UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Amendment No. 1Form 10-K
Form 10-K/A
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þ | | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended September 30, 20082010
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o | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to to
Commission File Number 1-3880
National Fuel Gas Company
(Exact name of registrant as specified in its charter)
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| New Jersey | | 13-1086010 |
(State or other jurisdiction of
incorporation or organization) | | (I.R.S. Employer
Identification No.) |
6363 Main Street
Williamsville, New York
incorporation or organization)(Address of principal executive offices) | | 14221
Identification No.)(Zip Code) |
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6363 Main Street | | 14221 |
Williamsville, New York | | (Zip Code) |
(Address of principal executive offices) | | |
(716) 857-7000
Registrant’s telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
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| Title of Each Class | | Registered |
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Common Stock, $1 Par Value, and
Common Stock Purchase Rights | | New York Stock Exchange |
Common Stock Purchase Rights | | |
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. Yesþ Noo
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yeso Noþ
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. Yesþ Noo
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 ofRegulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation 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 thisForm 10-K or any amendment to thisForm 10-K.oþ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule12b-2 of the Exchange Act. (Check one):
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| Large accelerated filerþ | | Accelerated filero | | Non-accelerated filero | | Smaller reporting companyo |
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Act). Yeso Noþ
The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $3,768,755,000$4,041,725,000 as of March 31, 2008.2010.
Common Stock, $1 Par Value, outstanding as of October 31, 2008: 79,124,6442010: 82,190,871 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement for its 2011 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
Distribution Corporation National Fuel Gas Distribution Corporation
Empire Empire Pipeline, Inc.
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.
Midstream Corporation National Fuel Gas Midstream Corporation
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
Regulatory Agencies
EPA United States Environmental Protection Agency
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
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
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. The Company 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.
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.
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.
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 oil and gas 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.
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.
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
LIFOLast-in, first-out
Marcellus Shale A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.
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)
MMBtu Million British thermal units
MMcf Million cubic feet (of natural gas)
MMcfe Million cubic feet equivalent
NGA The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
NYMEX New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Open Season A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.
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.”
PCB Polychlorinated Biphenyl
Precedent Agreement An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.
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 those reserves productive.
PRP Potentially responsible party
PUHCA 1935 Public Utility Holding Company Act of 1935
PUHCA 2005 Public Utility Holding Company Act of 2005
Reliable technology Technology that a company may use to establish reserves estimates and categories that has been proven empirically to lead to correct conclusions.
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 pipeline and/or utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundling”) 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.
Revenue decoupling mechanism A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation.
S&P Standard & Poor’s Ratings Service
SAR Stock appreciation right
Spot gas purchases The purchase of natural gas on a short-term basis.
Stock acquisitions Investments in corporations.
Unbundled service A service that has been separated from other services, with rates charged that reflect only the cost of the separated service.
VEBA Voluntary Employees’ Beneficiary Association
WNC Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.
For the Fiscal Year Ended September 30, 20082010
CONTENTS
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| Part I |
| ITEM 1 | | BUSINESS | | | 3 | |
| | The Company and its Subsidiaries | | | 3 | |
| | Rates and Regulation | | | 4 | |
| | The Utility Segment | | | 5 | |
| | The Pipeline and Storage Segment | | | 5 | |
| | The Exploration and Production Segment | | | 6 | |
| | The Energy Marketing Segment | | | 6 | |
| | All Other Category and Corporate Operations | | | 6 | |
| | Discontinued Operations | | | 6 | |
| | Sources and Availability of Raw Materials | | | 7 | |
| | Competition | | | 7 | |
| | Seasonality | | | 9 | |
| | Capital Expenditures | | | 9 | |
| | Environmental Matters | | | 9 | |
| | Miscellaneous | | | 9 | |
| | Executive Officers of the Company | | | 10 | |
| ITEM 1A | | RISK FACTORS | | | 11 | |
| ITEM 1B | | UNRESOLVED STAFF COMMENTS | | | 18 | |
| ITEM 2 | | PROPERTIES | | | 18 | |
| | General Information on Facilities | | | 18 | |
| | Exploration and Production Activities | | | 19 | |
| ITEM 3 | | LEGAL PROCEEDINGS | | | 24 | |
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| Part II |
| ITEM 5 | | MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES | | | 24 | |
| ITEM 6 | | SELECTED FINANCIAL DATA | | | 25 | |
| ITEM 7 | | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | | | 26 | |
| ITEM 7A | | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | | | 66 | |
| ITEM 8 | | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | | | 67 | |
| ITEM 9 | | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | | | 131 | |
| ITEM 9A | | CONTROLS AND PROCEDURES | | | 131 | |
| ITEM 9B | | OTHER INFORMATION | | | 132 | |
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ThisForm 10-K/A10-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 and important factors included in the Company’s thisForm 10-K for the fiscal year ended September 30, 2008, 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, objectives, goals, projections, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction and other 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.
EXPLANATORY NOTEPART I
National Fuel Gas Company (the Registrant), incorporated in 1902, is a holding company organized under the laws of the State of New Jersey. Except as otherwise indicated below, the Registrant owns directly or indirectly all of the outstanding securities of its subsidiaries. Reference to “the Company” in this report means the Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure. Also, all references to a certain year in this report relate to the Company’s fiscal year ended September 30 of that year unless otherwise noted.
The Company is filinga diversified energy company and reports financial results for four business segments.
1. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation sells natural gas or provides natural gas transportation services to approximately 728,700 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.
2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation, and Empire Pipeline, Inc. (Empire), a New York corporation. Supply Corporation provides interstate natural gas transportation and storage services for affiliated and nonaffiliated companies through (i) an integrated gas pipeline system extending from southwestern Pennsylvania to the New York-Canadian border at the Niagara River and eastward to Ellisburg and Leidy, Pennsylvania, and (ii) 27 underground natural gas storage fields owned and operated by Supply Corporation as well as four other underground natural gas storage fields owned and operated jointly with other interstate gas pipeline companies. Empire, an interstate pipeline company, transports natural gas for Distribution Corporation and for other utilities, large industrial customers and power producers in New York State. Empire owns the Empire Pipeline, a157-mile pipeline that extends from the United States/Canadian border at the Niagara River near Buffalo, New York to near Syracuse, New York, and the Empire Connector, which is a76-mile pipeline extension from near Rochester, New York to an interconnection with the unaffiliated Millennium Pipeline near Corning, New York. The Millennium Pipeline serves the New York City area. The Empire Connector was placed into service on December 10, 2008.
3. The Exploration and Production segment operations are carried out by Seneca Resources Corporation (Seneca), a Pennsylvania corporation, and by Seneca Western Minerals Corp., a Nevada corporation and an indirect, wholly owned subsidiary of Seneca. Seneca 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, and in the shallow waters of the Gulf Coast region of Texas and Louisiana, including offshore areas in federal waters and some state waters. At September 30, 2010, the Company had U.S. proved developed and undeveloped reserves of 45,239 Mbbl of oil and 428,413 MMcf of natural gas.
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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, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
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 K — Business Segment Information.
The Company’s other direct wholly owned subsidiaries are not included in any of the four reported business segments and include the following active companies:
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| • | Highland Forest Resources, Inc. (Highland), a New York corporation which, together with a division of Seneca known as its Northeast Division, markets timber from Appalachian land holdings. At September 30, 2010, the Company owned approximately 100,000 acres of timber property and managed an additional 3,424 acres of timber cutting rights; |
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| • | Horizon Energy Development, Inc. (Horizon), a New York corporation formed to engage in foreign and domestic energy projects through investments as a sole or substantial owner in various business entities. These entities include Horizon’s wholly owned subsidiary, Horizon Energy Holdings, Inc., a New York corporation, which owns 100% of Horizon Energy Development B.V. (Horizon B.V.). Horizon B.V. is a Dutch company that is in the process of winding up or selling certain power development projects in Europe; |
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| • | Horizon Power, Inc. (Horizon Power), a New York corporation which is an “exempt wholesale generator” under PUHCA 2005 and is operating landfill gas electric generation facilities; and |
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| • | National Fuel Gas Midstream Corporation (Midstream Corporation), a Pennsylvania corporation formed to build, own and operate natural gas processing and pipeline gathering facilities in the Appalachian region. |
No single customer, or group of customers under common control, accounted for more than 10% of the Company’s consolidated revenues in 2010.
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 A — Summary of Significant Accounting Policies (Regulatory Mechanisms) and Note C — Regulatory Matters.
The Pipeline and Storage segment’s rates, services and other matters are regulated by the FERC. 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 A — Summary of Significant Accounting Policies (Regulatory Mechanisms) and Note C — 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.
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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 28.5% of the Company’s 2010 income from continuing operations and 27.7% of the Company’s 2010 net income available for common stock.
Additional discussion of the Utility segment appears below in this AmendmentItem 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 16.7% of the Company’s 2010 income from continuing operations and 16.2% of the Company’s 2010 net income available for common stock.
Supply Corporation has service agreements for all of its firm storage capacity, totaling 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 4,811 MDth or 7.1% of the total firm storage capacity. Nonaffiliated customers have contracted for the remaining 35,732 MDth or 52.2% of the total firm storage capacity. The majority of Supply Corporation’s storage and transportation services are 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 extendyear-to-year at the end of the primary term. At the beginning of 2011, 88.1% of Supply Corporation’s total firm storage capacity was committed under contracts that, subject to 2010 shipper or Supply Corporation notifications, could have been terminated effective in 2011. Supply Corporation received storage contract termination notifications in 2010 totaling approximately 5,300 MDth of storage capacity. Supply Corporation expects to remarket this capacity with service beginning April 1, 2011.
Supply Corporation’s firm transportation capacity is not a fixed quantity, due to the diverse web-like 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 2,134 MDth per day (contracted transportation capacity). The Utility segment accounts for approximately 1,065 MDth per day or 49.9% of contracted transportation capacity, and the Energy Marketing and Exploration and Production segments represent another 126 MDth per day or 5.9% of contracted transportation capacity. The remaining 943 MDth or 44.2% of contracted transportation capacity is subject to firm contracts with nonaffiliated customers.
At the beginning of 2011, 53.8% of Supply Corporation’s contracted transportation capacity was committed under affiliate contracts that were scheduled to expire in 2011 or, subject to 2010 shipper or Supply Corporation notifications, could have been terminated effective in 2011. Based on contract expirations and termination notices received in 2010 for 2011 termination, and taking into account any known contract additions, contracted transportation capacity with affiliates is expected to increase 2.5% in 2011. Similarly, 35.9% of contracted transportation capacity was committed under unaffiliated shipper contracts that were scheduled to expire in 2011 or, subject to 2010 shipper or Supply Corporation notifications, could have been terminated effective in 2011. Based on contract expirations and termination notices received in 2010 for 2011 termination, and taking into account any known contract additions, contracted transportation capacity with unaffiliated shippers is expected to decrease 6.6% in 2011. This expected decrease is due largely to the relative increase in the price of natural gas supplies available at the receipt point on the United States/Canadian border at Niagara compared to the price of supplies at the delivery point of Leidy. Supply Corporation previously has been successful in marketing and obtaining executed contracts for available transportation capacity (at discounted rates when necessary), though costlier Niagara pricing will make these efforts more challenging in 2011. Supply Corporation expects to add significant incremental contracted transportation capacity in 2012 in connection with the development of the Marcellus Shale by independent producers.
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At the beginning of 2011, Empire had service agreements in place for firm transportation capacity totaling up to approximately 686 MDth per day (including capacity on the Empire Connector). The majority of Empire’s transportation services are performed under contracts that allow Empire 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 extendyear-to-year at the end of the primary term. At the beginning of 2011, most of Empire’s firm contracted capacity (91.6%) was contracted as long-term full-year deals. One of those contracts expires during 2011, representing approximately 2.5% of Empire’s firm contracted capacity. In addition, Empire has some seasonal (winter-only) contracts that extend for multiple years, representing 2.4% of Empire’s firm contracted capacity. None of those multi-year, seasonal contracts expires during 2011. Arrangements for the remaining 6.0% of Empire’s firm contracted capacity are single-season or single-year contracts that expire during 2011 or potentially expire early in 2012, depending on whether Empire issues or receives termination notices during 2011. Two single-season or single-year contracts expire during 2011, representing 1.1% of Empire’s firm contracted capacity. At the beginning of 2011, the Utility segment accounted for 6.1% of Empire’s firm contracted capacity, and the Energy Marketing segment accounted for 2.0% of Empire’s firm contracted capacity, with the remaining 91.9% of Empire’s firm contracted 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 51.4% of the Company’s 2010 income from continuing operations and 49.8% of the Company’s 2010 net income available for common stock.
Additional discussion of the Exploration and Production segment appears below under the headings “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 4.0% of the Company’s 2010 income from continuing operations and 3.9% of the Company’s 2010 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.
All Other Category and Corporate Operations
The All Other category and Corporate operations incurred a net loss from continuing operations in 2010. The impact of this net loss from continuing operations in relation to the Company’s 2010 income from continuing operations was negative 0.6%. The All Other and Corporate category, including both continuing and discontinued operations, contributed approximately 2.4% of the Company’s 2010 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 September 2010, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. The Company’s landfill gas operations were maintained under the Company’s wholly owned subsidiary, Horizon LFG, which owned and operated these short distance landfill gas pipeline companies. These operations are presented in the Company’s financial statements as discontinued operations.
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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 2010, the Utility segment purchased 67.1 Bcf of gas for delivery to its customers. Gas purchased from producers and suppliers in the southwestern United States and Canada under firm contracts (seasonal and longer) accounted for 53% of these purchases. Purchases of gas under contracts for one month or less accounted for 47% of the Utility segment’s 2010 purchases. Purchases from Chevron Natural Gas (16%), Total Gas & Power North America Inc. (12%) and Tenaska Marketing Ventures (10%) accounted for 38% of the Utility’s 2010 gas purchases. No other producer or supplier provided the Utility segment with more than 10% of its gas requirements in 2010.
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 K — Business Segment Information and Note Q — Supplementary Information for Oil and Gas Producing Activities.
The Energy Marketing segment depends on an adequate supply of natural gas to deliver to its customers. In 2010, this segment purchased 59.6 Bcf of gas, including 58.3 Bcf for delivery to its customers. The remaining 1.3 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. 1 on Form 10-K/A solely636, which was issued in 1992, continue to includereshape the roles of the gas utility industry and the state regulatory commissions. With respect to gas commodity service, in both New York and Pennsylvania, Distribution Corporation has retained a substantial majority of small sales customers. Almost all large-volume load, however, is served by unregulated retail marketers. In New York, approximately 20%, and in Pennsylvania, approximately 5%, of Distribution Corporation’s small-volume residential and commercial customers purchase their supplies from unregulated marketers. Retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation because in both jurisdictions, utility cost of service is recovered through delivery rates and charges, not through charges for gas commodity service. Over the longer run, however, rate design
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changes resulting from further customer migration to marketer service (e.g., “unbundling”) can expose utility companies such as Distribution Corporation to stranded costs and revenue erosion in the absence of compensating rate relief.
Competition for transportation service to 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.
The Utility segment competes in its most vulnerable markets (the large commercial and industrial markets) by offering unbundled, flexible, high quality services. The Utility segment continues to develop or promote new sources and uses of natural gas or new services, rates and contracts.
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 traditional 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. While costlier natural gas pricing at Niagara has decreased the importation and transportation of gas from that receipt point, new productive areas in the Appalachian region related to the development of the Marcellus Shale formation offer the opportunity for increased transportation services. Supply Corporation is pursuing its Northern Access pipeline expansion project to receive natural gas produced from the Marcellus Shale and transport it to key markets of Canada and the northeastern United States. For further discussion of this project, refer to Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters.”
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 of gas received at the Niagara River at Chippawa and, with further expansion, Appalachian-sourced gas. Empire’s location provides it the opportunity to compete for an increased share of the gas transportation markets. As noted above, Empire has constructed the Empire Connector project, which expands its natural gas pipeline and enables Empire to serve new markets in New York and elsewhere in the Northeast. Empire is also pursuing its Tioga County Extension project, which will stretch approximately 16 miles south from its existing interconnection with Millennium Pipeline at Corning, New York, into Tioga County, Pennsylvania. Like Supply Corporation’s Northern Access project, Empire’s Tioga County Extension project is designed to facilitate transportation of Marcellus Shale gas to key markets of Canada and the northeastern United States. 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 and mineral leaseholds.
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.
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Competition: The Energy Marketing Segment
The Energy Marketing segment competes with other marketers of natural gas and with other providers of energy supply. Competition in this area is well developed with regard to price and services from local, regional and national marketers.
Seasonality
Variations in weather conditions can materially affect the volume of natural gas delivered by the Utility segment, as virtually all of its residential and commercial customers use natural 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 warmer than normal results in an upward adjustment to customers’ current bills, while weather that is colder than normal results in a downward adjustment, so that in either case projected operating costs calculated at normal temperatures will be recovered.
Volumes transported and stored by Supply Corporation and volumes transported by Empire may vary materially depending on weather, without materially affecting revenues. Supply Corporation’s and Empire’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.
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.
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 I — Commitments and Contingencies.
Miscellaneous
The Company and its wholly owned or majority-owned subsidiaries had a total of 1,859 full-time employees at September 30, 2010. This compares to 1,949 employees in the Company’s operations at September 30, 2009.
The Company has agreements in place with collective bargaining units in New York and Pennsylvania. The agreements in New York are scheduled to expire in February 2013 and the agreements in Pennsylvania are scheduled to expire in April 2014 and May 2014.
The Utility segment has numerous municipal franchises under which it uses public roads and certain otherrights-of-way and public property for the location of facilities. When necessary, the Utility segment renews such franchises.
The Company makes its annual report onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 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 thisForm 10-K or any other report filed with or furnished to the SEC.
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Executive Officers of the Company as of November 15, 2010(1)
| | |
| | Current Company
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| | Positions and
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| | Other Material
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| | Business Experience
|
Name and Age (as of
| | During Past
|
| November 15, 2010) | | Five Years |
|
David F. Smith
(57) | | Chairman of the Board of Directors of the Company since March 2010 and Chief Executive Officer of the Company since February 2008. Mr. Smith previously served as President of the Company from February 2006 through June 2010; Chief Operating Officer of the Company from February 2006 through January 2008; President of Supply Corporation from April 2005 through June 2008; President of Empire from September 2005 through July 2008; and Vice President of the Company from April 2005 through January 2006. |
Ronald J. Tanski
(58) | | President and Chief Operating Officer of the Company since July 2010. Mr. Tanski previously served as Treasurer and Principal Financial Officer of the Company from April 2004 through June 2010; President of Supply Corporation from July 2008 through June 2010; President of Distribution Corporation from February 2006 through June 2008; Treasurer of Distribution Corporation from April 2004 through July 2008; and Senior Vice President of Distribution Corporation from July 2001 through January 2006. |
Matthew D. Cabell
(52) | | Senior Vice President of the Company since July 2010 and President of Seneca since December 2006. Prior to joining Seneca, Mr. Cabell served as Executive Vice President and General Manager of Marubeni Oil & Gas (USA) Inc., an exploration and production company, from June 2003 to December 2006. Mr. Cabell’s prior employer is not a subsidiary or affiliate of the Company. |
Anna Marie Cellino
(57) | | President of Distribution Corporation since July 2008. Ms. Cellino previously served as Secretary of the Company from October 1995 through June 2008; Secretary of Distribution Corporation from September 1999 through June 2008; and Senior Vice President of Distribution Corporation from July 2001 through June 2008. |
John R. Pustulka
(58) | | President of Supply Corporation since July 2010. Mr. Pustulka previously served as Senior Vice President of Supply Corporation from July 2001 through June 2010. |
David P. Bauer
(41) | | Treasurer and Principal Financial Officer of the Company since July 2010; Treasurer of Supply Corporation since June 2007; Treasurer of Empire since June 2007; and Assistant Treasurer of Distribution Corporation since April 2004. |
Karen M. Camiolo
(51) | | Controller and Principal Accounting Officer of the Company since April 2004; and Controller of Distribution Corporation and Supply Corporation since April 2004. |
Carl M. Carlotti
(55) | | Senior Vice President of Distribution Corporation since January 2008. Mr. Carlotti previously served as Vice President of Distribution Corporation from October 1998 to January 2008. |
Paula M. Ciprich
(50) | | Secretary of the Company since July 2008; General Counsel of the Company since January 2005; Secretary of Distribution Corporation since July 2008. Ms. Ciprich previously served as General Counsel of Distribution Corporation from February 1997 through February 2007 and as Assistant Secretary of Distribution Corporation from February 1997 through June 2008. |
Donna L. DeCarolis
(51) | | Vice President Business Development of the Company since October 2007. Ms. DeCarolis previously served as President of NFR from January 2005 to October 2007; Secretary of NFR from March 2002 to October 2007; and Vice President of NFR from May 2001 to January 2005. |
James D. Ramsdell
(55) | | Senior Vice President of Distribution Corporation since July 2001. |
| | |
| (1) | | The executive officers serve at the pleasure of the Board of Directors. The information provided relates to the Company and its principal subsidiaries. Many of the executive officers also have served or currently serve as officers or directors of other subsidiaries of the Company. |
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As a holding company, the Company depends on its operating subsidiaries to meet its financial obligations.
The Company is a holding company with no significant assets other than the stock of its operating subsidiaries. In order to meet its financial needs, the Company relies exclusively on repayments of principal and interest on intercompany loans made by the Company 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.
The Company is dependent on credit markets to successfully execute its business strategies.
The Company relies upon short-term bank borrowings, commercial paper markets and longer-term capital markets to finance capital requirements not satisfied by cash flow from operations. The Company is dependent on these capital sources to provide capital to its subsidiaries to fund operations, acquire, maintain and develop properties, and execute growth strategies. The availability and cost of credit sources may be cyclical and these capital sources may not remain available to the Company. Turmoil in credit markets may make it difficult for the Company to obtain financing on acceptable terms or at all for working capital, capital expenditures and other investments, or to refinance maturing debt on favorable terms. These difficulties could adversely affect the Company’s growth strategies, operations and financial performance. The Company’s ability to borrow under its credit facilities and commercial paper agreements, and its ability to issue long-term debt under its indentures, depend on the Company’s compliance with its obligations under the facilities, agreements and indentures. In addition, the Company’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, resulting in exposure to interest rate fluctuations in the absence of interest rate hedging transactions. The cost of long-term debt, the interest rates on the Company’s short-term bank loans and the ability of the Company to issue commercial paper are affected by its debt credit ratings published by Standard & Poor’s Ratings Service (“S&P”), Moody’s Investors Service and Fitch Ratings Service. A downgrade in the Company’s credit ratings could increase borrowing costs and negatively impact the availability of capital from banks, commercial paper purchasers and other sources.
