting for the interest rate collar, which resulted in a gain being recognized. 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. As discussed below, the Company was required to discontinue hedge accounting for a portion of its derivative financial instruments in the Exploration and Production segment, resulting in a charge to earnings in 2005.

 

The Company uses both exchange-traded and non exchange-traded derivative financial instruments. The fair values of the non exchange-traded derivative financial instruments are based on valuations determined by the counterparties. 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 discount rate used by the Company is equal to the Moody’s Aa Long-Term Corporate Bond index, rounded to the nearest 25 basis points. The duration of the securities underlying that index (approximately 13 years) reasonably matches the expected timing of anticipated future benefit payments (approximately 12 years). The Company also 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 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 substantially all 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. For financial reporting purposes, the difference between the amounts of pension cost and post-retirement benefit cost recoverable in rates and the amounts of such costs as determined under applicable accounting principles is recorded as either a regulatory asset or liability, as appropriate, as discussed above under “Regulation.” Pension and post-retirement benefit costs for the Utility and Pipeline and Storage segments represented 93% and 94%, respectively, of the Company’s total pension and post-retirement benefit costs as determined under SFAS 87 and SFAS 106 for the years ended September 30, 2007 and 2006.

 

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 post-retirement benefit plans and could impact the Company’s equity. For example, while the discount rate used to determine benefit obligations did not change from 2006 to 2007, the discount rate was changed from 5.0% in 2005 to 6.25% in 2006. The change in the discount rate from 2005 to 2006 reduced the pension plan projected benefit obligation by $113.1 million and the accumulated post-retirement benefit obligation by $77.5 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 obligations and the accumulated post-retirement benefit obligation for the Post-Retirement Plan. For 2007, actual versus expected return on plan assets resulted in an increase to the funded status of the Retirement Plan and the Post-Retirement Plan of $68.4 million and $38.6 million, respectively. The actual versus expected benefit payments for 2007 caused a decrease of $1.3 million and $1.8 million to the projected benefit obligation and accumulated post-retirement benefit obligation, respectively. In calculating the projected benefit obligation for the Retirement Plan and the accumulated post-retirement obligation for the Post-Retirement Plan, the actuary takes into account the average remaining service life of active participants. The average remaining service life of active participants is 9 years for both the Retirement Plan and the Post-Retirement Plan. 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 the adoption of SFAS 158, and to Item 8 at Note G — Retirement Plan and Other Post Retirement Benefits.

RESULTS OF OPERATIONS

 

EARNINGS

 

2007 Compared with 2006

 

The Company’s earnings were $337.5 million in 2007 compared with earnings of $138.1 million in 2006. As previously discussed, the Company has presented its Canadian operations in the Exploration and Production segment (in conjunction with the sale of SECI) as discontinued operations. The Company’s earnings from continuing operations were $201.7 million in 2007 compared with $184.6 million in 2006. The Company’s earnings from discontinued operations were $135.8 million in 2007 compared with a loss of $46.5 million in 2006. The increase in earnings from continuing operations of $17.1 million is primarily the result of higher earnings in the Exploration and Production, Utility, Pipeline and Storage, and Energy Marketing segments and the Corporate and All Other categories, slightly offset by lower earnings in the Timber segment, as shown in the table below. The increase in earnings from discontinued operations primarily resulted from the gain on the sale of SECI recognized in 2007 as well as the non-recurrence of $68.6 million of impairment charges recognized in 2006 related to the Exploration and Production segment’s Canadian oil and gas assets. In the discussion that follows, note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings from continuing operations and discontinued operations were impacted by several events in 2007 and 2006, including:

 

2007 Events

 

 

2006 Events

 

 

2006 Compared with 2005

 

The Company’s earnings were $138.1 million in 2006 compared with earnings of $189.5 million in 2005. As previously discussed, the Company has presented its Canadian operations in the Exploration and Production segment (in conjunction with the sale of SECI) as well as for its Czech Republic operations (in conjunction with the sale of U.E.) as discontinued operations. The Company’s earnings from continuing operations were $184.6 million in 2006 compared with $138.4 million in 2005. The Company recorded a loss from discontinued operations of $46.5 million in 2006 compared with earnings from discontinued operations of $51.1 million in 2005. The increase in earnings from continuing operations of $46.2 million is primarily the result of higher earnings in the Exploration and Production, Utility, Energy Marketing, and Timber segments, combined with

higher earnings in the All Other category and a lower loss in the Corporate category. These were offset somewhat by lower earnings in the Pipeline and Storage segment, as shown in the table below. The loss from discontinued operations in 2006 compared to earnings from discontinued operations in 2005 reflects the recognition of $68.6 million of impairment charges in 2006 related to the Exploration and Production segment’s Canadian oil and gas assets as well as the non-recurrence of the gain on the sale of U.E. recognized in 2005. Earnings from continuing operations and discontinued operations were impacted by several events discussed above and the following 2005 events:

 

2005 Events

 

 

Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.