The Company may be adversely affected by economic conditions and their impact on our suppliers and customers.
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 the Company’s revenues and cash flows or restrict its future growth. Economic conditions in the Company’s utility service territories and energy marketing territories also impact its collections of accounts receivable. All of the Company’s segments are exposed to risks associated with the creditworthiness or performance of key suppliers and customers, many of which may be adversely affected by volatile conditions in the financial markets. These conditions could result in financial instability or other adverse effects at any of our suppliers or customers. For example, counterparties to the Company’s commodity hedging arrangements or commodity sales contracts might not be able to perform their obligations under these arrangements or contracts. Customers of the Company’s Utility and Energy Marketing segments may have particular trouble paying their bills during periods of declining economic activity and high commodity prices, potentially resulting in increased bad debt expense and reduced earnings. Any of these events could have a material adverse effect on the Company’s results of operations, financial condition and cash flows.
The Company’s credit ratings may not reflect all the risks of an investment in its securities.
The Company’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. The
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Company’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 thisForm 10-K.
The Company’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 the Company 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 the Company’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 increase the Company’s costs or affect its business in ways that the Company cannot predict.
In the Company’s Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the FERC. 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 to the extent 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 established competitive markets in which customers may purchase gas commodity from unregulated marketers, in addition to utility companies. Retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation, because in both jurisdictions, it recovers its cost of service through delivery rates and charges, and not through anymark-up on the gas commodity purchased by its customers. Over the longer run, however, rate design changes resulting from further customer migration to marketer service (“unbundling”) can expose utilities such as Distribution Corporation to stranded costs and revenue erosion in the absence of compensating rate relief.
Both the NYPSC and the PaPUC have instituted proceedings for the purpose of promoting conservation of energy commodities, including natural gas. In New York, Distribution Corporation implemented a Conservation Incentive Program that promotes conservation and efficient use of natural gas by offering customer rebates for high-efficiency appliances, among other things. The intent of conservation and efficiency programs is to reduce customer usage of natural gas. Under traditional volumetric rates, reduced usage by customers results in decreased revenues to the Utility. To prevent revenue erosion caused by conservation, the NYPSC approved a “revenue decoupling mechanism” that renders Distribution Corporation’s New York division financially indifferent to the effects of conservation. In Pennsylvania, although a generic statewide proceeding is pending, the PaPUC has not yet directed Distribution Corporation to implement conservation measures. If the NYPSC were to revoke the revenue decoupling mechanism in a future proceeding or the PaPUC were to adopt a conservation program without a revenue decoupling mechanism or other changes in rate design, reduced customer usage could decrease revenues, forcing Distribution Corporation to file for rate relief.
In New York, aggressive generic statewide programs created under the label of efficiency or conservation continue to generate a sizable utility funding requirement for state agencies that administer those programs. Although utilities are authorized to recover the cost of efficiency and conservation program funding through special rates and surcharges, the resulting upward pressure on customer rates, coupled with increased assessments and taxes, could affect future tolerance for traditional utility rate increases, especially if natural gas commodity costs were to increase.
The Company is subject to the jurisdiction of the FERC with respect to Supply Corporation, Empire and some transactions performed by other Company subsidiaries, including Seneca Resources, Distribution Corporation and NFR. The FERC, among other things, approves the rates that Supply Corporation and Empire may charge to their natural gas transportationand/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
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commissions can also petition the FERC to investigate whether Supply Corporation’s and Empire’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 transportationand/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. The FERC also possesses significant penalty authority with respect to violations of the laws and regulations it administers. Supply Corporation, Empire and, to the extent subject to FERC jurisdiction, the Company’s other subsidiaries are subject to the FERC’s penalty authority.
In the wake of certain pipeline accidents not involving the Company, new laws or regulations may be adopted regarding pipeline safety. Proposals have been made at the federal level with respect to matters such as reporting of pipeline accidents, increased fines for pipeline safety violations, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In addition, unrelated to these safety initiatives, the EPA in April 2010 issued an Advance Notice of Proposed Rulemaking reassessing its regulations governing the use and distribution in commerce of PCBs. The EPA is considering, among other things, a proposal to eliminate by 2020 the PCB use authorization for natural gas pipeline systems, and a proposal to eliminate the authorization for storage of PCB-containing equipment for reuse. The EPA projects that it may issue a Notice of Proposed Rulemaking in March 2012. If as a result of new laws or regulations the Company incurs material costs that it is unable to recover fully through rates or otherwise offset, the Company’s financial condition, results of operations, and cash flows would be adversely affected.
The Company’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 the Company’s capital resources. The Company has issued commercial paper and used short-term borrowings in the past to temporarily finance storage inventories and purchased gas costs, and although the Company 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.
Changes in interest rates may affect the Company’s ability to finance capital expenditures and to refinance maturing debt.
The Company’s ability to finance capital expenditures and to refinance maturing debt will depend in part upon interest rates. 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, the Company’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, the Company’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, the Company’s ability to earn its authorized rate of return may be adversely impacted.
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Fluctuations in oil and natural gas prices could adversely affect revenues, cash flows and profitability.
Operations in the Company’s Exploration and Production segment 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 greenhouse gas emissions and natural gas transportation, royalties, and price controls. The Company sells most of the oil and natural gas that it produces at current market prices rather than through fixed-price contracts, although as discussed below, the Company frequently hedges the price of a significant portion of its future production in the financial markets. The prices the Company receives depend upon factors beyond the Company’s control, including the factors affecting price mentioned above. The Company believes that any prolonged reduction in oil and natural gas prices could restrict its ability to continue the level of exploration and production activity the Company otherwise would pursue, which could have a material adverse effect on its revenues, cash flows and results of operations.
In the Company’s Pipeline and Storage segment, significant changes in the price differential between equivalent quantities of natural gas at different geographic locations or between futures contracts for natural gas having different delivery dates could adversely impact the Company. For example, if the price of natural gas at a particular receipt point on the Company’s pipeline system increases relative to the price of natural gas at other locations, then the volume of natural gas received by the Company at the relatively more expensive receipt point may decrease, or the price the Company charges to transport that natural gas may decrease. Additionally, if the prices of natural gas futures contracts for winter deliveries to locations served by the Pipeline and Storage segment decline relative to the prices of such contracts for summer deliveries (for example, as a result of increased production of natural gas within the Pipeline and Storage segment’s geographic area), then demand for the Company’s natural gas storage services driven by that price differential could decrease. These changes could adversely affect revenues, cash flows and results of operations.
The Company 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, the Company’s Exploration and Production segment regularly 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 the Company’s expected energy production during the upcoming12-month period. These contracts reduce exposure to subsequent price drops but can also limit the Company’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 gas stored underground. The Company’s Pipeline and Storage segment enters into hedging arrangements with respect to certain sales of efficiency gas.
Under applicable accounting rules currently in effect, 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 bemarked-to-market on the income statement without
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regard to an underlying physical transaction. Gains would occur to the extent that natural gas and crude oil hedge prices exceed market prices for the Company’s natural gas and crude oil production, and losses would occur to the extent that market prices for the Company’s natural gas and crude oil production exceed hedge prices.
Use of energy commodity price hedges also exposes the Company 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 the Company’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. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose the Company 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.
ThisForm 10-K contains estimates of the Company’s proved oil and natural gas reserves and the future net cash flows from those reserves that were prepared by the Company’s petroleum engineers and audited by independent petroleum engineers. Petroleum engineers consider many factors and make assumptions in estimating 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 the Company’s reserves will vary from any estimates, and these variations may be material. Accordingly, the accuracy of the Company’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 the Company 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 the Company’s proved reserves is the current market value of the Company’s estimated oil and natural gas reserves. In accordance with SEC requirements that became effective for the Company with itsForm 10-K for the period ended September 30, 2010, the Company bases the estimated discounted future net cash flows from its proved reserves on12-month average prices for oil and natural gas (based on first day of the month prices and adjusted for hedging) and on costs as of the date of the estimate (under prior SEC requirements, the Company utilized market prices as of the last day of the period). 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 the Company’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 the Company’s reserve estimates in the future. 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
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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 the Company’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 the Company’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 the Company’s earnings. The total and timing of actual future production may vary significantly from reserves and production estimates. The Company’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 non-productive wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements, including completion of environmental impact analyses and compliance with other environmental laws and regulations, 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 the Company may not recover all or any portion of its investment. Production can also be delayed or made uneconomic if there is insufficient gathering, processing and transportation capacity available at an economic price to get that production to a location where it can be profitably sold. Without continued successful exploitation or acquisition activities, the Company’s reserves and revenues will decline as a result of its current reserves being depleted by production. The Company cannot make assurances that it will be able to find or acquire additional reserves at acceptable costs.
Financial accounting requirements regarding exploration and production activities may affect the Company’s profitability.
The Company accounts for its exploration and production activities under the full cost method of accounting. Each quarter, the Company 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 uses12-month average prices for oil and natural gas (based on first day of the month prices and 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 the Company to recognize an immediate expense in that quarter, and its earnings would be reduced. Depending on the magnitude of any decrease in average prices, that charge could be material.
Environmental regulation significantly affects the Company’s business.
The Company’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 and greenhouse gases into the environment, the reporting of such matters, and the general protection of public health, natural resources, wildlife and the environment. Costs of compliance and liabilities could negatively affect the Company’s results of operations, financial condition and cash flows. In addition, compliance with environmental laws and regulations could require unexpected capital expenditures at the Company’s facilities or delay or cause the cancellation of expansion projects or oil and natural gas drilling
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activities. Because the costs of complying with environmental regulations are significant, additional regulation could negatively affect the Company’s business. Although the Company cannot predict the impact of the interpretation or enforcement of EPA standards or other federal, state and local laws or regulations, the Company’s costs could increase if environmental laws and regulations change.
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. The EPA has determined that stationary sources of significant greenhouse gas emissions will be required under the federal Clean Air Act to obtain permits covering such emissions beginning in January 2011. In addition, the U.S. Congress has been considering bills that would establish acap-and-trade program to reduce emissions of greenhouse gases. Legislation or regulation that restricts greenhouse gas emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilitiesand/or purchase emission allowances. International, federal, state or regional climate change and greenhouse gas initiatives could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, or impose additional monitoring and reporting requirements. Climate change and greenhouse gas initiatives, and incentives to conserve energy or use alternative energy sources, could also reduce demand for oil and natural gas. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
Increased regulation of exploration and production activities, including hydraulic fracturing, could adversely impact the Company.
Due to the burgeoning Marcellus Shale natural gas play in the northeast United States, together with the fiscal difficulties faced by state governments in New York and Pennsylvania, various state legislative and regulatory initiatives regarding the exploration and production business have been proposed. These initiatives include potential new or updated statutes and regulations governing the drilling, casing, cementing, testing and monitoring of wells, the protection of water supplies, hydraulic fracturing of wells, surface owners’ rights and damage compensation, the spacing of wells, and environmental and safety issues regarding natural gas pipelines. New severance taxes for oil and gas production are also possible. Additionally, legislative initiatives in the U.S. Congress and regulatory studies, proceedings or initiatives at federal or state agencies focused on the hydraulic fracturing process could result in additional permitting, compliance, reporting and disclosure requirements. If adopted, any such new state or federal legislation or regulation could lead to operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risks of litigation for the Company’s Exploration and Production segment.
The nature of the Company’s operations presents inherent risks of loss that could adversely affect its results of operations, financial condition and cash flows.
The Company’s operations in its various reporting 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, the Company’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, the Company maintains insurance coverage against some, but not all, potential losses. In addition, many of the agreements that the Company executes with contractors provide for the division of responsibilities between the contractor and the Company, and the Company seeks to obtain an indemnification from the contractor for certain of these risks. The Company is not always able, however, to secure written agreements with its contractors that contain indemnification, and sometimes the Company is required to indemnify others.
Insurance or indemnification agreements when obtained may not adequately protect the Company 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
17
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 the Company. 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, the Company 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 the Company’s results of operations, financial condition and cash flows.
Hazards and risks faced by the Company, and insurance and indemnification obtained or provided by the Company, may subject the Company to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines or penalties against the Company or be resolved on unfavorable terms, the result of which could have a material adverse effect on the Company’s results of operations, financial condition and cash flows.
The increasing costs of certain employee and retiree benefits could adversely affect the Company’s results.
The Company’s earnings and cash flow may be impacted by the amount of income or expense it expends or records for employee benefit plans. This is particularly true for pension and other post-retirement benefit plans, which are dependent on actual plan asset returns and factors used to determine the value and current costs of plan benefit obligations. In addition, if medical costs rise at a rate faster than the general inflation rate, the Company might not be able to mitigate the rising costs of medical benefits. Increases to the costs of pension, other post-retirement and medical benefits could have an adverse effect on the Company’s financial results.
Significant shareholders or potential shareholders may attempt to effect changes at the Company or acquire control over the Company, which could adversely affect the Company’s results of operations and financial condition.
In January 2008, the Company entered into an agreement with New Mountain Vantage GP, L.L.C. (“New Mountain”) and certain parties related to New Mountain, including the California Public Employees’ Retirement System (collectively, “Vantage”), to settle a proxy contest pertaining to the election of directors to the Company’s Board of Directors at the Company’s 2008 Annual Meeting of Stockholders. That settlement agreement expired on September 15, 2009. Vantage or other existing or potential shareholders may engage in proxy solicitations or advance shareholder proposals after the Company’s 2011 Annual Meeting of Stockholders, or otherwise attempt to effect changes or acquire control over the Company.
Campaigns by shareholders to effect changes at publicly traded companies are sometimes led by investors seeking to increase short-term shareholder value through actions such as financial restructuring, increased debt, special dividends, stock repurchases or sales of assets or the entire company. Responding to proxy contests and other actions by activist shareholders can be costly and time-consuming, disrupting the Company’s operations and diverting the attention of the Company’s Board of Directors and senior management from the pursuit of business strategies. As a result, shareholder campaigns could adversely affect the Company’s results of operations and financial condition.
| |
| Item 1B | Unresolved Staff Comments |
None
General Information on Facilities
The net investment of the Company in property, plant and equipment was $3.5 billion at September 30, 2010. Approximately 59% of this investment was in the Utility and Pipeline and Storage segments, whose
18
operations are located primarily 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 (39%), is primarily located in California, in the Appalachian region of the United States, and in the shallow waters of the Gulf Coast region of Texas and Louisiana. The remaining net investment in property, plant and equipment consisted of the All Other and Corporate operations (2%). 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 $610.9 million, or 21.5%, since 2005. In September 2010, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. The net property, plant and equipment of the landfill gas operations at the date of sale was $8.8 million. In addition, 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.
The Utility segment had a net investment in property, plant and equipment of $1.2 billion at September 30, 2010. The net investment in its gas distribution network (including 14,836 miles of distribution pipeline) and its service connections to customers represent approximately 51% and 34%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2010.
The Pipeline and Storage segment had a net investment of $858.2 million in property, plant and equipment at September 30, 2010. Transmission pipeline represents 41% of this segment’s total net investment and includes 2,356 miles of pipeline utilized to move large volumes of gas throughout its service area. Storage facilities represent 20% of this segment’s total net investment and consist of 31 storage fields, four of which are jointly owned and operated with certain pipeline suppliers, and 431 miles of pipeline. Net investment in storage facilities includes $86.3 million of gas stored underground-noncurrent, representing the cost of the gas utilized 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 31 compressor stations with 98,194 installed compressor horsepower that represent 13% 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 $1.3 billion at September 30, 2010.
The Utility and Pipeline and Storage segments’ facilities provided the capacity to meet the Company’s 2010 peak day sendout, including transportation service, of 1,608 MMcf, which occurred on January 11, 2010. Withdrawals from storage of 595.4 MMcf provided approximately 37.0% of the requirements on that day.
Company maps are included in exhibit 99.2 of thisForm 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, and in the shallow waters of the Gulf Coast region of Texas and Louisiana. The Company has been increasing its emphasis in the Appalachian region, primarily in the Marcellus Shale, and has been decreasing its emphasis in the Gulf Coast region. 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 oil and gas producing activities is included in Item 8, Note Q — Supplementary Information for Oil and Gas Producing Activities. Note Q sets forth proved developed and undeveloped reserve information for Seneca. The September 30, 2010 reserves shown in Note Q have been impacted by the SEC’s final rule on Modernization of Oil and Gas Reporting. The most notable change of the final rule includes the replacement of the single day period-end pricing used to value oil and gas reserves with an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. The reserves were estimated by Seneca’s geologists and engineers and were audited by independent petroleum engineers from Netherland, Sewell & Associates, Inc.
19
The Company’s proved oil and gas reserve estimates are prepared by the Company’s reservoir engineers who meet the qualifications of Reserve Estimator per the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance.
The Company’s Vice President of Reservoir Engineering is the primary technical person responsible for overseeing the Company’s reserve estimation process and engaging and overseeing the third party reserve audit. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 25 years of Petroleum Engineering experience with both major and independent oil and gas companies. He has maintained oversight of the Company’s reserve estimation process for the past seven years. He is a member of the Society of Petroleum Engineers and a Registered Professional Engineer in the State of Texas.
The Company maintains a system of internal controls over the reserve estimation process. Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model to determine the reserves. The Vice President of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions. Access to the Reserve database is restricted. Significant changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the Company’s internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls.
All of the Company’s reserve estimates are audited annually by Netherland, Sewell and Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve quantities in the United States and internationally under the Texas Board of Professional Engineers RegistrationNo. F-002699. The primary technical persons (employed by NSAI) that are responsible for leading the audit include an engineer registered with the State of Texas (with 12 years of experience in petroleum engineering and six years of experience in the estimation and evaluation of reserves) and a Certified Petroleum Geologist and Geophysicist in the State of Texas (with 32 years of experience in petroleum geosciences and 21 years of experience in the estimation and evaluation of reserves). NSAI was satisfied with the methods and procedures used by the Company to prepare its reserve estimates at September 30, 2010 and did not identify any problems which would cause it to take exception to those estimates.
The reliable technologies that were utilized in estimating the reserves include wire line open-hole log data, performance data, log cross sections, core data, and statistical analysis. The statistical method utilized production performance from both the Company’s and competitor’s wells. Geophysical data include data from the Company’s wells, published documents, and state data-sites and were used to confirm continuity of the formation. Extension and discovery reserves added as a result of reliable technologies were not material.
Seneca’s proved developed and undeveloped natural gas reserves increased from 249 Bcf at September 30, 2009 to 428 Bcf at September 30, 2010. This increase is attributed primarily to extensions and discoveries (193.1 Bcf), primarily in the Appalachian region (190.0 Bcf), and revisions of previous estimates (16.7 Bcf). This increase was partially offset by production of 30.3 Bcf. Seneca’s proved developed and undeveloped oil reserves decreased from 46,587 Mbbl at September 30, 2009 to 45,239 Mbbl at September 30, 2010. This decrease is attributed to production (3,220 Mbbl), primarily occurring in the West Coast region (2,669 Mbbl). This decrease was partly offset by extensions and discoveries (1,054 Mbbl) and revisions of previous estimates (818 Mbbl). On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 528 Bcfe at September 30, 2009 to 700 Bcfe at September 30, 2010.
Seneca’s proved developed and undeveloped natural gas reserves increased from 226 Bcf at September 30, 2008 to 249 Bcf at September 30, 2009. This increase is attributed primarily to extensions and discoveries (59.2 Bcf), primarily in the Appalachian region (49.2 Bcf). This increase was partially offset by production of 22.3 Bcf, negative revisions of previous estimates (9.6 Bcf) and sales of minerals in place (4.7 Bcf) in the Gulf Coast region. Seneca’s proved developed and undeveloped oil reserves increased from 46,198 Mbbl at September 30, 2008 to 46,587 Mbbl at September 30, 2009. This increase is attributed to purchases of minerals in place (2,115 Mbbl) in the West Coast region, extensions and discoveries (1,213 Mbbl), and revisions of previous estimates (449 Mbbl). These increases were largely offset by production (3,373 Mbbl), primarily occurring in the West Coast region (2,674 Mbbl). On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 503 Bcfe at September 30, 2008 to 528 Bcfe at September 30, 2009.
20
The Company’s proved undeveloped (PUD) reserves increased from 87 Bcfe at September 30, 2009 to 177 Bcfe at September 30, 2010. Undeveloped reserves in the Marcellus Shale increased from 11 Bcf at September 30, 2009 to 110 Bcf at September 30, 2010. There was a material increase in undeveloped reserves at September 30, 2010 as a result of its Marcellus Shale reserve additions. The increase in undeveloped reserves in the Marcellus Shale is partially attributable to the change in SEC regulations allowing the recognition of PUD reserves more than one direct offset location away from existing production with reasonable certainty using reliable technology. The Company’s total PUD reserves are 25% of total proved reserves at September 30, 2010, up from 16% of total proved reserves at September 30, 2009.
The increase in PUD reserves in 2010 of 90 Bcfe is a result of 111 Bcfe in new PUD reserve additions (105 Bcfe from the Marcellus Shale), offset by 17 Bcfe in PUD conversions to developed reserves and 4 Bcfe in downward PUD revisions. The downward revisions were primarily from the removal of 51 PUD locations in the Upper Devonian play. This was the result of Seneca’s decision in 2010 to significantly reduce its5-year investment plan for the Upper Devonian as a result of lower forward gas price expectations. The Company invested $28.9 million during the year ended September 30, 2010 to convert 17 Bcfe of PUD reserves to developed reserves. This represents 19% of the PUD reserves booked at September 30, 2009. In 2011, the Company estimates that it will invest approximately $140 million to develop the PUD reserves. The Company is committed to developing its PUD reserves within five years of being recorded as PUD reserves as required by the SEC’s final rule on Modernization of Oil and Gas Reporting.
At September 30, 2010, the Company does not have a material concentration of proved undeveloped reserves that have been on the books for more than five years at the corporate level or country level. All of the Company’s proved reserves are in the United States. At the field level, only at the North Lost Hills Field in Kern County, California, does the Company have a material concentration of undeveloped reserves that have been on the books for more than five years. The Company has reduced the concentration of undeveloped reserves in this field from 61% of total field level reserves at September 30, 2005 to 24% of total field level reserves at September 30, 2010. The Company has been actively drilling undeveloped locations in this field for four out of the past five years, drilling 53 undeveloped locations and converting 3.1 million barrels of proved reserves from undeveloped to developed reserves. The undeveloped reserves in this field represent less than 2% of the Company’s proved reserves at the corporate level. The Company is committed to drilling the remaining proved undeveloped locations within five years of being recorded as PUD reserves.
At September 30, 2010, the Company had delivery commitments of 34 Bcf. The Company expects to meet those commitments through proved reserves and the future development of reserves that are currently classified as proved undeveloped reserves and does not anticipate any issues or constraints that would prevent the Company from meeting these commitments.
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.
Production
| | | | | | | | | | | | | |
| | | For The Year Ended September 30 |
| | | 2010 | | 2009 | | 2008 |
| |
United States | | | | | | | | | | | | |
| Gulf Coast Region | | | | | | | | | | | | |
| Average Sales Price per Mcf of Gas | | $ | 5.22 | | | $ | 4.54 | | | $ | 10.03 | |
| Average Sales Price per Barrel of Oil | | $ | 76.57 | | | $ | 54.58 | | | $ | 107.27 | |
| Average Sales Price per Mcf of Gas (after hedging) | | $ | 5.51 | | | $ | 5.28 | | | $ | 9.49 | |
| Average Sales Price per Barrel of Oil (after hedging) | | $ | 77.18 | | | $ | 54.58 | | | $ | 98.56 | |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | | $ | 1.15 | | | $ | 1.36 | | | $ | 1.19 | |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | | | 37 | | | | 38 | | | | 38 | |
21
| | | | | | | | | | | | | |
| | | For The Year Ended September 30 |
| | | 2010 | | 2009 | | 2008 |
| |
| West Coast Region | | | | | | | | | | | | |
| Average Sales Price per Mcf of Gas | | $ | 4.81 | | | $ | 3.91 | | | $ | 8.71 | |
| Average Sales Price per Barrel of Oil | | $ | 71.72 | (1) | | $ | 50.90 | (1) | | $ | 98.17 | (1) |
| Average Sales Price per Mcf of Gas (after hedging) | | $ | 7.02 | | | $ | 7.37 | | | $ | 8.22 | |
| Average Sales Price per Barrel of Oil (after hedging) | | $ | 74.88 | (1) | | $ | 67.61 | (1) | | $ | 77.64 | (1) |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | | $ | 1.71 | (1) | | $ | 1.38 | (1) | | $ | 1.76 | (1) |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | | | 54 | (1) | | | 55 | (1) | | | 51 | (1) |
| Appalachian Region | | | | | | | | | | | | |
| Average Sales Price per Mcf of Gas | | $ | 4.93 | (2) | | $ | 5.52 | | | $ | 9.73 | |
| Average Sales Price per Barrel of Oil | | $ | 75.81 | | | $ | 56.15 | | | $ | 97.40 | |
| Average Sales Price per Mcf of Gas (after hedging) | | $ | 6.15 | | | $ | 8.69 | | | $ | 8.85 | |
| Average Sales Price per Barrel of Oil (after hedging) | | $ | 75.81 | | | $ | 56.15 | | | $ | 97.40 | |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | | $ | 0.73 | (2) | | $ | 0.87 | | | $ | 0.70 | |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | | | 45 | (2) | | | 24 | | | | 22 | |
Total Company | | | | | | | | | | | | |
| Average Sales Price per Mcf of Gas | | $ | 5.01 | | | $ | 4.79 | | | $ | 9.70 | |
| Average Sales Price per Barrel of Oil | | $ | 72.54 | | | $ | 51.69 | | | $ | 99.64 | |
| Average Sales Price per Mcf of Gas (after hedging) | | $ | 6.04 | | | $ | 6.94 | | | $ | 9.05 | |
| Average Sales Price per Barrel of Oil (after hedging) | | $ | 75.25 | | | $ | 64.94 | | | $ | 81.75 | |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | | $ | 1.24 | | | $ | 1.27 | | | $ | 1.36 | |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | | | 136 | | | | 116 | | | | 111 | |
| | |
| (1) | | The Midway Sunset North fields (which exceed 15% of total reserves) contributed 25 MMcfe, 28 MMcfe and 26 MMcfe of production per day, at average sales prices (per bbl) of $69.68 ($75.75 after hedging), $48.87 ($75.47 after hedging), and $95.82 ($63.90 after hedging) for 2010, 2009 and 2008, respectively. Lifting costs (per Mcfe) were $1.90, $1.34 and $2.01 for 2010, 2009 and 2008, respectively. |
|
| (2) | | The Marcellus Shale fields (which exceed 15% of total reserves) contributed 20 MMcfe of daily production at an average sales price (per Mcfe) of $4.56 (before hedging) and lifting costs (per Mcfe) of $0.55 during 2010. The Company did not hedge Marcellus Shale production during 2010. |
Productive Wells
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Gulf Coast
| | West Coast
| | Appalachian
| | |
| | | Region | | Region | | Region | | Total Company |
| At September 30, 2010 | | Gas | | Oil | | Gas | | Oil | | Gas | | Oil | | Gas | | Oil |
| |
| Productive Wells — Gross | | | 19 | | | | 40 | | | | — | | | | 1,542 | | | | 2,974 | | | | 6 | | | | 2,993 | | | | 1,588 | |
| Productive Wells — Net | | | 10 | | | | 13 | | | | — | | | | 1,508 | | | | 2,865 | | | | 5 | | | | 2,875 | | | | 1,526 | |
22
Developed and Undeveloped Acreage
| | | | | | | | | | | | | | | | | |
| | | Gulf
| | West
| | | | |
| | | Coast
| | Coast
| | Appalachian
| | Total
|
| At September 30, 2010 | | Region | | Region | | Region | | Company |
| |
| Developed Acreage | | | | | | | | | | | | | | | | |
| — Gross | | | 74,248 | | | | 13,830 | | | | 522,158 | | | | 610,236 | |
| — Net | | | 49,436 | | | | 11,622 | | | | 498,701 | | | | 559,759 | |
| Undeveloped Acreage | | | | | | | | | | | | | | | | |
| — Gross | | | 90,573 | | | | 5,190 | | | | 430,865 | | | | 526,628 | |
| — Net | | | 75,427 | | | | 934 | | | | 412,464 | | | | 488,825 | |
| Total Developed and Undeveloped Acreage | | | | | | | | | | | | | | | | |
| — Gross | | | 164,821 | | | | 19,020 | | | | 953,023 | | | | 1,136,864 | |
| — Net | | | 124,863 | | | | 12,556 | | | | 911,165 | | | | 1,048,584 | |
As of September 30, 2010, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 61,167 acres in 2011 (45,775 net acres), 9,055 acres in 2012 (7,634 net acres), 40,173 acres in 2013 (39,151 net acres), and 66,877 acres thereafter (58,716 net acres). The remaining 349,356 gross acres (337,549 net acres) represent non-expiring oil and gas rights owned by the Company.
Drilling Activity
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Productive | | Dry |
| For the Year Ended September 30 | | 2010 | | 2009 | | 2008 | | 2010 | | 2009 | | 2008 |
| |
United States | | | | | | | | | | | | | | | | | | | | | | | | |
| Gulf Coast Region | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | |
| — Exploratory | | | 0.29 | | | | 0.29 | | | | 1.14 | | | | — | | | | — | | | | 0.37 | |
| — Development | | | — | | | | — | | | | — | | | | — | | | | 0.30 | | | | — | |
| West Coast Region | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | |
| — Exploratory | | | — | | | | — | | | | 1.00 | | | | — | | | | — | | | | — | |
| — Development | | | 41.72 | | | | 27.00 | | | | 62.00 | | | | — | | | | — | | | | 1.00 | |
| Appalachian Region | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | |
| — Exploratory | | | 33.00 | | | | 2.00 | | | | 8.00 | | | | 2.00 | | | | 3.00 | | | | 1.00 | |
| — Development | | | 131.55 | | | | 250.00 | | | | 186.00 | | | | 3.00 | | | | — | | | | — | |
| Total United States | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | |
| — Exploratory | | | 33.29 | | | | 2.29 | | | | 10.14 | | | | 2.00 | | | | 3.00 | | | | 1.37 | |
| — Development | | | 173.27 | | | | 277.00 | | | | 248.00 | | | | 3.00 | | | | 0.30 | | | | 1.00 | |
Present Activities
| | | | | | | | | | | | | | | | | |
| | | Gulf
| | West
| | | | |
| | | Coast
| | Coast
| | Appalachian
| | Total
|
| At September 30, 2010 | | Region | | Region | | Region | | Company |
| |
| Wells in Process of Drilling(1) | | | | | | | | | | | | | | | | |
| — Gross | | | 1.00 | | | | — | | | | 85.00 | | | | 86.00 | |
| — Net | | | 0.20 | | | | — | | | | 66.62 | | | | 66.82 | |
| | |
| (1) | | Includes wells awaiting completion. |
23
For a discussion of various environmental and other matters, refer to Part II, Item 7, MD&A and Item 8 at Note I — Commitments and Contingencies. In addition to these matters, 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 are they expected to have a material adverse effect on the financial condition of the Company.
PART II
| |
| Item 5 | Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Information regarding the market for the Company’s common equity and related stockholder matters appears under Item 12 at Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, Item 8 at Note E — Capitalization and Short-Term Borrowings, and at Note P — Market for Common Stock and Related Shareholder Matters (unaudited).
On July 1, 2010, the Company issued a total of 3,600 unregistered shares of Company common stock to the nine non-employee directors of the Company then serving on the Board of Directors of the Company, 400 shares to each such director. All of these unregistered shares were issued under the Company’s Retainer Policy for Non-Employee Directors as partial consideration for such directors’ services during the quarter ended September 30, 2010. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933, as transactions not involving a public offering.
Issuer Purchases of Equity Securities
| | | | | | | | | | | | | | | | | |
| | | | | | | | | Total Number
| | | Maximum Number
| |
| | | | | | | | | of Shares
| | | of Shares
| |
| | | | | | | | | Purchased as
| | | that May
| |
| | | | | | | | | Part of
| | | Yet Be
| |
| | | | | | | | | Publicly Announced
| | | Purchased Under
| |
| | | Total Number
| | | Average Price
| | | Share Repurchase
| | | Share Repurchase
| |
| | | of Shares
| | | Paid per
| | | Plans or
| | | Plans or
| |
| Period | | Purchased(a) | | | Share | | | Programs | | | Programs(b) | |
| |
| July 1-31, 2010 | | | 8,383 | | | $ | 47.90 | | | | — | | | | 6,971,019 | |
| Aug. 1-31, 2010 | | | 10,906 | | | $ | 45.60 | | | | — | | | | 6,971,019 | |
| Sept. 1-30, 2010 | | | 161,520 | | | $ | 51.52 | | | | — | | | | 6,971,019 | |
| | | | | | | | | | | | | | | | | |
| Total | | | 180,809 | | | $ | 51.00 | | | | — | | | | 6,971,019 | |
| | | | | | | | | | | | | | | | | |
| | |
| (a) | | Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock options or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes. During the quarter ended September 30, 2010, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 180,809 shares purchased other than through a publicly announced share repurchase program, 26,277 were purchased for the Company’s 401(k) plans and 154,532 were purchased as a result of shares tendered to the Company by holders of stock options or shares of restricted stock. |
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| (b) | | In December 2005, the Company’s Board of Directors authorized the repurchase of up to eight million shares of the Company’s common stock. The Company completed the repurchase of the eight million shares during 2008. In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares of the Company’s common stock. The Company, however, stopped |
24
| | |
| | repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. Since that time, the Company has increased its emphasis on Marcellus Shale development and pipeline expansion. As such, the Company does not anticipate repurchasing any shares in the near future. |
| |
| Item 6 | Selected Financial Data |
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | | | 2007 | | | 2006 | |
| | | (Thousands, except per share amounts and number of registered shareholders) | |
| |
Summary of Operations | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 1,760,503 | | | $ | 2,051,543 | | | $ | 2,396,837 | | | $ | 2,034,400 | | | $ | 2,236,369 | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Expenses: | | | | | | | | | | | | | | | | | | | | |
| Purchased Gas | | | 658,432 | | | | 997,216 | | | | 1,238,405 | | | | 1,019,349 | | | | 1,269,109 | |
| Operation and Maintenance | | | 394,569 | | | | 401,200 | | | | 429,394 | | | | 395,704 | | | | 395,226 | |
| Property, Franchise and Other Taxes | | | 75,852 | | | | 72,102 | | | | 75,525 | | | | 70,589 | | | | 69,129 | |
| Depreciation, Depletion and Amortization | | | 191,199 | | | | 170,620 | | | | 169,846 | | | | 157,142 | | | | 151,220 | |
| Impairment of Oil and Gas Producing Properties | | | — | | | | 182,811 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 1,320,052 | | | | 1,823,949 | | | | 1,913,170 | | | | 1,642,784 | | | | 1,884,684 | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income | | | 440,451 | | | | 227,594 | | | | 483,667 | | | | 391,616 | | | | 351,685 | |
| Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
| Income from Unconsolidated Subsidiaries | | | 2,488 | | | | 3,366 | | | | 6,303 | | | | 4,979 | | | | 3,583 | |
| Impairment of Investment in Partnership | | | — | | | | (1,804 | ) | | | — | | | | — | | | | — | |
| Other Income | | | 3,638 | | | | 8,200 | | | | 7,164 | | | | 6,995 | | | | 5,544 | |
| Interest Income | | | 3,729 | | | | 5,776 | | | | 10,815 | | | | 1,550 | | | | 9,409 | |
| Interest Expense on Long-Term Debt | | | (87,190 | ) | | | (79,419 | ) | | | (70,099 | ) | | | (68,446 | ) | | | (72,629 | ) |
| Other Interest Expense | | | (6,756 | ) | | | (7,370 | ) | | | (3,271 | ) | | | (4,155 | ) | | | (4,050 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Income from Continuing Operations Before Income Taxes | | | 356,360 | | | | 156,343 | | | | 434,579 | | | | 332,539 | | | | 293,542 | |
| Income Tax Expense | | | 137,227 | | | | 52,859 | | | | 167,672 | | | | 131,291 | | | | 108,241 | |
| | | | | | | | | | | | | | | | | | | | | |
| Income from Continuing Operations | | | 219,133 | | | | 103,484 | | | | 266,907 | | | | 201,248 | | | | 185,301 | |
| | | | | | | | | | | | | | | | | | | | | |
| Discontinued Operations: | | | | | | | | | | | | | | | | | | | | |
| Income (Loss) from Operations, Net of Tax | | | 470 | | | | (2,776 | ) | | | 1,821 | | | | 15,906 | | | | (47,210 | ) |
| Gain on Disposal, Net of Tax | | | 6,310 | | | | — | | | | — | | | | 120,301 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| Income (Loss) from Discontinued Operations, Net of Tax | | | 6,780 | | | | (2,776 | ) | | | 1,821 | | | | 136,207 | | | | (47,210 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net Income Available for Common Stock | | $ | 225,913 | | | $ | 100,708 | | | $ | 268,728 | | | $ | 337,455 | | | $ | 138,091 | |
| | | | | | | | | | | | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | | | 2007 | | | 2006 | |
| | | (Thousands, except per share amounts and number of registered shareholders) | |
| |
Per Common Share Data | | | | | | | | | | | | | | | | | | | | |
| Basic Earnings from Continuing Operations per Common Share | | $ | 2.70 | | | $ | 1.29 | | | $ | 3.25 | | | $ | 2.42 | | | $ | 2.21 | |
| Diluted Earnings from Continuing Operations per Common Share | | $ | 2.65 | | | $ | 1.28 | | | $ | 3.16 | | | $ | 2.36 | | | $ | 2.16 | |
| Basic Earnings per Common Share(1) | | $ | 2.78 | | | $ | 1.26 | | | $ | 3.27 | | | $ | 4.06 | | | $ | 1.64 | |
| Diluted Earnings per Common Share(1) | | $ | 2.73 | | | $ | 1.25 | | | $ | 3.18 | | | $ | 3.96 | | | $ | 1.61 | |
| Dividends Declared | | $ | 1.36 | | | $ | 1.32 | | | $ | 1.27 | | | $ | 1.22 | | | $ | 1.18 | |
| Dividends Paid | | $ | 1.35 | | | $ | 1.31 | | | $ | 1.26 | | | $ | 1.21 | | | $ | 1.17 | |
| Dividend Rate at Year-End | | $ | 1.38 | | | $ | 1.34 | | | $ | 1.30 | | | $ | 1.24 | | | $ | 1.20 | |
| At September 30: | | | | | | | | | | | | | | | | | | | | |
Number of Registered Shareholders | | | 15,549 | | | | 16,098 | | | | 16,544 | | | | 16,989 | | | | 17,767 | |
| | | | | | | | | | | | | | | | | | | | | |
Net Property, Plant and Equipment | | | | | | | | | | | | | | | | | | | | |
| Utility | | $ | 1,165,240 | | | $ | 1,144,002 | | | $ | 1,125,859 | | | $ | 1,099,280 | | | $ | 1,084,080 | |
| Pipeline and Storage | | | 858,231 | | | | 839,424 | | | | 826,528 | | | | 681,940 | | | | 674,175 | |
| Exploration and Production(2) | | | 1,338,956 | | | | 1,041,846 | | | | 1,095,960 | | | | 982,698 | | | | 1,002,265 | |
| Energy Marketing | | | 436 | | | | 71 | | | | 98 | | | | 102 | | | | 59 | |
| All Other(3) | | | 81,103 | | | | 99,787 | | | | 98,338 | | | | 106,637 | | | | 108,333 | |
| Corporate | | | 6,263 | | | | 6,915 | | | | 7,317 | | | | 7,748 | | | | 8,814 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Net Plant | | $ | 3,450,229 | | | $ | 3,132,045 | | | $ | 3,154,100 | | | $ | 2,878,405 | | | $ | 2,877,726 | |
| | | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 5,105,625 | | | $ | 4,769,129 | | | $ | 4,130,187 | | | $ | 3,888,412 | | | $ | 3,763,748 | |
| | | | | | | | | | | | | | | | | | | | | |
Capitalization | | | | | | | | | | | | | | | | | | | | |
| Comprehensive Shareholders’ Equity | | $ | 1,745,971 | | | $ | 1,589,236 | | | $ | 1,603,599 | | | $ | 1,630,119 | | | $ | 1,443,562 | |
| Long-Term Debt, Net of Current Portion | | | 1,049,000 | | | | 1,249,000 | | | | 999,000 | | | | 799,000 | | | | 1,095,675 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Capitalization | | $ | 2,794,971 | | | $ | 2,838,236 | | | $ | 2,602,599 | | | $ | 2,429,119 | | | $ | 2,539,237 | |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Includes discontinued operations. |
|
| (2) | | Includes net plant of SECI discontinued operations as follows: $0 for 2010, 2009, 2008 and 2007, and $88,023 for 2006. |
|
| (3) | | Includes net plant of landfill gas discontinued operations as follows: $0 for 2010, $9,296 for 2009, $11,870 for 2008, $12,516 for 2007, and $13,206 for 2006. |
| |
| Item 7 | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
OVERVIEW
The Company is a diversified energy company and reports financial results for four business segments. Refer to Item 1, Business, for a more detailed description of each of the segments. This Item 7, MD&A, provides information concerning:
| | |
| 1. | The critical accounting estimates of the Company; |
|
| 2. | Changes in revenues and earnings of the Company under the heading, “Results of Operations;” |
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| | |
| 3. | Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity;” |
|
| 4. | Off-Balance Sheet Arrangements; |
|
| 5. | Contractual Obligations; and |
|
| 6. | Other Matters, including: (a) 2010 and projected 2011 funding for the Company’s pension and other post-retirement benefits, (b) realizability of deferred tax assets, (c) disclosures and tables concerning market risk sensitive instruments, (d) rate and regulatory matters in the Company’s New York, Pennsylvania and FERC regulated jurisdictions, (e) environmental matters, and (f) new authoritative accounting and financial reporting guidance. |
The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report.
For the year ended September 30, 2010 compared to the year ended September 30, 2009, the Company experienced an increase in earnings of $125.2 million. Earnings from continuing operations increased $115.6 million and earnings from discontinued operations increased $9.6 million. From a continuing operations perspective, the earnings increase was primarily driven by the non-recurrence of an impairment charge of $182.8 million ($108.2 million after tax) recorded in the Exploration and Production segment during the year ended September 30, 2009. 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. Such costs are subject to a quarterly ceiling test prescribed by SECRegulation S-XRule 4-10 that determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. At December 31, 2008, due to significant declines in crude oil and natural gas commodity prices (and using the SEC full cost rules then in effect), the book value of the Company’s oil and gas properties exceeded the ceiling, resulting in the impairment charge mentioned above. For further discussion of the ceiling test results at September 30, 2010 and a sensitivity analysis to changes in crude oil and natural gas commodity prices, refer to the Critical Accounting Estimates section below. For further discussion of the Company’s earnings, refer to the Results of Operations section below.
The Company continues to focus on the development of its Marcellus Shale acreage in the Appalachian region of its Exploration and Production segment. The Marcellus Shale is a Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York. Due to the depth at which this formation is found, drilling and completion costs, including the drilling and completion of horizontal wells with hydraulic fracturing, are very expensive. However, independent geological studies have indicated that this formation could yield natural gas reserves measured in the trillions of cubic feet. The Company controls approximately 745,000 net acres within the Marcellus Shale area, with a majority of the acreage held in fee, carrying no royalty and no lease expirations. The Company’s reserve base has grown substantially from development in the Marcellus Shale. Natural gas proved developed and undeveloped reserves in the Appalachian region have increased from 150 Bcf at September 30, 2009 to 331 Bcf at September 30, 2010. With this in mind, and with a natural desire to realize the value of these assets in a responsible and orderly fashion, the Company has spent significant amounts of capital in this region. For the year ended September 30, 2010, the Company spent $332.4 million towards the development of the Marcellus Shale. This included paying $71.8 million in March 2010 for two tracts of leasehold acreage (consisting of approximately 18,000 net acres) in Tioga and Potter Counties in Pennsylvania. These tracts are geologically and geographically similar to the Company’s existing Marcellus Shale acreage in the area, and will help the Company continue its developmental drilling program.