 

 

 

 

 

Utility Throughput — million cubic feet (MMcf)

 

 

 

2007 Compared with 2006

 

Operating revenues for the Utility segment decreased $160.0 million in 2007 compared with 2006. This decrease largely resulted from a $180.4 million decrease in retail gas sales revenues. This decrease was primarily offset by a $10.0 million increase in transportation revenues and a $9.8 million increase in off-system sales revenues.

The decrease in retail gas sales revenues for the Utility segment was largely a function of the recovery of lower gas costs (gas costs are recovered dollar for dollar in revenues), which more than offset the revenue impact of higher retail sales volumes, as shown in the table above. See further discussion of purchased gas below under the heading “Purchased Gas.” This decrease was offset slightly by a base rate increase in the Pennsylvania jurisdiction, effective January 2007, which increased operating revenues by $8.5 million for 2007. The increase is included within both retail and transportation revenues in the table above.

 

The increase in transportation revenues was primarily due to a 4.3 Bcf increase in transportation throughput, largely due to the migration of retail sales customers to transportation service. The corresponding $10.0 million increase in transportation revenues would have been greater if not for a $3.9 million out-of-period adjustment recorded in the first quarter of 2006 to correct Distribution Corporation’s calculation of the symmetrical sharing component of New York’s gas adjustment rate.

 

As reported in 2006, on November 17, 2006 the U.S. Court of Appeals vacated and remanded FERC’s Order No. 2004, its latest affiliate standards of conduct, with respect to natural gas pipelines. The court’s decision became effective on January 5, 2007, and on January 9, 2007, FERC issued Order No. 690, its Interim Rule, designed to respond to the court’s decision. In Order No. 690, as clarified by FERC on March 21, 2007, the FERC readopted, on an interim basis, certain provisions that existed prior to the issuance of Order No. 2004 that had made it possible for the Utility to engage in certain off-system sales without triggering the adverse consequences that would otherwise arise under the standards of conduct. As such, the Utility resumed engaging in off-system sales on non-affiliated pipelines as of May 2007, resulting in total off-system sales revenues of $9.8 million for 2007. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was not a material impact to margins in 2007.

 

2006 Compared with 2005

 

Operating revenues for the Utility segment increased $163.7 million in 2006 compared with 2005. This increase largely resulted from a $146.5 million increase in retail gas sales revenues. Transportation revenues and other revenues also increased by $8.9 million and $8.3 million, respectively.

 

The increase in retail gas sales revenues for the Utility segment was largely a function of the recovery of higher gas costs (gas costs are recovered dollar for dollar in revenues), which more than offset the revenue impact of lower retail sales volumes, as shown in the table above. See further discussion of purchased gas below under the heading “Purchased Gas.” Warmer weather, as shown in the table above, and greater conservation by customers due to higher natural gas commodity prices, were the principal reasons for the decrease in retail sales volumes.

 

The increase in transportation revenues was primarily due to a $5.9 million increase in the New York jurisdiction’s calculation of the symmetrical sharing component of the gas adjustment rate. The symmetrical sharing component is a mechanism included in Distribution Corporation’s New York rate agreement that shares with customers 90% of the difference between actual revenues received from large volume customers and the level of revenues that were projected to be received during the rate year. Of the $5.9 million increase, $3.9 million was due to an out-of-period adjustment recorded in fiscal year 2006 when it was determined that certain credits that had been included in the calculation should have been removed during the implementation of a previous rate case. The adjustment related to fiscal years 2002 through 2005.

 

The impact of the August 2005 New York rate agreement was to increase operating revenues by $19.1 million (of which $12.4 million was an increase to other operating revenues). This increase consisted of a base rate increase, the implementation of a merchant function charge, the elimination of certain bill credits, and the elimination of the gross receipts tax surcharge. The rate agreement also allowed Distribution Corporation to continue to utilize certain refunds from upstream pipeline companies and certain other credits (referred to as the “cost mitigation reserve”) to offset certain specific expense items. In 2005, Distribution Corporation utilized $7.8 million of the cost mitigation reserve, which increased other operating revenues, to recover previous under-collections of pension and post-retirement expenses. The impact of that increase in other operating revenues was offset by an equal amount of operation and maintenance expense (thus there was no earnings impact). Distribution Corporation did not record any entries involving the cost mitigation reserve

in 2006. Other operating revenues were also impacted by two out-of-period regulatory adjustments recorded during 2005. The first adjustment related to the final settlement with the Staff of the NYPSC of the earnings sharing liability for the 2001 to 2003 time period. As a result of that settlement, the New York rate jurisdiction recorded additional earnings sharing expense (as an offset to other operating revenues) of $0.9 million. The second adjustment related to a regulatory liability recorded for previous over-collections of New York State gross receipts tax. In preparing for the implementation of the rate agreement in New York, the Company determined that it needed to adjust that regulatory liability by $3.1 million (of which $1.0 million was recorded as a reduction of other operating revenues and $2.1 million was recorded as additional interest expense) related to fiscal years 2004 and prior. These adjustments did not recur in 2006.

 

In the Pennsylvania jurisdiction, the impact of the base rate increase, which became effective in mid-April 2005, was to increase operating revenues by $7.5 million. This increase is included within both retail and transportation revenues in the table above.