The Company has engaged Jefferies & Company to explore joint-venture opportunities across its Marcellus Shale acreage in its Exploration and Production segment. It is the Company’s goal to ramp up Marcellus Shale development faster than its current plans. By entering into a joint-venture agreement, the Company expects to enhance shareholder value by shifting a significant portion of the early drilling costs to a minority-interest partner while still allowing the Company to continue operating across most of its acreage. The Company’s position in the Marcellus Shale provides a competitive advantage for a potential joint- venture partner as a majority of the acreage is held in fee, carrying no royalty and no lease expirations, and large,
27
contiguous acreage blocks allow for operating- and cost-efficiency through multi-well pad drilling. The Company will forgo any joint-venture opportunities that do not enhance shareholder value when compared to its current growth plans.
Coincident with the development of its Marcellus Shale acreage, the Company’s Pipeline and Storage segment is building pipeline gathering and transmission facilities to connect Marcellus Shale production with existing pipelines in the region and is pursuing the development of additional pipeline and storage capacity in order to meet anticipated demand for the large amount of Marcellus Shale production expected to come on-line in the months and years to come. Two of the projects, the Tioga County Extension Project and the Northern Access expansion project, are considered significant for Empire and Supply Corporation. Both projects are designed to receive natural gas produced from the Marcellus Shale and transport it to Canada and the Northeast United States to meet growing demand in those areas. During the past year, Empire and Supply Corporation have experienced a decline in the volumes of natural gas received at the Canada/United States border at the Niagara River to be shipped across their systems. The historical price advantage for gas sold at the Niagara import points has declined as production in the Canadian producing regions has declined or been diverted to other demand areas, and as production from new shale plays has increased in the United States. This factor has been causing shippers to seek alternative gas supplies and consequently alternative transportation routes. Empire and Supply Corporation have seen transportation volumes decrease as a result of this situation. The Tioga County Extension Project and the Northern Access expansion project are designed to provide an alternative gas supply source for the customers of Empire and Supply Corporation. These projects, which are discussed more completely in the Investing Cash Flow section that follows, will involve significant capital expenditures.
From a capital resources perspective, the Company has been able to meet its capital expenditure needs for all of the above projects by using cash from operations. The Company had $395.2 million in Cash and Temporary Cash Investments at September 30, 2010, as shown on the Company’s Consolidated Balance Sheet. For fiscal 2011, the Company expects that it will be able to use cash on hand and cash from operations as its first means of financing capital expenditures, with short-term borrowings being its next source of funding. It is not expected that long-term financing will be required to meet capital expenditure needs until the later part of fiscal 2011 or in fiscal 2012.
The possibility of environmental risks associated with a well completion technology referred to as hydraulic fracturing continues to be debated. In Pennsylvania, where the Company is focusing its Marcellus Shale development efforts, the permitting and regulatory processes seem to strike a balance between the environmental concerns associated with hydraulic fracturing and the benefits of increased natural gas production. Hydraulic fracturing is a well stimulation technique that has been used for many years, and in the Company’s experience, one that the Company believes has little impact to the environment. Nonetheless, the potential for increased state or federal regulation of hydraulic fracturing could impact future costs of drilling in the Marcellus Shale and lead to operational delays or restrictions. There is also the risk that drilling could be prohibited on certain acreage that is prospective for the Marcellus Shale. For example, New York State currently has a moratorium in place that prevents hydraulic fracturing of new horizontal wells in the Marcellus Shale. However, due to the small amount of Marcellus Shale acreage owned by the Company in New York State, the moratorium is not expected to have a significant impact on the Company’s plans for Marcellus Shale development. Please refer to the Risk Factors section above for further discussion.
On September 1, 2010, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. Those operations consisted of short distance landfill gas pipeline companies engaged in the purchase, sale and transportation of landfill gas. The Company’s landfill gas operations were maintained under the Company’s wholly-owned subsidiary, Horizon LFG. This sale resulted in a $6.3 million gain, net of tax. The decision to sell was based on progressing the Company’s strategy of divesting its smaller, non-core assets in order to focus on its core businesses, including the development of the Marcellus Shale and the construction of key pipeline infrastructure projects throughout the Appalachian region. As a result of the decision to sell the landfill gas operations, the Company began presenting those operations as discontinued operations in September 2010.
On September 17, 2010, the Company completed the sale of its sawmill in Marienville, Pennsylvania, including approximately 23 million board feet of logs and timber consisting of yard inventory along with
28
unexpired timber cutting contracts and certain land and timber holdings designed to provide the purchaser with a supply of logs for the mill. Despite this sale, the Company has retained substantially all of its land and timber holdings, along with mineral rights on land to be sold. The Company will maintain a forestry operation; however, as part of this change in focus, the Company will no longer be processing lumber products. The Company received proceeds of approximately $15.8 million from the sale. In addition, the purchaser assumed approximately $7.4 million in payment obligations under the Company’s timber cutting contracts with various timber suppliers. In addition to the 23 million board feet mentioned above, the Company expects to sell an additional 17 million board feet of logs to the purchaser over a five-year period, during which time the Company anticipates receiving up to an additional $10 million in proceeds. There was not a material impact to earnings from this sale.
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 aunits-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 theunits-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 SECRegulation S-XRule 4-10. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less
29
estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in oil and gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment 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. At September 30, 2010, the ceiling exceeded the book value of the Company’s oil and gas properties by approximately $269.6 million. The12-month average of the first day of the month price for crude oil for each month during 2010, based on posted Midway Sunset prices, was $69.64 per Bbl. The12-month average of the first day of the month price for natural gas for each month during 2010, based on the quoted Henry Hub spot price for natural gas, was $4.41 per MMBtu. (Note — Because actual pricing of the Company’s various producing properties varies depending on their location and hedging, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Midway Sunset and Henry Hub prices, which are only indicative of12-month average prices for 2010.) If natural gas prices used in the ceiling test calculation at September 30, 2010 had been $1 per MMBtu lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $152.9 million. If crude oil prices used in the ceiling test calculation at September 30, 2010 had been $5 per Bbl lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $221.6 million. If both natural gas and crude oil prices used in the ceiling test calculation at September 30, 2010 were lower by $1 per MMBtu and $5 per Bbl, respectively, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $104.8 million. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation.
It is difficult to predict what factors could lead to future impairments under the SEC’s full cost ceiling test. As discussed above, fluctuations in or subtractions from proved reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time.
In accordance with the current authoritative guidance for asset retirement obligations, the Company records an asset retirement obligation for plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and capitalizes such costs in property, plant and equipment (i.e. the full cost pool). Under the current authoritative guidance for asset retirement obligations, since plugging and abandonment costs are already included in the full cost pool, theunits-of-production depletion calculation excludes from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.
As discussed above, the full cost method of accounting provides a ceiling to the amount of costs that can be capitalized in the full cost pool. In accordance with current authoritative guidance, since the full cost pool includes an amount associated with plugging and abandoning the wells, as discussed in the preceding paragraph, the calculation of the full cost ceiling no longer reduces the future net cash flows from proved oil and gas reserves by an estimate of 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 the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting 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
30
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, and Pipeline and Storage segment, 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 and futures contracts. In accordance with the authoritative guidance for derivative instruments and hedging activities, the Company accounted for these instruments as effective cash flow hedges or fair value hedges. Gains or losses associated with the derivative financial instruments are matched with gains or losses resulting from the underlying physical transaction that is being hedged. To the extent that the derivative financial instruments would ever be deemed to be ineffective based on the effectiveness testing,mark-to-market gains or losses from the derivative financial instruments would be recognized in the income statement without regard to an underlying physical transaction.
The Company uses both exchange-traded and non exchange-traded derivative financial instruments. The Company adopted the authoritative guidance for fair value measurements during the quarter ended December 31, 2008. As such, the fair value of such derivative financial instruments is determined under the provisions of this guidance. The fair value of exchange traded derivative financial instruments is determined from Level 1 inputs, which are quoted prices in active markets. The Company determines the fair value of non exchange-traded derivative financial instruments based on an internal model, which uses both observable and unobservable inputs other than quoted prices. These inputs are considered Level 2 or Level 3 inputs. All derivative financial instrument assets and liabilities are evaluated for the probability of default by either the counterparty or the Company. Credit reserves are applied against the fair values of such assets or liabilities. Refer to the “Market Risk Sensitive Instruments” section below for further discussion of the Company’s derivative financial instruments.
Pension and Other Post-Retirement Benefits. The amounts reported in the Company’s financial statements related to its pension and other post-retirement benefits are determined on an actuarial basis, which uses many assumptions in the calculation of such amounts. These assumptions include the discount rate, the expected return on plan assets, the rate of compensation increase and, for other post-retirement benefits, the expected annual rate of increase in per capita cost of covered medical and prescription benefits. The Company utilizes a yield curve model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year’s anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments. The expected return on plan assets assumption used by the Company reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets. Changes in actuarial assumptions and actuarial experience, including deviations between actual versus expected return on plan assets, could have a material impact on the amount of pension and post-retirement benefit costs and funding requirements experienced by the Company. However, the Company expects to recover 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
31
and Pipeline and Storage segments, as determined under the authoritative guidance for pensions and postretirement benefits, represented 93% of the Company’s total pension and post-retirement benefit costs for the years ended September 30, 2010 and 2009.
Changes in actuarial assumptions and actuarial experience could also have an impact on the benefit obligation and the funded status related to the Company’s pension and other post-retirement benefits and could impact the Company’s equity. For example, the discount rate was changed from 5.50% in 2009 to 4.75% in 2010. The change in the discount rate from 2009 to 2010 increased the Retirement Plan projected benefit obligation by $75.1 million and the accumulated post-retirement benefit obligation by $39.4 million. Other examples include actual versus expected return on plan assets, which has an impact on the funded status of the plans, and actual versus expected benefit payments, which has an impact on the pension plan projected benefit obligation and the accumulated post-retirement benefit obligation. For 2010, the actual return on plan assets exceeded the expected return, which improved the funded status of the Retirement Plan ($3.3 million) as well as the VEBA trusts and 401(h) accounts ($4.1 million). The actual versus expected benefit payments for 2010 caused a decrease of $4.3 million to the accumulated post-retirement benefit obligation. In calculating the projected benefit obligation for the Retirement Plan and the accumulated post-retirement obligation, the actuary takes into account the average remaining service life of active participants. The average remaining service life of active participants is 9 years for the Retirement Plan and 8 years for those eligible for other post-retirement benefits. For further discussion of the Company’s pension and other post-retirement benefits, refer to Other Matters in this Item 7, which includes a discussion of funding for the current year, and to Item 8 at Note H — Retirement Plan and Other Post Retirement Benefits.
RESULTS OF OPERATIONS
EARNINGS
2010 Compared with 2009
The Company’s earnings were $225.9 million in 2010 compared with earnings of $100.7 million in 2009. As previously discussed, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana in September 2010. Accordingly, all financial results for those operations, which are part of the All Other category, have been presented as discontinued operations. The Company’s earnings from continuing operations were $219.1 million in 2010 compared with $103.5 million in 2009. The Company’s earnings from discontinued operations were $6.8 million in 2010 compared to a loss of $2.8 million in 2009. The increase in earnings from continuing operations of $115.6 million is primarily the result of higher earnings in the Exploration and Production segment. The Utility and Energy Marketing segments, as well as the All Other category, also contributed to the increase in earnings. Lower earnings in the Pipeline and Storage segment and a higher loss in the Corporate category slightly offset these increases. The increase in earnings from discontinued operations primarily resulted from the gain on the sale of the Company’s landfill gas operations recognized in 2010 as well as the non-recurrence of $2.8 million of impairment charges recognized in 2009 related to certain landfill 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 the following event in 2010 and several events in 2009, including:
2010 Event
| | |
| • | A $6.3 million gain on the sale of the Company’s landfill gas operations, which was completed in September 2010. This amount is included in earnings from discontinued operations. |
2009 Events
| | |
| • | A non-cash $182.8 million impairment charge ($108.2 million after tax) recorded during the quarter ended December 31, 2008 for the Exploration and Production segment’s oil and gas producing properties; |
32
| | |
| • | A $2.8 million impairment in the value of certain landfill gas assets; |
|
| • | A $1.1 million impairment in the value of the Company’s 50% investment in ESNE (recorded in the All Other category), a limited liability company that owns an 80-megawatt, combined cycle, natural gas-fired power plant in the town of North East, Pennsylvania; and |
|
| • | A $2.3 million death benefit gain on life insurance policies recognized in the Corporate category. |
2009 Compared with 2008
The Company’s earnings were $100.7 million in 2009 compared with earnings of $268.7 million in 2008. The Company’s earnings from continuing operations were $103.5 million in 2009 compared with $266.9 million in 2008. The Company recorded a loss from discontinued operations of $2.8 million in 2009 compared with earnings from discontinued operations of $1.8 million in 2008. Discontinued operations in 2009 and 2008 consisted of the Company’s landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. The decrease in earnings from continuing operations of $163.4 million is primarily the result of lower earnings in the Exploration and Production, Pipeline and Storage and Utility segments and the All Other category, slightly offset by a lower loss in the Corporate category and higher earnings in the Energy Marketing segment, as shown in the table below. The loss from discontinued operations in 2009 compared to earnings from discontinued operations in 2008 reflects the recognition of $2.8 million of impairment charges in 2009 related to certain landfill gas assets. Earnings from continuing operations and discontinued operations were impacted by the 2009 events discussed above and the following 2008 event:
2008 Event
| | |
| • | A $0.6 million gain in the All Other category associated with the sale of Horizon Power’s gas-powered turbine. |
Earnings (Loss) by Segment
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
| Utility | | $ | 62,473 | | | $ | 58,664 | | | $ | 61,472 | |
| Pipeline and Storage | | | 36,703 | | | | 47,358 | | | | 54,148 | |
| Exploration and Production | | | 112,531 | | | | (10,238 | ) | | | 146,612 | |
| Energy Marketing | | | 8,816 | | | | 7,166 | | | | 5,889 | |
| | | | | | | | | | | | | |
| Total Reported Segments | | | 220,523 | | | | 102,950 | | | | 268,121 | |
| All Other | | | 3,396 | | | | 705 | | | | 3,958 | |
| Corporate | | | (4,786 | ) | | | (171 | ) | | | (5,172 | ) |
| | | | | | | | | | | | | |
| Total Earnings from Continuing Operations | | | 219,133 | | | | 103,484 | | | | 266,907 | |
| Earnings (Loss) from Discontinued Operations | | | 6,780 | | | | (2,776 | ) | | | 1,821 | |
| | | | | | | | | | | | | |
| Total Consolidated | | $ | 225,913 | | | $ | 100,708 | | | $ | 268,728 | |
| | | | | | | | | | | | | |
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UTILITY
Revenues
Utility Operating Revenues
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
| Retail Revenues: | | | | | | | | | | | | |
| Residential | | $ | 583,443 | | | $ | 850,088 | | | $ | 876,677 | |
| Commercial | | | 81,110 | | | | 128,520 | | | | 135,361 | |
| Industrial | | | 5,697 | | | | 7,213 | | | | 7,419 | |
| | | | | | | | | | | | | |
| | | | 670,250 | | | | 985,821 | | | | 1,019,457 | |
| | | | | | | | | | | | | |
| Off-System Sales | | | 29,135 | | | | 3,740 | | | | 58,225 | |
| Transportation | | | 109,675 | | | | 111,483 | | | | 113,901 | |
| Other | | | 10,730 | | | | 11,980 | | | | 18,686 | |
| | | | | | | | | | | | | |
| | | $ | 819,790 | | | $ | 1,113,024 | | | $ | 1,210,269 | |
| | | | | | | | | | | | | |
Utility Throughput — million cubic feet (MMcf)
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| |
| Retail Sales: | | | | | | | | | | | | |
| Residential | | | 54,012 | | | | 58,835 | | | | 57,463 | |
| Commercial | | | 8,203 | | | | 9,551 | | | | 9,769 | |
| Industrial | | | 646 | | | | 515 | | | | 552 | |
| | | | | | | | | | | | | |
| | | | 62,861 | | | | 68,901 | | | | 67,784 | |
| | | | | | | | | | | | | |
| Off-System Sales | | | 5,899 | | | | 513 | | | | 5,686 | |
| Transportation | | | 60,105 | | | | 59,751 | | | | 64,267 | |
| | | | | | | | | | | | | |
| | | | 128,865 | | | | 129,165 | | | | 137,737 | |
| | | | | | | | | | | | | |
Degree Days
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Percent (Warmer)
|
| | | | | | | | | Colder Than |
| Year Ended September 30 | | | | Normal | | Actual | | Normal | | Prior Year |
| |
| 2010(1): | | | Buffalo | | | | 6,692 | | | | 6,292 | | | | (6.0 | )% | | | (6.1 | )% |
| | | | Erie | | | | 6,243 | | | | 5,947 | | | | (4.7 | )% | | | (3.7 | )% |
| 2009(2): | | | Buffalo | | | | 6,692 | | | | 6,701 | | | | 0.1 | % | | | 6.8 | % |
| | | | Erie | | | | 6,243 | | | | 6,176 | | | | (1.1 | )% | | | 6.9 | % |
| 2008(3): | | | Buffalo | | | | 6,729 | | | | 6,277 | | | | (6.7 | )% | | | 0.1 | % |
| | | | Erie | | | | 6,277 | | | | 5,779 | | | | (7.9 | )% | | | (3.8 | )% |
| | |
| (1) | | Percents compare actual 2010 degree days to normal degree days and actual 2010 degree days to actual 2009 degree days. |
|
| (2) | | Percents compare actual 2009 degree days to normal degree days and actual 2009 degree days to actual 2008 degree days. |
|
| (3) | | Percents compare actual 2008 degree days to normal degree days and actual 2008 degree days to actual 2007 degree days. |
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2010 Compared with 2009
Operating revenues for the Utility segment decreased $293.2 million in 2010 compared with 2009. This decrease largely resulted from a $315.6 million decrease in retail gas sales revenues, a $1.8 million decrease in transportation revenues, and a $1.2 million decrease in other operating revenues. These were partially offset by a $25.4 million increase in off-system sales revenue.
The decrease in retail gas sales revenues of $315.6 million was largely a function of warmer weather and lower gas costs (subject to certain timing variations, gas costs are recovered dollar for dollar in revenues). The recovery of lower gas costs resulted from a lower cost of purchased gas combined with the refunding of previously over-recovered purchased gas costs. See further discussion of purchased gas below under the heading “Purchased Gas.”
The increase in off-system sales revenues of $25.4 million was largely due to the Utility segment not engaging in off-system sales from November 2008 through October 2009. This was due to Order No. 717 (“Final Rule”), which was issued by the FERC on October 16, 2008. The Final Rule seemingly held that a local distribution company making off-system sales on unaffiliated pipelines would be engaging in “marketing” that would require Distribution Corporation to substantially modify its operations in order to assure compliance with the FERC’s standards of conduct. Accordingly, pending clarification of this issue from the FERC, as of November 1, 2008, Distribution Corporation ceased off-system sales activities. On October 15, 2009, the FERC released OrderNo. 717-A, which clarified that a local distribution company making off-system sales of gas that has been transported on non-affiliated pipelines is not subject to the FERC standards of conduct. In light of and in reliance on this clarification, Distribution Corporation determined that it could resume engaging in off-system sales on non-affiliated pipelines. Such off-system sales resumed in November 2009. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was not a material impact to earnings.
The decrease in transportation revenues of $1.8 million was primarily due to warmer weather and the resulting decrease in transportation volumes for residential and commercial customers. While there was a slight increase in transportation volumes of 0.4 Bcf for all revenue classes, this was largely due to an increase in throughput for large industrial customers. Margins associated with large industrial customers do not have a significant impact on transportation revenues. The decrease in other operating revenues of $1.2 million is largely due to a decrease in late payment revenue, caused by a decrease in gas costs.
2009 Compared with 2008
Operating revenues for the Utility segment decreased $97.2 million in 2009 compared with 2008. This decrease largely resulted from a $54.5 million decrease in off-system sales revenue (see discussion below), a $33.6 million decrease in retail gas sales revenues, a $2.4 million decrease in transportation revenues, and a $6.7 million decrease in other operating revenues.
The decrease in retail gas sales revenues of $33.6 million was largely a function of the recovery of lower gas costs (subject to certain timing variations, gas costs are recovered dollar for dollar in revenues). The recovery of lower gas costs resulted from a much lower cost of purchased gas. See further discussion of purchased gas below under the heading “Purchased Gas.” The decrease in transportation revenues of $2.4 million was primarily due to a 4.5 Bcf decrease in transportation throughput, largely the result of customer conservation efforts and the poor economy.
In the New York jurisdiction, the NYPSC issued an order providing for an annual rate increase of $1.8 million beginning December 28, 2007. As part of this rate order, a rate design change was adopted that shifts a greater amount of cost recovery into the minimum bill amount, thus spreading the recovery of such costs more evenly throughout the year. As a result of this rate order, retail and transportation revenues for 2009 were $2.2 million lower than revenues for 2008.
The Utility segment had off-system sales revenues of $3.7 million and $58.2 million for 2009 and 2008, respectively. 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 2009 and 2008. The decrease in off-system sales revenue stemmed from Order No. 717 (“Final Rule”), as discussed above.
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The decrease in other operating revenues of $6.7 million is largely related to amounts recorded in 2008 pursuant to rate settlements approved by the NYPSC. In accordance with these settlements, Distribution Corporation was allowed 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 2008, Distribution Corporation utilized $5.6 million of the cost mitigation reserve, which increased other operating revenues, to recover previous undercollections of pension expenses. In 2009, Distribution Corporation utilized only $0.2 million of the cost mitigation reserve. The impact of this $5.4 million decrease in other operating revenues was offset by an equal decrease to operation and maintenance expense (thus there was no earnings impact).
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. Distribution Corporation recorded $428.4 million, $713.2 million and $800.5 million of Purchased Gas Expense during 2010, 2009 and 2008, respectively. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs. Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers, a component of Operating Revenues on the consolidated income statement. Under mechanisms approved by the NYPSC in New York and the PaPUC in Pennsylvania, any difference between actual purchased gas costs and what has been collected from the customer is deferred on the consolidated balance sheet as either an asset, Unrecovered Purchased Gas Costs, or a liability, Amounts Payable to Customers. These deferrals are subsequently collected from the customer or passed back to the customer, subject to review by the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution Corporation’s purchased gas costs, such costs do not impact the profitability of the Company. Purchased gas costs impact cash flow from operations due to the timing of recovery of such costs versus the actual purchased gas costs incurred during a particular period. Distribution Corporation’s purchased gas adjustment clauses seek to mitigate this impact by adjusting revenues on either a quarterly or monthly basis.
Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation, Empire 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 two 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 $7.13 per Mcf in 2010, a decrease of 13% from the average cost of $8.17 per Mcf in 2009. The average cost of purchased gas in 2009 was 27% lower than the average cost of $11.23 per Mcf in 2008. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.
Earnings
2010 Compared with 2009
The Utility segment’s earnings in 2010 were $62.5 million, an increase of $3.8 million when compared with earnings of $58.7 million in 2009.
In the New York jurisdiction, earnings increased by $1.8 million. The positive earnings impact associated with lower operating expenses of $1.5 million (primarily a decrease in bad debt expense slightly offset by an increase in personnel costs) and routine regulatory adjustments ($1.4 million) were partially offset by a $1.2 million decrease in late payment revenue (due to lower gas costs) and higher income tax expense of $0.3 million.
The impact of weather on the Utility segment’s New York rate jurisdiction is tempered by a weather normalization clause (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. For 2010, the WNC preserved
36
earnings of approximately $1.3 million, as the weather was warmer than normal. For 2009, the WNC reduced earnings by approximately $0.2 million, as the weather was colder than normal.
In the Pennsylvania jurisdiction, earnings increased by $2.0 million. The positive earnings impact associated with a lower effective tax rate ($5.1 million) and lower operating expenses of $2.8 million were the main factors in the earnings increase. The effective tax rate impact is attributable to a lower state income tax expense in 2010 as a result of the pass-back to customers of over-collected gas costs. The decrease in operating expenses was primarily attributable to a decrease in bad debt expense. These factors were partially offset by lower usage per account ($2.1 million), higher interest expense ($2.1 million), warmer weather ($0.8 million) and routine regulatorytrue-up adjustments ($0.2 million). The phrase “usage per account” refers to average gas consumption per account after factoring out any impact that weather may have had on consumption. The increase in interest expense was partially due to the Company’s April 2009 debt issuance that was issued at a significantly higher interest rate than the debt that had matured in March 2009. In addition, accrued interest on deferred gas costs increased as a result of the over-recovery of gas costs during fiscal 2009.
2009 Compared with 2008
The Utility segment’s earnings in 2009 were $58.7 million, a decrease of $2.8 million when compared with earnings of $61.5 million in 2008.
In the New York jurisdiction, earnings decreased by $3.0 million. This was primarily due to an increase in interest expense ($2.9 million) stemming from the borrowing by the New York jurisdiction of Distribution Corporation of a portion of the Company’s April 2009 debt issuance. The April 2009 debt was issued at a significantly higher interest rate than the interest rates on debt that had matured in March 2009. The negative earnings impact of the December 28, 2007 rate order discussed above ($1.4 million) and routine regulatory adjustments ($0.7 million) also contributed to the decrease. The decrease was partially offset by a $2.6 million overall reduction in operating expenses (mostly other post-retirement benefits and pension expense).
In 2009, the WNC reduced earnings by approximately $0.2 million, as the weather was colder than normal. In 2008, the WNC preserved earnings of approximately $2.5 million, as the weather was warmer than normal.
In the Pennsylvania jurisdiction, earnings increased by $0.2 million. This was primarily due to the positive earnings impact of colder weather ($2.1 million), routine regulatory adjustments ($0.5 million) and lower operating expenses ($0.9 million). A decrease in normalized usage per account ($2.3 million), a higher effective tax rate ($1.4 million) and an increase in interest expense ($0.2 million) partially offset these increases. The phrase “usage per account” refers to the average gas consumption per customer account after factoring out any impact that weather may have had on consumption.
37
PIPELINE AND STORAGE
Revenues
Pipeline and Storage Operating Revenues
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
| Firm Transportation | | $ | 139,324 | | | $ | 139,034 | | | $ | 122,321 | |
| Interruptible Transportation | | | 1,863 | | | | 3,175 | | | | 4,330 | |
| | | | | | | | | | | | | |
| | | | 141,187 | | | | 142,209 | | | | 126,651 | |
| | | | | | | | | | | | | |
| Firm Storage Service | | | 66,593 | | | | 66,711 | | | | 67,020 | |
| Interruptible Storage Service | | | 78 | | | | 20 | | | | 14 | |
| | | | | | | | | | | | | |
| | | | 66,671 | | | | 66,731 | | | | 67,034 | |
| | | | | | | | | | | | | |
| Other | | | 11,025 | | | | 10,333 | | | | 22,871 | |
| | | | | | | | | | | | | |
| | | $ | 218,883 | | | $ | 219,273 | | | $ | 216,556 | |
| | | | | | | | | | | | | |
Pipeline and Storage Throughput — (MMcf)
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| |
| Firm Transportation | | | 296,907 | | | | 348,294 | | | | 353,173 | |
| Interruptible Transportation | | | 4,459 | | | | 3,888 | | | | 5,197 | |
| | | | | | | | | | | | | |
| | | | 301,366 | | | | 352,182 | | | | 358,370 | |
| | | | | | | | | | | | | |
Operating revenues for the Pipeline and Storage segment decreased $0.4 million in 2010 as compared with 2009. The decrease was due to a decrease in interruptible transportation revenues of $1.3 million largely due to a decrease in the gathering rate under Supply Corporation’s tariff. Also contributing to the decrease was a decrease in cashout revenues of $0.3 million (reported as a part of other revenue in the table above). Cashout revenues are completely offset by purchased gas expense and as a result have no impact on earnings. Offsetting the decrease was an increase in efficiency gas revenues of $1.3 million (reported as a part of other revenue in the table above) due to higher efficiency gas volumes and a significantly lower efficiency gas inventory write down in 2010 versus 2009. These increases to efficiency gas revenues were partially offset by lower gas prices and a lower gain, period over period, on the sale of retained efficiency gas volumes held in inventory. Under Supply Corporation’s tariff with shippers, Supply Corporation is allowed to retain a set percentage of shipper-supplied gas to cover compressor fuel costs and for other operational purposes. To the extent that Supply Corporation does not need all of the gas to cover such operational needs, it is allowed to keep the excess gas as inventory. That inventory is later sold to buyers on the open market. The excess gas that is retained as inventory, as well as any gains resulting from the sale of such inventory, represent efficiency gas revenue to Supply Corporation. Also offsetting the decrease in revenues was an increase in firm transportation revenues of $0.3 million. This increase was primarily the result of higher revenues from the Empire Connector, which was placed in service in December 2008, partially offset by a reduction in the level of short-term contracts entered into by shippers period over period as such shippers utilized lower priced pipeline transportation routes.
Transportation volume decreased by 50.8 Bcf in 2010 as compared with 2009. These decreases were largely due to shippers seeking alternative lower priced gas supply (and in some cases, not renewing short-term transportation contracts) combined with warmer weather and lower industrial demand. The reason shippers are seeking lower priced gas supply is primarily because of the relatively higher price of natural gas supplies available at the United States/Canadian border at the Niagara River near Buffalo, New York compared to the lower pricing for supplies available at Leidy, Pennsylvania. Empire’s proposed Tioga County Extension Project and Supply Corporation’s “Northern Access” expansion project, both of which are discussed in the Investing Cash Flow
38
section that follows, are designed to utilize that available pipeline capacity by receiving natural gas produced from the Marcellus Shale and transporting it to Canada and the Northeast United States where demand has been growing. Much of the impact of lower volumes is offset by the straight fixed-variable rate design utilized by Supply Corporation and Empire. However, this rate design does not protect Supply Corporation or Empire in situations where shippers do not contract for that capacity at the same quantity and rate. In that situation, Supply Corporation or Empire can propose revised rates and services in a rate case at the FERC.
2009 Compared with 2008
Operating revenues for the Pipeline and Storage segment increased $2.7 million in 2009 as compared with 2008. The increase was primarily due to a $15.6 million increase in transportation revenue primarily due to higher revenues from the Empire Connector and new contracts for transportation service. Partially offsetting this increase, efficiency gas revenues decreased $11.5 million. The majority of this decrease was due to significantly lower gas prices in 2009 as compared to 2008.
Earnings
2010 Compared with 2009
The Pipeline and Storage segment’s earnings in 2010 were $36.7 million, a decrease of $10.7 million when compared with earnings of $47.4 million in 2009. The decrease in earnings is primarily due to a decrease in the allowance for funds used during construction ($2.3 million), higher operating costs ($4.5 million), higher property taxes ($2.0 million), higher interest expense ($3.1 million) and higher depreciation expense ($0.5 million). Lower transportation revenues of $0.7 million, as discussed above, also contributed to the earnings decrease. The decrease in allowance for funds used during construction (equity component) is a result of the construction of the Empire Connector, which was completed and placed in service on December 10, 2008. The increase in operating expenses can primarily be attributed to higher pension expense, higher personnel costs, and an increase in corrosion logging expenses associated with Supply Corporation’s storage wells. The increase in property taxes is primarily a result of additional property taxes and higher payments in lieu of taxes associated with the Empire Connector. The increase in interest expense can be attributed to higher debt balances and a higher average interest rate on borrowings combined with a decrease in the allowance for borrowed funds used during construction resulting from the completion of the Empire Connector. The increase in the average interest rate stems from the Company’s April 2009 debt issuance. The increase in depreciation expense is primarily the result of the Empire Connector being placed in service in December 2008. These earnings decreases were partially offset by the earnings impact associated with higher efficiency gas revenues ($0.8 million), as discussed above, and lower income tax expense ($1.4 million) due to a lower effective tax rate.
2009 Compared with 2008
The Pipeline and Storage segment’s earnings in 2009 were $47.4 million, a decrease of $6.7 million when compared with earnings of $54.1 million in 2008. The decrease was primarily due to the earnings impact associated with a decrease in efficiency gas revenues ($7.5 million), as discussed above. In addition, higher interest expense ($5.1 million), higher depreciation expense ($1.5 million), and a decrease in the allowance for funds used during construction ($2.0 million) also contributed to the decrease in earnings. The increase in interest expense can be attributed to higher debt balances and a higher average interest rate on borrowings. The increase in the average interest rate stems from the Company’s April 2009 debt issuance. The increase in depreciation expense can be attributed primarily to a revision of accumulated depreciation combined with the increased depreciation associated with placing the Empire Connector in service in December 2008. The decrease in the allowance for funds used during construction was due to completion of the Empire Connector project in December 2008. Whereas the allowance for funds used during construction related to the Empire Connector project was recorded throughout 2008, it was only recorded for three months in 2009. These earnings decreases were partially offset by the earnings impact associated with higher transportation revenues ($9.7 million), as discussed above.
39
EXPLORATION AND PRODUCTION
Revenues
Exploration and Production Operating Revenues
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
| Gas (after Hedging) | | $ | 183,327 | | | $ | 154,582 | | | $ | 202,153 | |
| Oil (after Hedging) | | | 242,303 | | | | 219,046 | | | | 250,965 | |
| Gas Processing Plant | | | 29,369 | | | | 24,686 | | | | 49,090 | |
| Other | | | 820 | | | | 432 | | | | (944 | ) |
| Intrasegment Elimination(1) | | | (17,791 | ) | | | (15,988 | ) | | | (34,504 | ) |
| | | | | | | | | | | | | |
| Operating Revenues | | $ | 438,028 | | | $ | 382,758 | | | $ | 466,760 | |
| | | | | | | | | | | | | |
| | |
| (1) | | Represents the elimination of certain West Coast gas production revenue included in “Gas (after Hedging)” in the table above that is sold to the gas processing plant shown in the table above. An elimination for the same dollar amount was made to reduce the gas processing plant’s Purchased Gas expense. |
Production
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| |
Gas Production(MMcf) | | | | | | | | | | | | |
| Gulf Coast | | | 10,304 | | | | 9,886 | | | | 11,033 | |
| West Coast | | | 3,819 | | | | 4,063 | | | | 4,039 | |
| Appalachia | | | 16,222 | | | | 8,335 | | | | 7,269 | |
| | | | | | | | | | | | | |
| Total Production | | | 30,345 | | | | 22,284 | | | | 22,341 | |
| | | | | | | | | | | | | |
Oil Production(Mbbl) | | | | | | | | | | | | |
| Gulf Coast | | | 502 | | | | 640 | | | | 505 | |
| West Coast | | | 2,669 | | | | 2,674 | | | | 2,460 | |
| Appalachia | | | 49 | | | | 59 | | | | 105 | |
| | | | | | | | | | | | | |
| Total Production | | | 3,220 | | | | 3,373 | | | | 3,070 | |
| | | | | | | | | | | | | |
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Average Prices
| | | | | | | | | | | | | |
| | | Year Ended September 30 |
| | | 2010 | | 2009 | | 2008 |
| |
Average Gas Price/Mcf | | | | | | | | | | | | |
| Gulf Coast | | $ | 5.22 | | | $ | 4.54 | | | $ | 10.03 | |
| West Coast | | $ | 4.81 | | | $ | 3.91 | | | $ | 8.71 | |
| Appalachia | | $ | 4.93 | | | $ | 5.52 | | | $ | 9.73 | |
| Weighted Average | | $ | 5.01 | | | $ | 4.79 | | | $ | 9.70 | |
| Weighted Average After Hedging(1) | | $ | 6.04 | | | $ | 6.94 | | | $ | 9.05 | |
Average Oil Price/Barrel (bbl) | | | | | | | | | | | | |
| Gulf Coast | | $ | 76.57 | | | $ | 54.58 | | | $ | 107.27 | |
| West Coast(2) | | $ | 71.72 | | | $ | 50.90 | | | $ | 98.17 | |
| Appalachia | | $ | 75.81 | | | $ | 56.15 | | | $ | 97.40 | |
| Weighted Average | | $ | 72.54 | | | $ | 51.69 | | | $ | 99.64 | |
| Weighted Average After Hedging(1) | | $ | 75.25 | | | $ | 64.94 | | | $ | 81.75 | |
| | |
| (1) | | Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note G — Financial Instruments in Item 8 of this report. |
|
| (2) | | Includes low gravity oil which generally sells for a lower price. |
2010 Compared with 2009
Operating revenues for the Exploration and Production segment increased $55.3 million in 2010 as compared with 2009. Gas production revenue after hedging increased $28.7 million primarily due to production increases in the Appalachian division. The increase in Appalachian natural gas production was mainly due to Marcellus Shale production that came on line during fiscal 2010, primarily in Tioga County, Pennsylvania. Increases in natural gas production were partially offset by a $0.90 per Mcf decrease in the weighted average price of gas after hedging. Oil production revenue after hedging increased $23.3 million due to an increase in the weighted average price of oil after hedging ($10.31 per Bbl), while oil production levels were slightly lower in fiscal 2010. In addition, there was a $2.9 million increase in gross processing plant revenues (net of eliminations) due to an increase in the commodity prices of residual gas and liquids sold at Seneca’s processing plants in the West Coast region.
Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.
2009 Compared with 2008
Operating revenues for the Exploration and Production segment decreased $84.0 million in 2009 as compared with 2008. Gas production revenue after hedging decreased $47.6 million primarily due to a $2.11 per Mcf decrease in weighted average prices after hedging. Gas production was virtually flat with the prior year as production decreases in the Gulf Coast region were substantially offset by production increases in the Appalachian region. The decrease in gas production that occurred in the Gulf Coast region (1,147 MMcf) was a result of lingering shut-ins caused by Hurricanes Edouard, Gustav and Ike in September 2008. While Seneca’s properties sustained only superficial damage from the hurricanes, two significant producing properties were shut-in for a significant portion of the current fiscal year due to repair work on third party pipelines and onshore processing facilities. One of the properties was back on line by March 31, 2009 and the other property was back on line by the end of April 2009. The increase in gas production in the Appalachian region of 1,066 MMcf resulted from additional wells drilled throughout fiscal 2008 that came on line in 2009. Oil production revenue after hedging decreased $31.9 million due to a $16.81 per barrel decrease in weighted average prices after hedging, which more than offset an increase in oil production of 303,000 barrels (primarily from the West Coast and Gulf Coast regions). In addition, there was a $5.9 million decrease in gross processing plant revenues (net of
41
eliminations) due to a reduction in the commodity prices of residual gas and liquids sold at Seneca’s processing plants in the West Coast and Appalachian regions.
Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.
Earnings
2010 Compared with 2009
The Exploration and Production segment’s earnings for 2010 were $112.5 million, compared with a loss of $10.2 million for 2009, an increase of $122.7 million. The increase in earnings is primarily the result of the non-recurrence of an impairment charge of $108.2 million during the quarter ended December 31, 2008, as discussed above in the Overview section. Higher natural gas production and higher crude oil prices increased earnings by $36.3 million and $21.6 million, respectively. Higher processing plant revenues ($1.9 million) largely due to an increase in commodity prices of residual gas and liquids sold at Seneca’s processing plants in the West Coast region further contributed to an increase in earnings. Lower interest expense ($1.6 million) due to a lower average amount of debt outstanding and the capitalization of interest further contributed to an increase in earnings. In addition, lower general and administrative and other operating expenses ($1.2 million) increased earnings. The decrease in general and administrative and other operating expenses primarily reflects variations between actual plugging and abandonment costs incurred versus amounts previously accrued for such properties. During 2010, actual plugging and abandonment costs incurred were less than the liability that had been established for such properties, resulting in a gain. The decrease in general and administrative and other operating expenses also reflects a decrease in bad debt expense. Higher personnel costs, primarily in the Appalachian region, partially offset these decreases. Lower natural gas prices ($17.7 million) and lower crude oil production ($6.5 million) partially offset the increase in earnings. In addition, the earnings increases noted above were partially offset by higher depletion expense ($10.0 million), the earnings impact associated with higher income tax expense ($7.2 million), higher lease operating expenses ($6.1 million), and lower interest income ($0.9 million). The increase in depletion expense was primarily due to an increase in production and depletable base (largely due to increased capital spending in the Appalachian region). The increase in income tax expense in 2010 is attributable to the loss of a domestic production activities deduction for fiscal 2010, the non-recurrence of a Corporate tax benefit received in the prior year, and higher state income taxes. Lease operating expenses increased due to higher steaming costs in California, additional production properties related to the acquisition of Ivanhoe Energy’s United States oil and gas properties in July 2009, an increase in the costs associated with a higher number of producing properties in the Appalachian region, primarily within the Marcellus Shale, and higher production taxes. The reduction in interest income was largely due to lower interest rates on cash investment balances.
2009 Compared with 2008
The Exploration and Production segment’s loss for 2009 was $10.2 million, compared with earnings of $146.6 million for 2008, a decrease of $156.8 million. The decrease in earnings is primarily the result of an impairment charge of $108.2 million, as discussed above. In addition, lower crude oil prices, lower natural gas prices, and lower natural gas production decreased earnings by $36.9 million, $30.6 million, and $0.3 million, respectively, while higher crude oil production increased earnings by $16.1 million. Lower interest income ($5.5 million) and higher operating expenses ($1.7 million) further reduced earnings. In addition, there was a $3.8 million decrease in earnings caused by a reduction in the commodity prices of residual gas and liquids sold at Seneca’s processing plants in the West Coast and Appalachian regions. The decrease in interest income is due to lower interest rates and lower temporary cash investment balances. The increase in operating expenses is due to an increase in bad debt expense as a result of a customer’s bankruptcy filing, and higher personnel costs in the Appalachian region. These earnings decreases were partially offset by lower interest expense ($5.4 million), lower lease operating costs ($2.6 million), lower depletion expense ($0.9 million), and lower income tax expense ($4.2 million). The decline in interest expense is primarily due to a lower average amount of debt outstanding. The reduction in lease operating expenses is primarily due to a reduction in steam fuel costs in the West Coast region and lower production taxes in the Gulf Coast region. The decrease in depletion is primarily
42
due to a lower full cost pool balance after the impairment charge taken during the quarter ended December 31, 2008.
ENERGY MARKETING
Revenues
Energy Marketing Operating Revenues
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
| Natural Gas (after Hedging) | | $ | 344,077 | | | $ | 398,205 | | | $ | 551,243 | |
| Other | | | 725 | | | | 116 | | | | (11 | ) |
| | | | | | | | | | | | | |
| | | $ | 344,802 | | | $ | 398,321 | | | $ | 551,232 | |
| | | | | | | | | | | | | |
Energy Marketing Volume
| | | | | | | | | | | | | |
| | | Year Ended September 30 |
| | | 2010 | | 2009 | | 2008 |
| |
| Natural Gas — (MMcf) | | | 58,299 | | | | 60,858 | | | | 56,120 | |
2010 Compared with 2009
Operating revenues for the Energy Marketing segment decreased $53.5 million in 2010 as compared with 2009. The decrease primarily reflects a decline in gas sales revenue due to a lower average price of natural gas that was recovered through revenues, as well as a decrease in volume sold. The decrease in volume is largely attributable to a decrease in volume sold to low-margin wholesale customers as well as fewer sales transactions undertaken at the Niagara pipeline delivery point to offset certain basis risks that the Energy Marketing segment was exposed to under certain fixed basis commodity purchase contracts for Appalachian production. Such transactions had the effect of increasing revenue and volume sold with minimal impact to earnings.
2009 Compared with 2008
Operating revenues for the Energy Marketing segment decreased $152.9 million in 2009 as compared with 2008. The decrease is primarily due to lower gas sales revenue, due to a lower average price of natural gas that was recovered through revenues. This decline was somewhat offset by an increase in volume sold. The increase in sales volume is largely attributable to colder weather as well as an increase in sales transactions undertaken at the Niagara pipeline delivery point to offset certain basis risks that the Energy Marketing segment was exposed to under certain fixed basis commodity purchase contracts for Appalachian production. Such transactions had the effect of increasing revenue and volume sold with minimal impact to earnings.
Earnings
2010 Compared with 2009
The Energy Marketing segment’s earnings in 2010 were $8.8 million, an increase of $1.6 million when compared with earnings of $7.2 million in 2009. This increase was primarily attributable to higher margin of $1.4 million combined with lower income tax expense of $0.4 million. The increase in margin was primarily driven by improved average margins per Mcf, the benefit that the Energy Marketing segment derived from its contracts for storage capacity, and proceeds received as a member of a class of claimants in a class action litigation settlement. Higher operating costs of $0.1 million slightly offset the increase in earnings. The increase in operating expenses was primarily due to a June 2010 accrual for U.S. Customs merchandise processing fees that may be due for certain past gas imports from Canada, largely offset by lower bad debt expense.