 

Purchased Gas

 

The cost of purchased gas is the Company’s single largest operating expense. Annual variations in purchased gas costs are attributed directly to changes in gas sales volumes, the price of gas purchased and the operation of purchased gas adjustment clauses.

 

Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation and six other upstream pipeline companies, for long-term gas supplies with a combination of producers and marketers, and for storage service with Supply Corporation and three nonaffiliated companies. In addition, Distribution Corporation satisfies a portion of its gas requirements through spot market purchases. Changes in wellhead prices have a direct impact on the cost of purchased gas. Distribution Corporation’s average cost of purchased gas, including the cost of transportation and storage, was $10.04 per Mcf in 2007, a decrease of 17% from the average cost of $12.07 per Mcf in 2006. The average cost of purchased gas in 2006 was 31% higher than the average cost of $9.19 per Mcf in 2005. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.

 

Earnings

 

2007 Compared with 2006

 

The Utility segment’s earnings in 2007 were $50.9 million, an increase of $1.1 million when compared with earnings of $49.8 million in 2006.

 

In the New York jurisdiction, earnings decreased by $6.2 million. This was primarily due to lower interest income ($4.5 million). The New York division’s current rate agreement with the NYPSC allows the Company to accrue interest on a pension-related regulatory asset. The amount of interest that can be accrued is reduced as the funded status of the pension plan improves. The fair market value of the pension plan assets exceeded the accumulated benefit obligation at September 30, 2007 resulting in a significant reduction in the interest accrual on this regulatory asset. The out-of-period symmetrical sharing adjustment discussed above ($2.6 million), higher bad debt and other operating costs ($0.8 million), higher property taxes ($0.6 million) and higher interest expense ($0.5 million) also contributed to this decrease. The positive impact associated with a lower effective tax rate ($1.9 million) and increased usage per account ($1.9 million) partially offset the overall decrease.

 

In the Pennsylvania jurisdiction, earnings increased by $7.3 million. This was primarily due to a base rate increase ($5.5 million) that became effective January 2007, colder weather ($2.5 million), and the positive impact associated with a lower effective tax rate ($1.1 million). Higher intercompany and other interest expense ($0.8 million), coupled with a decrease in normalized usage ($0.3 million), partially offset these increases.

 

The impact of weather on the Utility segment’s New York rate jurisdiction is tempered by a WNC. The WNC, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the

Utility segment’s New York customers. In 2007 and 2006, the WNC preserved earnings of approximately $2.3 million and $6.2 million, respectively, as the weather was warmer than normal.

 

2006 Compared with 2005

 

The Utility segment’s earnings in 2006 were $49.8 million, an increase of $10.6 million when compared with earnings of $39.2 million in 2005.

 

In the New York jurisdiction, earnings increased by $9.2 million, primarily due to the positive impact of the rate agreement in this jurisdiction that became effective August 2005 ($13.7 million). In addition, the increase in the New York jurisdiction’s calculation of the symmetrical sharing component of the gas adjustment rate, including the out-of-period adjustment discussed above, contributed $3.9 million to earnings. Two out-of-period regulatory adjustments recorded during fiscal year 2005 that did not recur during 2006, as discussed above, also contributed an additional $2.6 million to earnings. The first adjustment, related to the final settlement with the Staff of the NYPSC of the earnings sharing liability for the fiscal 2001 through 2003 time period, increased earnings in fiscal 2006 by $0.6 million. The second adjustment, related to a regulatory liability recorded for previous over-collections of New York State gross receipts tax, increased earnings in fiscal 2006 by $2.0 million. The increase in earnings due to the New York rate agreement, the symmetrical sharing component of the gas adjustment rate, and the two out-of-period regulatory adjustments recorded in 2005, was partially offset by a decline in margin associated with lower weather-normalized usage by customers ($2.3 million), higher operation expenses ($2.5 million), higher interest expense ($2.7 million), and a higher effective income tax rate ($3.2 million). The higher effective income tax rate is due to positive tax adjustments recorded in 2005 that did not recur in 2006. The increase in operation expenses consisted primarily of higher pension expense offset by lower bad debt expense.

 

In the Pennsylvania jurisdiction, earnings increased by $1.4 million, due to the positive impact of the rate case settlement in this jurisdiction that became effective April 2005 ($4.9 million), and lower operation expenses ($1.8 million). The decrease in operation expenses consisted primarily of lower bad debt expense offset partially by higher pension expense. These increases to earnings were partially offset by the impact of warmer than normal weather in Pennsylvania ($3.0 million), lower weather-normalized usage by customer ($0.6 million), higher interest expense ($0.8 million), and a higher effective tax rate ($1.3 million).

 

The decrease in bad debt expense reflects the fact that in the fourth quarter of 2005, the New York and Pennsylvania jurisdictions increased the allowance for uncollectible accounts to reflect the increase in final billed account balances and the increased aging of outstanding active receivables heading into the heating season. A similar adjustment was not required in 2006.

 

In 2006, the WNC preserved earnings of approximately $6.2 million because it was warmer than normal in the New York service territory. In 2005, the WNC did not have a significant impact on earnings.