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2009 Compared with 2008
The Energy Marketing segment’s earnings in 2009 were $7.2 million, an increase of $1.3 million when compared with earnings of $5.9 million in 2008. Higher margin of $1.5 million combined with lower operating costs of $0.4 million (primarily due to a decline in bad debt expense) are responsible for the increase in earnings. These increases were partially offset by higher income tax expense of $0.4 million in 2009 as compared to 2008. The increase in margin was primarily driven by lower pipeline transportation fuel costs due to lower natural gas commodity prices, an unfavorable pipeline imbalance resolution in fiscal 2008 that did not recur in fiscal 2009, and improved average margins per Mcf, partially offset by higher pipeline reservation charges related to additional storage capacity.
ALL OTHER AND CORPORATE OPERATIONS
All Other and Corporate operations primarily includes the operations of Highland, Seneca’s Northeast Division, Midstream Corporation, Horizon Power, former International segment activity and corporate operations. Highland and Seneca’s Northeast Division market timber from their New York and Pennsylvania land holdings. In September 2010, the Company sold its sawmill in Marienville, Pennsylvania along with the mill’s inventory, stumpage tracts and certain land and timber acreage for approximately $15.8 million. The Company recognized a gain of approximately $0.4 million from this sale ($0.2 million net of tax). The Company continues to maintain a forestry operation, but will no longer be processing lumber products. Midstream Corporation is a Pennsylvania corporation formed to build, own and operate natural gas processing and pipeline gathering facilities in the Appalachian region. Horizon Power’s activity primarily consists of equity method investments in Seneca Energy, Model City and ESNE. Horizon Power has a 50% ownership interest in each of these entities. The income from these equity method investments is reported as Income from Unconsolidated Subsidiaries on the Consolidated Statements of Income. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. On November 1, 2010, ESNE stopped all electricity generation operations. The turbines and other assets will be sold and the building will be dismantled. ESNE generated electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania. In September 2010, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana for $38.0 million, recognizing a gain of $10.3 million ($6.3 million net of tax). The Company’s landfill gas operations were maintained under the Company’s wholly owned subsidiary, Horizon LFG, which owned and operated these short distance landfill gas pipeline companies. These operations are presented in the Company’s financial statements as discontinued operations. Refer to Item 8 at Note J — Discontinued Operations for further details.
Earnings
2010 Compared with 2009
All Other and Corporate operations had a loss from continuing operations of $1.4 million in 2010 compared with earnings from continuing operations of $0.5 million in 2009. The overall decrease was due to higher interest expense of $3.8 million (primarily the result of higher borrowings at a higher interest rate due to the $250 million of 8.75% notes issued in April 2009), higher income tax expense of $3.7 million (due to a higher effective tax rate), higher depreciation and depletion of $2.4 million (mostly attributable to increased depletion expense due to an increase in timber harvested from Company owned lands), and higher operating expenses of $1.0 million (mostly attributable to an increase in Midstream Corporation’s operating activities). In addition, the non-recurrence of a gain resulting from a death benefit on corporate-owned life insurance policies held by the Company of $2.3 million that occurred during the quarter ended December 31, 2008 further reduced earnings. The negative earnings impact associated with items mentioned above were partially offset by higher margins of $6.5 million and higher interest income of $3.1 million. The increase in margins was mostly attributable to higher margins from log and lumber sales (partially due to the increase in timber harvested from low cost basis, Company owned lands) coupled with higher revenues from Midstream Corporation’s gathering operations. The increase in interest income was due to higher intercompany interest collected from the Company’s other operating segments as a result of the allocation of the aforementioned April 2009 debt issuance. In addition, during the quarter ended December 31, 2008, ESNE, an unconsolidated subsidiary of
44
Horizon Power, recorded an impairment charge of $3.6 million, which did not recur. Horizon Power’s 50% share of the impairment was $1.8 million ($1.1 million on an after tax basis).
2009 Compared with 2008
All Other and Corporate operations had earnings from continuing operations of $0.5 million in 2009, an increase of $1.7 million compared with a loss from continuing operations of $1.2 million for 2008. The increase was due to lower operating costs ($3.8 million), lower income tax expenses ($4.6 million), lower depreciation and depletion ($0.4 million) and higher other income ($0.7 million). In 2008, the proxy contest with New Mountain Vantage GP, L.L.C. led to an increase in operating costs, which did not recur in 2009. In addition, a gain on life insurance policies held by the Company ($2.3 million) further increased earnings. The reduction in depreciation and depletion expense is due to a decrease in timber harvested from Company owned lands. The increase in other income is primarily due to an increase in the value of corporate owned life insurance policies. These earnings increases were partially offset by higher interest expense ($3.4 million), lower income from Horizon Power’s investments in unconsolidated subsidiaries ($2.0 million), lower margins from lumber, log, and timber rights sales ($2.5 million) and lower interest income ($0.6 million). The decrease in margins from lumber, log and timber rights sales is a result of a decline in revenues due to unfavorable market conditions. The increase in interest expense was primarily the result of higher borrowings at a higher interest rate (mostly due to the $250 million of 8.75% notes that were issued in April 2009). The decrease in interest income is largely due to lower rates on cash investment balances. In addition, during 2009, ESNE, an unconsolidated subsidiary of Horizon Power, recorded an impairment charge of $3.6 million. Horizon Power’s 50% share of the impairment was $1.8 million ($1.1 million on an after tax basis). The impairment charge of $3.6 million recorded by ESNE during 2009 (as discussed above) was driven by a significant decrease in “run time” for the plant given the economic downturn and the resulting decrease in demand for electric power. Also, Horizon Power recognized a gain on the sale of a turbine ($0.6 million) during 2008 that did not recur in 2009.
INTEREST INCOME
Interest income was $2.0 million lower in 2010 as compared to 2009. Lower interest rates on cash investment balances was the primary factor contributing to this decrease.
Interest income was $5.0 million lower in 2009 as compared to 2008. Lower cash investment balances in the Exploration and Production segment and lower interest rates on such investments were the primary factors contributing to this decrease.
OTHER INCOME
Other income was $4.6 million lower in 2010 as compared to 2009. This decrease is attributable to a $2.1 million decrease in the allowance for funds used during construction, which is primarily due to the completion of the Empire Connector project in December 2008. In addition, a death benefit gain on corporate-owned life insurance policies of $2.3 million recognized during the first quarter of 2009 did not recur in 2010.
Other income was $1.0 million higher in 2009 as compared to 2008. This increase was primarily due to a death benefit gain on corporate-owned life insurance policies of $2.3 million recognized during the first quarter of 2009. In addition, there was a largeryear-over-year increase in the value of corporate-owned life insurance policies ($1.8 million). This increase is partially offset by a $2.2 million decrease in the allowance for funds used during construction, which is primarily due to the completion of the Empire Connector project in December 2008. In addition, Horizon Power recognized a $0.9 million pre-tax gain on the sale of a turbine during 2008 that did not recur in 2009.
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INTEREST CHARGES
Although most of the variances in Interest Charges are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis:
Interest on long-term debt increased $7.8 million in 2010 as compared to 2009. The increase in 2010 was primarily the result of a higher average amount of long-term debt outstanding combined with higher average interest rates. In April 2009, the Company issued $250 million of 8.75% senior, unsecured notes due in May 2019. This increase was partially offset by the repayment of $100 million of 6% medium-term notes that matured in March 2009. In addition, during fiscal 2009, the Exploration and Production segment significantly increased its capital expenditures related to unproved properties in the Marcellus Shale area of the Appalachian region. As a result, the Company capitalized interest costs associated with capital expenditures, which decreased interest expense by $1.1 million.
Interest on long-term debt increased $9.3 million in 2009 as compared to 2008. The increase in 2009 was primarily the result of a higher average amount of long-term debt outstanding combined with higher average interest rates due to the April 2009 debt issuance discussed above. This increase was partially offset by the repayment of $100 million of 6% medium-term notes that matured in March 2009.
Other interest charges decreased $0.6 million in 2010 compared to 2009. The decrease is mainly attributable to a $1.4 million decrease in interest expense on regulatory deferrals (primarily deferred gas costs) in the Utility segment, which was partially offset by a $0.9 million decrease in the allowance for borrowed funds used during construction resulting from the completion of the Empire Connector in December 2009.
Other interest charges increased $4.1 million in 2009 compared to 2008. The increase in 2009 was primarily caused by a $2.3 million increase in interest expense on regulatory deferrals (primarily deferred gas costs) in the Utility segment’s New York jurisdiction combined with a $0.7 million decrease in the allowance for borrowed funds used during construction related to the Empire Connector project. In addition, there was an increase due to an audit adjustment on a state tax return from 2008 ($0.4 million).
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CAPITAL RESOURCES AND LIQUIDITY
The primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows:
Sources (Uses) of Cash
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Millions) | |
| |
| Provided by Operating Activities | | $ | 459.7 | | | $ | 611.8 | | | $ | 482.8 | |
| Capital Expenditures | | | (455.8 | ) | | | (313.6 | ) | | | (397.7 | ) |
| Investment in Subsidiary, Net of Cash Acquired | | | — | | | | (34.9 | ) | | | — | |
| Net Proceeds from Sale of Timber Mill and Related Assets | | | 15.8 | | | | — | | | | — | |
| Net Proceeds from Sale of Landfill Gas Pipeline Assets | | | 38.0 | | | | — | | | | — | |
| Cash Held in Escrow | | | — | | | | (2.0 | ) | | | 58.4 | |
| Net Proceeds from Sale of Oil and Gas Producing Properties | | | — | | | | 3.6 | | | | 5.9 | |
| Other Investing Activities | | | (0.3 | ) | | | (2.8 | ) | | | 4.4 | |
| Reduction of Long-Term Debt | | | — | | | | (100.0 | ) | | | (200.0 | ) |
| Net Proceeds from Issuance of Long-Term Debt | | | — | | | | 247.8 | | | | 296.6 | |
| Net Proceeds from Issuance of Common Stock | | | 26.0 | | | | 28.2 | | | | 17.4 | |
| Dividends Paid on Common Stock | | | (109.5 | ) | | | (104.2 | ) | | | (103.7 | ) |
| Excess Tax Benefits Associated with Stock- Based Compensation Awards | | | 13.2 | | | | 5.9 | | | | 16.3 | |
| Shares Repurchased under Repurchase Plan | | | — | | | | — | | | | (237.0 | ) |
| | | | | | | | | | | | | |
| Net Increase (Decrease) in Cash and Temporary Cash Investments | | $ | (12.9 | ) | | $ | 339.8 | | | $ | (56.6 | ) |
| | | | | | | | | | | | | |
OPERATING CASH FLOW
Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, impairment of investment in partnership, deferred income taxes, income or loss from unconsolidated subsidiaries net of cash distributions and gain on sale of discontinued operations.
Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.
Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil. The Company uses various derivative financial instruments, including price swap agreements and futures contracts in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $459.7 million in 2010, a decrease of $152.1 million compared with the $611.8 million provided by operating activities in 2009. The decrease is primarily due to the timing of gas cost recovery in the Utility segment. As gas prices decreased significantly during 2009, the Company’s Utility segment experienced an over-recovery of gas costs that was reflected in Amounts Payable to Customers on the Company’s Consolidated Balance Sheet. Since September 30, 2009, the Company has been
47
refunding that over-recovery to its customers. From a consolidated perspective, higher interest payments on long-term debt also contributed to the decrease in cash provided by operating activities.
Net cash provided by operating activities totaled $611.8 million in 2009, an increase of $129.0 million compared with the $482.8 million provided by operating activities in 2008. The increase is primarily due to the timing of gas cost recovery in the Utility segment. As gas prices decreased significantly during 2009, the Company’s Utility segment experienced an over-recovery of gas costs that is reflected in Amounts Payable to Customers on the Company’s Consolidated Balance Sheet at September 30, 2009. At September 30, 2008, the Company’s Utility segment was in an under-recovery position.
INVESTING CASH FLOW
Expenditures for Long-Lived Assets
The Company’s expenditures from continuing operations for long-lived assets totaled $501.4 million, $341.4 million and $414.4 million in 2010, 2009 and 2008, respectively. The table below presents these expenditures:
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Millions) | |
| |
| Utility: | | | | | | | | | | | | |
| Capital Expenditures | | $ | 58.0 | | | $ | 56.2 | | | $ | 57.5 | |
| Pipeline and Storage: | | | | | | | | | | | | |
| Capital Expenditures | | | 37.9 | | | | 52.5 | (3) | | | 165.5 | (3) |
| Exploration and Production: | | | | | | | | | | | | |
| Capital Expenditures | | | 398.2 | (1)(2) | | | 188.3 | (2) | | | 192.2 | |
| Investment in Subsidiary | | | — | | | | 34.9 | (4) | | | — | |
| All Other and Corporate: | | | | | | | | | | | | |
| Capital Expenditures | | | 7.3 | (2) | | | 9.8 | (2) | | | 1.6 | |
| Eliminations | | | — | | | | (0.3 | )(5) | | | (2.4 | )(6) |
| | | | | | | | | | | | | |
| Total Expenditures from Continuing Operations | | $ | 501.4 | (7) | | $ | 341.4 | (7) | | $ | 414.4 | (7) |
| | | | | | | | | | | | | |
| | |
| (1) | | Amount for 2010 includes $55.5 million of accrued capital expenditures, the majority of which was in the Appalachian region. This amount has been excluded from the Consolidated Statement of Cash Flows at September 30, 2010 since it represents a non-cash investing activity at that date. |
|
| (2) | | Capital expenditures for the Exploration and Production segment for 2010 exclude $9.1 million of accrued capital expenditures, the majority of which was in the Appalachian region. Capital expenditures for All Other for 2010 exclude $0.7 million of accrued capital expenditures related to the construction of the Midstream Covington Gathering System. Both of these amounts were accrued at September 30, 2009 and paid during the year ended September 30, 2010. These amounts were included in the 2009 capital expenditures shown in the table above, but were excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represented non-cash investing activities at that date. These amounts have been included in the Consolidated Statement of Cash Flows at September 30, 2010. |
|
| (3) | | Amount for 2009 excludes $16.8 million of accrued capital expenditures related to the Empire Connector project accrued at September 30, 2008 and paid during the year ended September 30, 2009. This amount was included in 2008 capital expenditures shown in the table above, but was excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represented a non-cash investing activity at that date. The amount was included in the Consolidated Statement of Cash Flows at September 30, 2009. |
|
| (4) | | Investment amount is net of $4.3 million of cash acquired. |
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| | |
| (5) | | Represents $0.3 million of capital expenditures in the Pipeline and Storage segment for the purchase of pipeline facilities from the Appalachian region of the Exploration and Production segment during the quarter ended December 31, 2008. |
|
| (6) | | Represents $2.4 million of capital expenditures included in the Appalachian region of the Exploration and Production segment for the purchase of storage facilities, buildings, and base gas from Supply Corporation during the quarter ended March 31, 2008. |
|
| (7) | | Excludes expenditures for long-lived assets associated with discontinued operations as follows: $0.1 million for 2010, $0.2 million for 2009, and $0.1 million for 2008. |
Utility
The majority of the Utility capital expenditures for 2010, 2009 and 2008 were made for replacement of mains and main extensions, as well as for the replacement of service lines.
Pipeline and Storage
The majority of the Pipeline and Storage segment’s capital expenditures for 2010 were made for additions, improvements, and replacements to this segment’s transmission and gas storage systems. The Pipeline and Storage capital expenditure amounts for 2010 also include $6.0 million spent on the Lamont Project, discussed below. The majority of the Pipeline and Storage segment’s capital expenditures for 2009 and 2008 were related to the Empire Connector project, which was placed into service on December 10, 2008, as well as for additions, improvements, and replacements to this segment’s transmission and gas storage systems. The Empire Connector project was completed for a cost of approximately $192 million. The Company capitalized Empire Connector project costs of $27.3 million and $149.2 million for the years ended September 30, 2009 and 2008, respectively.
Exploration and Production
In 2010, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $14.9 million for the Gulf Coast region, the majority of which was for the off-shore program in the shallow waters of the Gulf of Mexico, $27.6 million for the West Coast region and $355.7 million for the Appalachian region (including $332.4 million in the Marcellus Shale area). These amounts included approximately $28.9 million spent to develop proved undeveloped reserves. The capital expenditures in the Appalachian region include the Company’s acquisition of two tracts of leasehold acreage for approximately $71.8 million. The Company acquired these tracts in order to expand its Marcellus Shale acreage holdings. These tracts, consisting of approximately 18,000 net acres in Tioga and Potter Counties in Pennsylvania, are geographically similar to the Company’s existing Marcellus Shale acreage in the area, and will help the Company continue its developmental drilling program. The transaction closed on March 12, 2010. The Company funded this transaction with cash from operations.
In 2009, the Exploration and Production segment’s capital expenditures were primarily well drilling and completion expenditures and included approximately $18.3 million for the Gulf Coast region, substantially all of which was for the off-shore program in the shallow waters of the Gulf of Mexico, $31.4 million for the West Coast region and $138.6 million for the Appalachian region. These amounts included approximately $24.2 million spent to develop proved undeveloped reserves.
In July 2009, the Company’s wholly-owned subsidiary in the Exploration and Production segment, Seneca, purchased Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million in cash (including cash acquired of $4.3 million). The cash acquired at acquisition includes $2.0 million held in escrow at September 30, 2010 and 2009. Seneca placed this amount in escrow as part of the purchase price. Currently, the Company and Ivanhoe Energy are negotiating a final resolution to the issue of whether Ivanhoe Energy is entitled to some or all of the amount held in escrow. This purchase complements the segment’s existing oil producing assets in the Midway Sunset Field in California. This acquisition was funded with cash on hand.
In 2008, the Exploration and Production segment’s capital expenditures were primarily well drilling and completion expenditures and included approximately $63.6 million for the Gulf Coast region, substantially all
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of which was for the off-shore program in the shallow waters of the Gulf of Mexico, $62.8 million for the West Coast region and $65.8 million for the Appalachian region. These amounts included approximately $25.4 million spent to develop proved undeveloped reserves. The Appalachian region capital expenditures include $2.4 million for the purchase of storage facilities, buildings, and base gas from Supply Corporation, as shown in the table above.
All Other and Corporate
In 2010 and 2009, the majority of the All Other category’s capital expenditures for long-lived assets were for the construction of Midstream Corporation’s Covington Gathering System, as discussed below.
NFG Midstream Covington, LLC, a wholly owned subsidiary of Midstream Corporation, constructed a gathering system in Tioga County, Pennsylvania. The project, called the Covington Gathering System, was constructed in two phases. The first phase was completed and placed in service in November 2009. The second phase was placed in service in May 2010. The system consists of approximately 10 miles of gathering system at a cost of $14.5 million. During the years ended September 30, 2010 and 2009, Midstream Corporation spent $6.4 million and $8.1 million, respectively, related to this project.
On September 17, 2010, the Company completed the sale of its sawmill in Marienville, Pennsylvania, including approximately 23 million board feet of logs and timber consisting of yard inventory along with unexpired timber cutting contracts and certain land and timber holdings designed to provide the purchaser with a supply of logs for the mill. Despite this sale, the Company has retained substantially all of its land and timber holdings, along with mineral rights on land to be sold. The Company will maintain a forestry operation; however, as part of this change in focus, the Company will no longer be processing lumber products. The Company received proceeds of approximately $15.8 million from the sale. In addition, the purchaser assumed approximately $7.4 million in payment obligations under the Company’s timber cutting contracts with various timber suppliers. In addition to the 23 million board feet mentioned above, the Company expects to sell an additional 17 million board feet of logs to the purchaser over a five-year period, during which time the Company anticipates receiving up to an additional $10 million in proceeds. There was not a material impact to earnings from this sale.
In 2008, the majority of the All Other and Corporate category’s expenditures for long-lived assets were for construction of a lumber sorter for Highland’s sawmill operations that was placed into service in October 2007, as well as for purchases of equipment for Highland’s sawmill and kiln operations. Additionally, Horizon Power sold a gas-powered turbine in March 2008 that it had planned to use in the development of a co-generation plant. Horizon Power received proceeds of $5.3 million and recorded a pre-tax gain of $0.9 million associated with the sale.
Estimated Capital Expenditures
The Company’s estimated capital expenditures for the next three years are:
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2011 | | | 2012 | | | 2013 | |
| | | (Millions) | |
| |
| Utility | | $ | 58.0 | | | $ | 58.0 | | | $ | 58.0 | |
| Pipeline and Storage | | | 130.0 | | | | 124.0 | | | | 341.0 | |
| Exploration and Production(1)(2) | | | 455.0 | | | | 596.0 | | | | 606.0 | |
| All Other | | | 30.0 | | | | 11.0 | | | | 10.0 | |
| | | | | | | | | | | | | |
| | | $ | 673.0 | | | $ | 789.0 | | | $ | 1,015.0 | |
| | | | | | | | | | | | | |
| | |
| (1) | | Includes estimated expenditures for the years ended September 30, 2011, 2012 and 2013 of approximately $140 million, $74 million and $29 million, respectively, to develop proved undeveloped reserves. The Company is committed to developing its proved undeveloped reserves within five years of being recorded as proved undeveloped reserves as required by the SEC’s final rule on Modernization of Oil and Gas Reporting. |
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| | |
| (2) | | Exploration and Production segment estimated capital expenditures do not take into account possible joint-venture opportunities involving this segment’s Marcellus Shale acreage. The amounts could change if a joint-venture is formed. |
Utility
Estimated capital expenditures for the Utility segment in 2011 will be concentrated in the areas of main and service line improvements and replacements and, to a lesser extent, the purchase of new equipment.
Pipeline and Storage
Estimated capital expenditures for the Pipeline and Storage segment in 2011 will be concentrated on the replacement of transmission and storage lines, the reconditioning of storage wells, improvements of compressor stations and construction of new pipeline and compressor stations to support expansion projects.
In light of the growing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia — specifically in the Marcellus Shale producing area — Supply Corporation and Empire are actively pursuing several expansion projects and paying for preliminary survey and investigation costs, which are initially recorded as Deferred Charges on the Consolidated Balance Sheet. An offsetting reserve is established as those preliminary survey and investigation costs are incurred, which reduces the Deferred Charges balance and increases Operation and Maintenance Expense on the Consolidated Statement of Income. The Company reviews all projects on a quarterly basis, and if it is determined that it is highly probable that the project will be built, the reserve is reversed. This reversal reduces Operation and Maintenance Expense and reestablishes the original balance in Deferred Charges. After the reversal of the reserve, amounts remain in Deferred Charges until construction begins, at which point the balance is transferred from Deferred Charges to Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet. As of September 30, 2010, the total amount reserved for the Pipeline and Storage segment’s preliminary survey and investigation costs was $5.1 million.
Supply Corporation is moving forward with several projects designed to move anticipated Marcellus production gas to other interstate pipelines and to markets beyond Supply Corporation’s pipeline system.
Supply Corporation has signed a precedent agreement to provide 320,000 Dth/day of firm transportation capacity in conjunction with its “Northern Access” expansion project. Upon satisfaction of the conditions in the precedent agreement, Statoil Natural Gas LLC will enter into a20-year firm transportation agreement for 320,000 Dth/day. This capacity will provide the subscribing shipper with a firm transportation path from the Tennessee Gas Pipeline (“TGP”) 300 Line at Ellisburg into the TransCanada Pipeline at Niagara. This path is attractive because it provides a route for Marcellus shale gas, principally along the TGP 300 Line in northern Pennsylvania, to be transported from the Marcellus supply basin to northern markets. Service is expected to begin in late 2012, and Supply Corporation has begun working on an application for FERC authorization of the project, which it expects to file in the second quarter of fiscal year 2011. The project facilities involve additional compression at Supply Corporation’s existing Ellisburg Station and at a new station in East Aurora, New York, along with other system enhancements including the jointly owned Niagara Spur Loop Line. The preliminary cost estimate for the Northern Access expansion is $60 million. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2010, less than $0.1 million has been spent to study the Northern Access expansion project, which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2010.
One strategic horsepower expansion project involves new compression along Supply Corporation’s Line N (“Line N Expansion Project”), increasing that line’s capacity by 160,000 Dth/day into Texas Eastern’s Holbrook Station (“TETCO Holbrook”) in southwestern Pennsylvania. A precedent agreement for 150,000 Dth/day of firm transportation has been executed and negotiations are underway for the remaining capacity. The project will allow Marcellus production located in the vicinity of Line N to flow south into Texas Eastern and access markets off Texas Eastern’s system, with a projected in-service date of September 2011. On October 20, 2009, the FERC granted Supply Corporation’s request for a pre-filing environmental review of the Line N Expansion Project, and on June 11, 2010, Supply Corporation filed an NGA Section 7(c) application to the FERC for
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approval of the project. The preliminary cost estimate for the Line N Expansion Project is $23 million, all of which is expected to be spent in fiscal 2011 and 2012 except for approximately $2.0 million already spent through September 30, 2010. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. The Company has determined that it is highly probable that this project will be built. Accordingly, all previous reserves established in connection with this project have been reversed, and the $2.0 million has been reestablished as a Deferred Charge on the Consolidated Balance Sheet.
Supply Corporation has also executed a precedent agreement for 150,000 Dth/day of additional capacity on Line N to TETCO Holbrook to be ready for service beginning November 2012 (“Line N Phase II Expansion Project”). The Line N Phase II Expansion Project will provide approximately 195,000 Dth/day of incremental firm transportation capacity. Marketing efforts are underway for the remaining 45,000 Dth/day of capacity. The preliminary cost estimate for the Line N Phase II Expansion Project is approximately $40 million. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2010, less than $0.1 million has been spent to study the Line N Phase II Expansion Project, which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2010.
Another strategic horsepower expansion project, involving the addition of compression at Supply Corporation’s existing interconnect with TGP at Lamont, Pennsylvania, has been in service since June 15, 2010 (“Lamont Project”).
A second Lamont Project phase is planned (“Lamont Phase II Project”). With the construction of additional horsepower, 50,000 Dth/day of incremental firm capacity will be available starting July 1, 2011 ramping up to full service by October 1, 2011. Supply Corporation has two signed precedent agreements for the full capacity of this project. The preliminary cost estimate for the Lamont Phase II Project is approximately $7 million. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2010, less than $0.1 million has been spent to study the Lamont Phase II project, which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2010.
In addition, Supply Corporation continues to actively pursue its largest planned expansion, theWest-to-East (“W2E”) pipeline project, which is designed to transport Rockiesand/or locally produced natural gas supplies to the Ellisburg/Leidy/Corning area. Supply Corporation anticipates that the development of the W2E project will occur in phases. As currently envisioned, the first two phases of W2E, referred to as the “W2E Overbeck to Leidy” project, are designed to transport at least 425,000 Dth/day, and involves construction of a new82-mile pipeline through Elk, Cameron, Clinton, Clearfield and Jefferson Counties to the Leidy Hub, from Marcellus and other producing areas along over 300 miles of Supply Corporation’s existing pipeline system. The W2E Overbeck to Leidy project also includes a total of approximately 25,000 horsepower of compression at two separate stations. The project may be built in phases depending on the development of Marcellus production along the corridor, with the first facilities expected to go in service in 2013.
Following an Open Season that concluded on October 8, 2009, Supply Corporation executed precedent agreements to provide 125,000 Dth/day of firm transportation on the W2E Overbeck to Leidy project. Supply Corporation is pursuing post-Open Season capacity requests for the remaining capacity. On March 31, 2010, the FERC granted Supply Corporation’s request for a pre-filing environmental review of the W2E Overbeck to Leidy project, and Supply Corporation is in the process of preparing an NGA Section 7(c) application. The capital cost of the W2E Overbeck to Leidy project is estimated to be $260 million, approximately $191 million of which is expected to be spent during the period of fiscal 2011 through 2013. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2010, approximately $3.8 million has been spent to study the W2E Overbeck to Leidy project, which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2010.
Supply Corporation expects that its previously announced Appalachian Lateral project will complement the W2E Overbeck to Leidy project due to its strategic upstream location. The Appalachian Lateral pipeline, which would be routed through several counties in central Pennsylvania where producers are actively drilling
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and seeking market access for their newly discovered reserves, will be able to collect and transport locally produced Marcellus shale gas into the W2E Overbeck to Leidy facilities. Supply Corporation expects to continue marketing efforts for the Appalachian Lateral and all other remaining sections of W2E. The timeline and projected costs associated with W2E sections other than W2E Overbeck to Leidy, including the Appalachian Lateral project, will depend on market development, and as of September 30, 2010, no preliminary survey and investigation charges had been spent on those projects and no capital expenditures are included as estimated capital expenditures in the table above.
Supply Corporation has also developed plans for new storage capacity by expansion of two of its existing storage facilities. The expansion of the East Branch and Galbraith fields will provide 7.9 MMDth of incremental storage capacity and approximately 88 MDth per day of additional withdrawal deliverability. This storage expansion project, if pursued, would require an NGA Section 7(c) application, which Supply Corporation has not yet filed. The preliminary cost estimate for this storage expansion project is $64 million. These expenditures are not included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2010, approximately $1.0 million has been spent to study this storage expansion project, which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2010. The specific timeline associated with the storage expansion will depend on market development, which at this time, due to economic conditions, does not warrant additional project development.
Empire has executed precedent agreements for all 350,000 Dth/day of incremental firm transportation capacity in its “Tioga County Extension Project.” This project will transport Marcellus production from new interconnections at the southern terminus of a16-mile extension of its recently completed Empire Connector line, in Tioga County, Pennsylvania. Empire’s preliminary cost estimate for the Tioga County Extension Project is approximately $46 million, all of which is expected to be spent in fiscal 2011 and 2012 except for approximately $2.0 million already spent through September 30, 2010. These expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. This project will enable shippers to deliver their natural gas at existing Empire interconnections with Millennium Pipeline at Corning, New York, with the TransCanada Pipeline at the Niagara River at Chippawa, and with utility and power generation markets along its path, as well as to a planned new interconnection with TGP’s 200 Line (Zone 5) in Ontario County, New York. On January 28, 2010, the FERC granted Empire’s request for a pre-filing environmental review of the Tioga County Extension Project, and on August 26, 2010, Empire filed an NGA Section 7(c) application to the FERC for approval of the project. Empire anticipates that these facilities will be placed in service on September 1, 2011. The Company has determined that it is highly probable that this project will be built. Accordingly, all previous reserves have been reversed and the $2.0 million has been reestablished as a Deferred Charge on the Consolidated Balance Sheet. Empire is evaluating a second phase expansion of the Tioga County Extension Project that could extend the Empire system further into the Marcellus production area in Pennsylvania,and/or increase the capacity by up to 260,000 Dth/day by late 2013. The cost of this second phase could be as much as $135 million, most of which would be spent in fiscal 2013 and is included as Pipeline and Storage segment estimated capital expenditures in the table above.
The Company anticipates financing the Line N Expansion Projects, the Lamont Projects, the Northern Access expansion project, the W2E Overbeck to Leidy project, the Appalachian Lateral project, and the Tioga County Extension Projects, all of which are discussed above, with a combination of cash from operations, short-term debt, and long-term debt. The Company had $395.2 million in Cash and Temporary Cash Investments at September 30, 2010, as shown on the Company’s Consolidated Balance Sheet. The Company expects to use cash from operations as the first means of financing these projects, with short-term debt providing temporary financing when needed. The Company may issue some long-term debt in conjunction with these projects in the later part of fiscal 2011 or in fiscal 2012.
Exploration and Production
Estimated capital expenditures in 2011 for the Exploration and Production segment include approximately $11.0 million for the Gulf Coast region, substantially all of which is for the off-shore program in the shallow waters of the Gulf of Mexico, $39.0 million for the West Coast region and $405.0 million for the Appalachian region. The Company anticipates drilling 100 to 130 gross wells in the Marcellus Shale during 2011.
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Estimated capital expenditures in 2012 for the Exploration and Production segment include approximately $20.0 million for the Gulf Coast region, substantially all of which is for the off-shore program in the shallow waters of the Gulf of Mexico, $43.0 million for the West Coast region and $533.0 million for the Appalachian region. The Company anticipates drilling 130 to 160 gross wells in the Marcellus Shale during 2012.
Estimated capital expenditures in 2013 for the Exploration and Production segment include approximately $47.0 million for the West Coast region and $559.0 million for the Appalachian region. The Company does not expect to incur any significant capital expenditures in the Gulf Coast region during 2013. The Company anticipates drilling 140 to 170 gross wells in the Marcellus Shale during 2013.
It is anticipated that these future capital expenditures will be funded with a combination of cash from operations, short-term debt, and long-term debt. Natural gas and crude oil prices combined with production from existing wells will be a significant factor in determining how much of the capital expenditures are funded from cash from operations. The Company expects to use cash from operations as the first means of financing these expenditures, with short-term debt providing temporary financing when needed. The Company may issue some long-term debt in conjunction with these expenditures in the later part of fiscal 2011 or in fiscal 2012.
All Other and Corporate
Estimated capital expenditures in 2011 for the All Other and Corporate category will primarily be for construction of anticipated gathering systems, including the construction of Midstream Corporation’s Trout Run Gathering System, as discussed below.
NFG Midstream Trout Run, LLC, a wholly owned subsidiary of Midstream Corporation, is planning a gathering system in Lycoming County, Pennsylvania. The project, called the Trout Run Gathering System, is anticipated to be placed in service in the fall of 2011. The system will consist of approximately 15.5 miles of gathering system at a cost of $27 million. These expenditures are included as All Other category capital expenditures in the table above. As of September 30, 2010, the Company has spent approximately $0.1 million in costs related to this project.
The Company anticipates funding the Midstream Corporation project with cash from operationsand/or short-term borrowings. Given the Company’s cash position at September 30, 2010, the Company expects to use cash from operations as the first means of financing these projects.
The Company continuously evaluates capital expenditures and investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, natural gas storage facilities and the expansion of natural gas transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.
FINANCING CASH FLOW
The Company did not have any outstanding short-term notes payable to banks or commercial paper at September 30, 2010 or during the fiscal year ended September 30, 2010. However, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporationsand/or partnerships,gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, repurchases of stock, and other working capital needs. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As for bank loans, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines, which aggregate to $405.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed, or substantially replaced by similar lines. The total amount available to be issued
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under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million, which commitment extends through September 30, 2013.
Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through September 30, 2013. At September 30, 2010, the Company’s debt to capitalization ratio (as calculated under the facility) was .42. The constraints specified in the committed credit facility would permit an additional $1.99 billion in short-termand/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio would exceed .65. If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its committed credit facility, uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations. In addition, the Company’s cost of capital is directly affected by its credit ratings. At September 30, 2010, the Company’s long-term debt ratings were: BBB (S&P), Baa1 (Moody’s Investor Service), and BBB+ (Fitch Ratings Service). In March 2010, Fitch Ratings Service decreased the Company’s long-term debt rating from A- to BBB+. The Company does not believe that this ratings action will impact its access to the commercial paper markets. At September 30, 2010, the Company’s commercial paper ratings were:A-2 (S&P),P-2 (Moody’s Investor Service), and F2 (Fitch Ratings Service). A credit rating is not a recommendation to buy, sell or hold securities. Each credit rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered in the context of the applicable methodology, independently of all other ratings. The rating agencies provide ratings at the request of the Company and charge the Company fees for their services.
Under the Company’s existing indenture covenants, at September 30, 2010, the Company would have been permitted to issue up to a maximum of $1.3 billion in additional long-term unsecured indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands. However, if the Company were to experience a significant loss in the future (for example, as a result of an impairment of oil and gas properties), it is possible, depending on factors including the magnitude of the loss, that these indenture covenants would restrict the Company’s ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not at any time preclude the Company from issuing new indebtedness to replace maturing debt.
The Company’s 1974 indenture pursuant to which $99.0 million (or 7.9%) of the Company’s long-term debt (as of September 30, 2010) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
The Company’s $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2010, the Company had no debt outstanding under the committed credit facility.
The Company’s embedded cost of long-term debt was 6.95% at both September 30, 2010 and September 30, 2009. If the Company were to issue long-term debt today, its borrowing costs might be expected to be in the
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range of 5.0% to 6.5% depending on the maturity date. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.
Current Portion of Long-Term Debt at September 30, 2010 consists of $200 million of 7.50% medium-term notes that mature in November 2010. Currently, the Company expects to refund these medium-term notes in November 2010 with cash on handand/or short-term borrowings.
In April 2009, the Company issued $250.0 million of 8.75% notes due in May 2019. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $247.8 million. These notes were registered under the Securities Act of 1933. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including to replenish cash that was used to pay the $100 million due at the maturity of the Company’s 6.0% medium-term notes on March 1, 2009.
On December 8, 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company could repurchase outstanding shares of common stock, up to an aggregate amount of eight million shares in the open market or through privately negotiated transactions. The Company completed the repurchase of the eight million shares during 2008 (“for a total program cost of $324.2 million (of which 4,165,122 shares were repurchased during the year ended September 30, 2008 Form 10-K”)for $191.0 million). In September 2008, the informationCompany’s Board of Directors authorized the repurchase of an additional eight million shares of the Company’s common stock. Under this new authorization, the Company repurchased 1,028,981 shares for $46.0 million through September 17, 2008. The Company, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. Since that time, the Company has increased its emphasis on Marcellus Shale development and pipeline expansion. As such, the Company does not anticipate repurchasing any shares in the near future. The share repurchases mentioned above were funded with cash provided by operating activitiesand/or through the use of the Company’s lines of credit.
The Company may issue debt or equity securities in a public offering or a private placement from time to time. The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, indenture requirements, regulatory authorizations and the capital requirements of the Company.
OFF-BALANCE SHEET ARRANGEMENTS
The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Utility and the Pipeline and Storage segments, having a remaining lease commitment of approximately $27.4 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters and other items and are accounted for as operating leases.
CONTRACTUAL OBLIGATIONS
The following table summarizes the Company’s expected future contractual cash obligations as of September 30, 2010, and the twelve-month periods over which they occur:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payments by Expected Maturity Dates | |
| | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | Thereafter | | | Total | |
| | | (Millions) | |
| |
| Long-Term Debt, including interest expense(1) | | $ | 274.0 | | | $ | 213.2 | | | $ | 304.2 | | | $ | 48.7 | | | $ | 48.7 | | | $ | 839.9 | | | $ | 1,728.7 | |
| Operating Lease Obligations | | $ | 5.1 | | | $ | 4.6 | | | $ | 3.5 | | | $ | 3.2 | | | $ | 2.8 | | | $ | 8.2 | | | $ | 27.4 | |
| Purchase Obligations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas Purchase Contracts(2) | | $ | 337.8 | | | $ | 47.7 | | | $ | 13.2 | | | $ | 0.4 | | | $ | — | | | $ | — | | | $ | 399.1 | |
| Transportation and Storage Contracts | | $ | 42.3 | | | $ | 38.6 | | | $ | 38.4 | | | $ | 34.3 | | | $ | 19.8 | | | $ | 14.5 | | | $ | 187.9 | |
| Other | | $ | 25.1 | | | $ | 5.1 | | | $ | 4.0 | | | $ | 3.9 | | | $ | 3.7 | | | $ | 11.3 | | | $ | 53.1 | |
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| | |
| (1) | | Refer to Note E — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense. |
|
| (2) | | Gas prices are variable based on the NYMEX prices adjusted for basis. |
The Company has other long-term obligations recorded on its Consolidated Balance Sheets that are not reflected in the table above. Such long-term obligations include pension and other post-retirement liabilities, asset retirement obligations, deferred income tax liabilities, various regulatory liabilities, derivative financial instrument liabilities and other deferred credits (the majority of which consist of liabilities for non-qualified benefit plans, deferred compensation liabilities, environmental liabilities, workers compensation liabilities and liabilities for income tax uncertainties).
The Company has made certain other guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the Consolidated Balance Sheets in accordance with the authoritative guidance (see Item 7, MD&A under the heading “Critical Accounting Estimates — Accounting for Derivative Financial Instruments”); (ii) NFR obligations to purchase gas or to purchase gas transportation/storage services where the amounts due on those obligations each month are included on the Consolidated Balance Sheets as a current liability; and (iii) other obligations which are reflected on the Consolidated Balance Sheets. The Company believes that the likelihood it would be required to make payments under the guarantees is remote, and therefore has not included them in the table above.
OTHER MATTERS
In addition to the environmental and other matters discussed in this Item 7 and in Item 8 at Note I — Commitments and Contingencies, 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 period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) that covers a majority of the Company’s employees. The Company has been making contributions to the Retirement Plan over the last several years and anticipates that it will continue making contributions to the Retirement Plan. During 2010, the Company contributed $22.2 million to the Retirement Plan. The Company anticipates that the annual contribution to the Retirement Plan in 2011 will be in the range of $40.0 million to $45.0 million. Changes in the discount rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund larger amounts to the Retirement Plan in 2011 in order to be in compliance with the Pension Protection Act of 2006. The Company expects that all subsidiaries having employees covered by Part IIIthe Retirement Plan will make contributions to the Retirement Plan. The funding of Form 10-K. Nosuch contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments or through short-term borrowings or through cash from operations.
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. The Company has been making contributions to its VEBA trusts and 401(h) accounts over the last several years and anticipates that it will continue making contributions to the VEBA trusts and 401(h) accounts. During 2010, the Company contributed $25.5 million to its VEBA trusts and 401(h) accounts. The Company anticipates that the annual contribution to its VEBA trusts and 401(h) accounts in 2011 will be in the range of $25.0 million to $30.0 million. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments.
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As of September 30, 2010, the Company has a federal net operating loss carryover of $19.7 million, which expires in varying amounts between 2023 and 2029. Although this loss carryover is subject to certain annual limitations, no valuation allowance was recorded because of management’s determination that the amount will be fully utilized during the carryforward period.
MARKET RISK SENSITIVE INSTRUMENTS
Energy Commodity Price Risk
The Company, in its Exploration and Production segment, Energy Marketing segment and Pipeline and Storage segment, uses various derivative financial instruments (derivatives), including price swap agreements and futures contracts, as part of the Company’s 2008 Form 10-Koverall energy commodity price risk management strategy. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas and crude oil, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would receive from, or pay to, the respective counterparties at September 30, 2010 to terminate the derivatives. However, the tables below and the fair value that is amended hereby.disclosed do not consider the physical side of the natural gas and crude oil transactions that are related to the financial instruments.
On July 21, 2010, the Wall Street Reform and Consumer Protection Act (H.R. 4173) was signed into law. The information includedlaw includes provisions related to the swaps andover-the-counter derivatives markets. A variety of rules must be adopted by federal agencies (including the Commodity Futures Trading Commission, SEC and the FERC) to implement the law. These rules, which will be implemented over time frames as determined in the law, could have a significant impact on the Company that was not clearly defined in the law itself. Under the law, the Company expects to be exempt from mandatory clearing and exchange trading requirements for most or all of its commodity hedges. Capital and margin requirements for these hedges are expected to be determined as regulators write more detailed rules and requirements. While the Company is currently reviewing the provisions of H.R. 4173, it will not be able to determine the impact to its financial condition until the final rules are issued.
In accordance with the authoritative guidance for fair value measurements, the Company has identified certain inputs used to recognize fair value as Level 3 (unobservable inputs). The Level 3 derivative net liabilities relate to oil swap agreements used to hedge forecasted sales at a specific location (southern California). The Company’s internal model that is used to calculate fair value applies a historical basis differential (between the sales locations and NYMEX) to a forward NYMEX curve because there is not a forward curve specific to this sales location. Given the high level of historical correlation between NYMEX prices and prices at this sales location, the Company does not believe that the fair value recorded by the Company would be significantly different from what it expects to receive upon settlement.
The Level 3 net liabilities amount to $16.5 million at September 30, 2010 and represent 4.6% of the Total Net Assets shown in Item 118 at Note F — Fair Value Measurements at September 30, 2010.
The Company uses the crude oil swaps classified as Level 3 to hedge against the risk of declining commodity prices and not as speculative investments. Gains or losses related to these Level 3 derivative net liabilities (including any reduction for credit risk) are deferred until the hedged commodity transaction occurs in accordance with the provisions of the existing guidance for derivative instruments and hedging activities.
The decrease in the net fair value of the Level 3 positions from a net asset position at October 1, 2009 to a net liability position at September 30, 2010, as shown in Item 8 at Note F, was attributable to an increase in the commodity price of crude oil relative to the swap price during that period. The Company believes that these fair values reasonably represent the amounts that the Company would realize upon settlement based on commodity prices that were present at September 30, 2010.
The fair value of all of the Company’s Net Derivative Assets was reduced by $0.7 million based upon the Company’s assessment of counterparty credit risk (for the Company’s derivative assets) and the Company’s
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credit risk (for the Company’s derivative liabilities). The Company applied default probabilities to the anticipated cash flows that it was expecting to receive and pay to its counterparties to calculate the credit reserve.
The following tables disclose natural gas and crude oil price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2010. At September 30, 2010, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2014.
Natural Gas Price Swap Agreements
| | | | | | | | | | | | | | | | | | | | | |
| | | Expected Maturity Dates |
| | | 2011 | | 2012 | | 2013 | | 2014 | | Total |
| |
| Notional Quantities (Equivalent Bcf) | | | 20.4 | | | | 13.9 | | | | 3.9 | | | | 0.1 | | | | 38.3 | |
| Weighted Average Fixed Rate (per Mcf) | | $ | 6.77 | | | $ | 7.11 | | | $ | 6.67 | | | $ | 7.12 | | | $ | 6.88 | |
| Weighted Average Variable Rate (per Mcf) | | $ | 4.67 | | | $ | 5.47 | | | $ | 5.85 | | | $ | 5.78 | | | $ | 5.09 | |
Of the total Bcf above, 0.4 Bcf is accounted for as fair value hedges at a weighted average fixed rate of $7.18 per Mcf. The remaining 37.9 Bcf are accounted for as cash flow hedges at a weighted average fixed rate of $6.88 per Mcf.
Crude Oil Price Swap Agreements
| | | | | | | | | | | | | | | | | |
| | | Expected Maturity Dates |
| | | 2011 | | 2012 | | 2013 | | Total |
| |
| Notional Quantities (Equivalent bbls) | | | 1,560,000 | | | | 972,000 | | | | 156,000 | | | | 2,688,000 | |
| Weighted Average Fixed Rate (per bbl) | | $ | 69.93 | | | $ | 69.34 | | | $ | 72.98 | | | $ | 69.89 | |
| Weighted Average Variable Rate (per bbl) | | $ | 74.71 | | | $ | 78.04 | | | $ | 79.27 | | | $ | 76.18 | |
At September 30, 2010, the Company would have received from its respective counterparties an aggregate of approximately $67.3 million to terminate the natural gas price swap agreements outstanding at that date. The Company would have to pay its respective counterparties an aggregate of approximately $16.5 million to terminate the crude oil price swap agreements outstanding at September 30, 2010.
At September 30, 2009, the Company had natural gas price swap agreements covering 38.0 Bcf at a weighted average fixed rate of $7.15 per Mcf. The Company also had crude oil price swap agreements covering 2,688,000 bbls at a weighted average fixed rate of $71.14 per bbl.
The following table discloses the net contract volume purchased (sold), weighted average contract prices and weighted average settlement prices by expected maturity date for futures contracts used to manage natural gas price risk. At September 30, 2010, the Company held no futures contracts with maturity dates extending beyond 2013.
Futures Contracts
| | | | | | | | | | | | | | | | | |
| | | Expected Maturity Dates |
| | | 2011 | | 2012 | | 2013 | | Total |
| |
| Net Contract Volume Purchased (Sold) (Equivalent Bcf) | | | 4.8 | | | | 2.8 | | | | 0.1 | (1) | | | 7.7 | |
| Weighted Average Contract Price (per Mcf) | | $ | 5.42 | | | $ | 5.85 | | | $ | 6.39 | | | $ | 5.48 | |
| Weighted Average Settlement Price (per Mcf) | | $ | 5.64 | | | $ | 6.45 | | | $ | 7.15 | | | $ | 5.77 | |
| | |
| (1) | | The Energy Marketing segment has purchased 14 futures contracts (1 contract = 10,000 Dth) for 2013. |
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At September 30, 2010, the Company had long (purchased) futures contracts covering 14.2 Bcf of gas extending through 2013 at a weighted average contract price of $5.47 per Mcf and a weighted average settlement price of $4.54 per Mcf. Of this Amendment No.amount, 14.1 Bcf is accounted for as fair value hedges and are used by the Company’s Energy Marketing segment to hedge against rising prices, a risk to which this segment is exposed to due to the fixed price gas sales commitments that it enters into with certain residential, commercial, industrial, public authority and wholesale customers. The remaining 0.1 Bcf is accounted for as cash flow hedges used to hedge against rising prices related to anticipated gas purchases for potential injections into storage. The Company would have had to pay $13.2 million to terminate these futures contracts at September 30, 2010.
At September 30, 2010, the Company had short (sold) futures contracts covering 6.5 Bcf of gas extending through 2011 at a weighted average contract price of $5.52 per Mcf and a weighted average settlement price of $4.38 per Mcf. Of this amount, 5.7 Bcf is accounted for as cash flow hedges as these contracts relate to the anticipated sale of natural gas by the Energy Marketing segment. The remaining 0.8 Bcf is accounted for as fair value hedges used to hedge against falling prices, a risk to which the Energy Marketing segment is exposed to due to the fixed price gas purchase commitments that it enters into with its natural gas suppliers. The Company would have received $7.4 million to terminate these futures contracts at September 30, 2010.
At September 30, 2009, the Company had long (purchased) futures contracts covering 11.6 Bcf of gas extending through 2012 at a weighted average contract price of $6.37 per Mcf and a weighted average settlement price of $6.07 per Mcf.
At September 30, 2009, the Company had short (sold) futures contracts covering 6.7 Bcf of gas extending through 2011 at a weighted average contract price of $7.37 per Mcf and a weighted average settlement price of $6.07 per Mcf. Of this amount, 5.8 Bcf is accounted for as cash flow hedges as these contracts relate to the anticipated sale of natural gas by the Energy Marketing segment. The remaining 0.9 Bcf is accounted for as fair value hedges used to hedge against falling prices.
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company hasover-the-counter swap positions with eleven counterparties of which ten of the eleven counterparties are in a net gain position. On average, the Company had $6.5 million of credit exposure per counterparty in a gain position at September 30, 2010. The maximum credit exposure per counterparty at September 30, 2010 was $11.9 million. BP Energy Company (an affiliate of BP Corporation North America, Inc.) was one of the ten counterparties in a gain position. At September 30, 2010, the Company had an $11.3 million receivable with BP Energy Company. The Company considered the credit quality of BP Energy Company (as it does with all of its counterparties) in determining hedge effectiveness and believes the hedges remain effective. The Company had not received any collateral from these counterparties at September 30, 2010 since the Company’s gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral.
As of September 30, 2010, nine of the eleven counterparties to the Company’s outstanding derivative instrument contracts (specifically theover-the-counter swaps) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (the lower of the S&P or Moody’s Debt Rating), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position and the Company’s credit rating declined, then additional hedging collateral deposits would be required. At September 30, 2010, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $42.1 million according to the Company’s internal model (discussed in Item 8 at Note F — Fair Value Measurements). At September 30, 2010, the fair market value of the derivative financial instrument liability with a credit-risk related contingency feature was $14.3 million according to the Company’s internal model (discussed in Item 8 at Note F — Fair Value Measurements). For itsover-the-counter crude oil
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swap agreements, which are in a liability position, the Company was required to post $1.0 million in hedging collateral deposits at September 30, 2010. This is discussed in Item 8 at Note A under Hedging Collateral Deposits.
For its exchange traded futures contracts which are in a liability position, the Company had posted $10.1 million in hedging collateral as of September 30, 2010. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.
The Company’s requirement to post hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Item 8 at Note A under Hedging Collateral Deposits.
Interest Rate Risk
The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt as well as the other long-term debt of certain of the Company’s subsidiaries:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Principal Amounts by Expected Maturity Dates |
| | | 2011 | | 2012 | | 2013 | | 2014 | | 2015 | | Thereafter | | Total |
| | | (Dollars in millions) |
| |
| Long-Term Fixed Rate Debt | | $ | 200.0 | | | $ | 150.0 | | | $ | 250.0 | | | $ | — | | | $ | — | | | $ | 649.0 | | | $ | 1,249.0 | |
| Weighted Average Interest Rate Paid | | | 7.5 | % | | | 6.7 | % | | | 5.3 | % | | | — | | | | — | | | | 7.5 | % | | | 7.0 | % |
| Fair Value of Long-Term Fixed Rate Debt = $1,423.3 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
RATE AND REGULATORY MATTERS
Utility Operation
Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and are changed only when approved through a procedure known as a “rate case.” Currently neither division has a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected through a separately-stated “supply charge” on the customer bill.
New York Jurisdiction
Customer delivery rates charged by Distribution Corporation’s New York division were established in a rate order issued on December 21, 2007 by the NYPSC. The rate order approved a revenue increase of $1.8 million annually, together with a surcharge that would collect up to $10.8 million to cover expenses for implementation of an efficiency and conservation incentive program. The rate order further provided for a return on equity of 9.1%. In connection with the efficiency and conservation program, the rate order approved a revenue decoupling mechanism. The revenue decoupling mechanism “decouples” revenues from throughput by enabling the Company to collect from small volume customers its allowed margin on average weather normalized usage per customer. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. The Company surcharges or credits any difference from the average weather normalized usage per customer account. The surcharge or credit is calculated to recover total margin for the most recent twelve-month period ending December 31, and is applied to customer bills annually, beginning March 1st.
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On April 18, 2008, Distribution Corporation filed an appeal with Supreme Court, Albany County, seeking review of the rate order. The appeal contended that portions of the rate order were invalid because they failed to meet the applicable legal standard for agency decisions. Among the issues challenged by the Company was the reasonableness of the NYPSC’s disallowance of expense items and the methodology used for calculating rate of return, which the appeal contended understated the Company’s cost of equity. Because of the issues appealed, the case was later transferred to the Appellate Division, New York State’s second-highest court. On December 31, 2009, the Appellate Division issued its Opinion and Judgment. The court upheld the NYPSC’s determination relating to the authorized rate of return but also supported the Company’s argument that the NYPSC improperly disallowed recovery of certain environmentalclean-up costs. On February 1, 2010, the NYPSC filed a motion with the Court of Appeals, New York State’s highest court, seeking permission to appeal the Appellate Division’s annulment of that part of the rate order relating to disallowance of environmental clean up costs. On May 4, 2010, the NYPSC’s motion was granted, and the matter will be heard by the Court of Appeals. The Briefing schedule began on Form 10-K/AJuly 28, 2010 and is followed by oral argument. The Company cannot predict the outcome of the appeal proceedings at this time.
Pennsylvania Jurisdiction
Distribution Corporation’s current delivery charges in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007.
Pipeline and Storage
Supply Corporation currently does not have a rate case on file with the FERC. The rate settlement approved by the FERC on February 9, 2007 requires Supply Corporation to make a general rate filing to be effective December 1, 2011, and bars Supply Corporation from making a general rate filing before then, with some exceptions specified in the settlement.
Empire’s new facilities (the Empire Connector project) were placed into service on December 10, 2008. As of that date, Empire became an interstate pipeline subject to FERC regulation, performing services under a FERC-approved tariff and at FERC-approved rates. The December 21, 2006 FERC order issuing Empire its Certificate of Public Convenience and Necessity requires Empire to file a cost and revenue study at the FERC following three years of actual operation, in conjunction with which Empire will either justify Empire’s existing recourse rates or propose alternative rates.
ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmentalclean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, 2010, the Company has estimated its remainingclean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $17.3 million to $21.5 million. The minimum estimated liability of $17.3 million has been recorded on the Consolidated Balance Sheet at September 30, 2010. The Company expects to recover its environmentalclean-up costs through rate recovery. Other than as discussed in Note I (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.
For further discussion refer to Item 8 at Note I — Commitments and Contingencies under the heading “Compensation Committee Report” is furnished, not filed, pursuant“Environmental Matters.”
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. The EPA has determined that stationary sources of significant greenhouse gas emissions will be required under the Instructionsfederal Clean Air Act to Item 407(e)(5) of Regulation S-K.obtain permits covering such emissions beginning in January 2011. In addition, the U.S. Congress has been considering bills that would
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establish acap-and-trade program to reduce emissions of greenhouse gases. Legislation or regulation that restricts carbon emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilitiesand/or purchase emission allowances. Climate change and greenhouse gas measures could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, or impose additional monitoring and reporting requirements. But legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted. PART IIINEW AUTHORITATIVE ACCOUNTING AND FINANCIAL REPORTING GUIDANCE
In September 2006, the FASB issued authoritative guidance for using fair value to measure assets and liabilities. This guidance serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. This guidance is to be applied whenever assets or liabilities are to be measured at fair value. On October 1, 2008, the Company adopted this guidance for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis. The FASB’s authoritative guidance for using fair value to measure nonfinancial assets and nonfinancial liabilities on a nonrecurring basis became effective during the quarter ended December 31, 2009. The Company’s nonfinancial assets and nonfinancial liabilities were not significantly impacted by this guidance during the year ended September 30, 2010. The Company had identified Goodwill as being the major nonfinancial asset that may have been impacted by the adoption of this guidance; however, the adoption of the guidance did not have a significant impact on the Company’s annual test for goodwill impairment. The Company had identified Asset Retirement Obligations as a nonfinancial liability that may have been impacted by the adoption of the guidance. The adoption of the guidance did not have a significant impact on the Company’s Asset Retirement Obligations. Refer to Item 8 at Note B — Asset Retirement Obligations for further disclosure. Additionally, in February 2010, the FASB issued updated guidance that includes additional requirements and disclosures regarding fair value measurements. The guidance now requires the gross presentation of activity within the Level 3 roll forward and requires disclosure of details on transfers in and out of Level 1 and 2 fair value measurements. It also provides further clarification on the level of disaggregation of fair value measurements and disclosures on inputs and valuation techniques. The Company has updated its disclosures to reflect the new requirements in Item 8 at Note F — Fair Value Measurements, except for the Level 3 roll forward gross presentation, which will be effective as of the Company’s first quarter of fiscal 2012.
On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting. The final rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves and aligns the full cost accounting rules with the revised disclosures. The most notable changes of the final rule include the replacement of the single day period-end pricing used to value oil and gas reserves with an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. Additionally, on January 6, 2010, the FASB amended the oil and gas accounting standards to conform to the SEC final rule on Modernization of Oil and Gas Reporting (final rule). The revised reporting and disclosure requirements became effective with thisForm 10-K for the period ended September 30, 2010. The Company has updated its disclosures to reflect the new requirements in Item 8 at Note Q — Supplementary Information for Oil and Gas Producing Activities. The Company chose not to disclose probable and possible reserves. In order to estimate the effect of adopting the final rule, the Company would be required to prepare two sets of reserve reports (applying both the final rule and previous rules). There would be significant time and expense associated with preparing two sets of reports to address changes between the different rules. Since the information obtained from the dual reserve reports would be relevant only for transitional purposes, the cost is deemed to exceed the benefit. As a result, the Company has determined it would be impractical to estimate the impact of adoption of the final rule.
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In March 2009, the FASB issued authoritative guidance that expands the disclosures required in an employer’s financial statements about pension and other post-retirement benefit plan assets. The additional disclosures include more details on how investment allocation decisions are made, the plan’s investment policies and strategies, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period, and disclosure regarding significant concentrations of risk within plan assets. The additional disclosure requirements became effective with thisForm 10-K for the period ended September 30, 2010. The Company has updated its disclosures to reflect the new requirements in Item 8 at Note H — Retirement Plan and Other Post-Retirement Benefits.
In June 2009, the FASB issued amended authoritative guidance to improve and clarify financial reporting requirements by companies involved with variable interest entities. The new guidance requires a company to perform an analysis to determine whether the company’s variable interest or interests give it a controlling financial interest in a variable interest entity. The analysis also assists in identifying the primary beneficiary of a variable interest entity. This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2011. Given the current organizational structure of the Company, the Company does not believe this authoritative guidance will have any impact on its consolidated financial statements.
EFFECTS OF INFLATION
Although the rate of inflation has been relatively low over the past few years, the Company’s operations remain sensitive to increases in the rate of inflation because of its capital spending and the regulated nature of a significant portion of its business.
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
The Company is including the following cautionary statement in thisForm 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, strategies, future events or performance and underlying assumptions, 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,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:
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| 1. | Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; |
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| 2. | Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; |
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| 3. | The creditworthiness or performance of the Company’s key suppliers, customers and counterparties; |
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| 4. | Economic disruptions or uninsured losses resulting from terrorist activities, acts of war, major accidents, fires, hurricanes, other severe weather, pest infestation or other natural disasters; |
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| 5. | Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits and compliance with environmental laws and regulations; |
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| 6. | Changes in laws and regulations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, and exploration and production activities such as hydraulic fracturing; |
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| 7. | Uncertainty of oil and gas reserve estimates; |
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| 8. | Significant differences between the Company’s projected and actual production levels for natural gas or oil; |
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| 9. | Significant changes in market dynamics or competitive factors affecting the Company’s ability to retain existing customers or obtain new customers; |
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| 10. | Changes in demographic patterns and weather conditions; |
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| 11. | Changes in the availabilityand/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments; |
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| 12. | Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; |
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| 13. | Changes in the availabilityand/or cost of derivative financial instruments; |
|
| 14. | Changes in the price differentials between oil having different qualityand/or different geographic locations, or changes in the price differentials between natural gas having different heating valuesand/or different geographic locations; |
|
| 15. | Changes in the projected profitability of pending or potential projects, investments or transactions; |
|
| 16. | Significant differences between the Company’s projected and actual capital expenditures and operating expenses; |
|
| 17. | Delays or changes in costs or plans with respect to our projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; |
|
| 18. | Governmental/regulatory actions, initiatives and proceedings, including those involving derivatives, acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; |
|
| 19. | Unanticipated impacts of restructuring initiatives in the natural gas and electric industries; |
|
| 20. | Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; |
|
| 21. | Changes in actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; |
|
| 22. | Significant changes in tax rates or policies or in rates of inflation or interest; |
65
| |
| 23. | Significant changes in the Company’s relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur; |
|
| 24. | Changes in accounting principles or the application of such principles to the Company; |
|
| 25. | The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; |
|
| 26. | Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or |
|
| 27. | Increasing costs of insurance, changes in coverage and the ability to obtain insurance. |
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
Industry and Market Information
The industry and market data used or referenced in this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources. Some industry and market data may also be based on good faith estimates, which are derived from the Company’s review of internal information, as well as the independent sources listed above. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While the Company believes that each of these studies and publications is reliable, the Company has not independently verified such data and makes no representation as to the accuracy of such information. Forecasts in particular may prove to be inaccurate, especially over long periods of time. Similarly, while the Company believes its internal information is reliable, such information has not been verified by any independent sources, and the Company makes no assurances that any predictions contained herein will prove to be accurate.
| |
| Item 7A | Quantitative and Qualitative Disclosures About Market Risk |
Refer to the “Market Risk Sensitive Instruments” section in Item 107, MD&A.
66
| |
| Item 8 | Financial Statements and Supplementary Data |
Directors, Executive Officers and Corporate GovernanceIndex to Financial Statements
DIRECTORS
| | | | | | |
Name and Year | | Page |
|
Financial Statements: | | | | |
Became a Director | | | | |
| Report of Independent Registered Public Accounting Firm | | | 68 | |
| Consolidated Statements of Income and Earnings Reinvested in the Business, three years ended September 30, 2010 | | | 69 | |
| Consolidated Balance Sheets at September 30, 2010 and 2009 | | | 70 | |
| Consolidated Statements of Cash Flows, three years ended September 30, 2010 | | | 71 | |
| Consolidated Statements of Comprehensive Income, three years ended September 30, 2010 | | | 72 | |
| Notes to Consolidated Financial Statements | | | 73 | |
| Financial Statement Schedules: | | | | |
ofFor the Company | | Age(1) | | Principal Occupation |
| | three years ended September 30, 2010 | | | | |
Nominees for Election as Directors
For Three-Year Terms to Expire in 2012
|
| Schedule II — Valuation and Qualifying Accounts | | | | | 131 | |
R. DON CASH
2003 | | | 66 | | | Chairman Emeritus since May 2003, and Board Director since May 1978, of Questar Corporation (Questar), an integrated natural gas company headquartered in Salt Lake City, Utah. Chairman of Questar from May 1985 to May 2003. Chief Executive Officer of Questar from May 1984 to May 2002 and President of Questar from May 1984 to February 1, 2001. Director of Zions Bancorporation since 1982 and Associated Electric and Gas Insurance Services Limited since 1993. Director of Texas Tech Foundation since November 2003 and TODCO (The Offshore Drilling Company) from May 2004 until July 2007. Former trustee, until September 2002, of the Salt Lake Organizing Committee for the Olympic Winter Games of 2002. |
| | | | | | |
STEPHEN E. EWING
2007 | | | 64 | | | Vice Chairman of DTE Energy, a Detroit-based diversified energy company involved in the development and management of energy-related businesses and services nationwide, from November 1, 2005 until December 31, 2006. Group President, Gas Division, DTE Energy from June 1, 2001 until November 1, 2005. Former president and chief operating officer of MCN Energy Group, Inc. Former president and Chief Executive Officer of Michigan Consolidated Gas Co. (MichCon), a natural gas utility. MichCon is a principal operating subsidiary of DTE Energy as a result of the 2001 merger of DTE Energy and MCN Energy Group, Inc. Chairman of the Board of Directors of the American Gas Association for 2006 and past chairman of the Midwest Gas Association and the Natural Gas Vehicle Coalition. |
| | | | | | |
GEORGE L. MAZANEC
1996 | | | 72 | | | Former Vice Chairman, from 1989 until October 1996, of PanEnergy Corporation, Houston, Texas, a diversified energy company (now part of Spectra). Advisor to the Chief Operating Officer of Duke Energy Corporation from August 1997 to 2000. Director of TEPPCO, LP from 1992 to 1997, Director of Northern Border Pipeline Company Partnership from 1993 to 1998, Director of Westcoast Energy Inc. from 1998 to 2002 and Director of the Northern Trust Bank of Texas, NA from 1998 to 2007. Director of Dynegy Inc. since May 2004 and Director of Associated Electric and Gas Insurance Services Limited since 1995. Former Chairman of the Management Committee of Maritimes & Northeast Pipeline, L.L.C. Member of the Board of Trustees of DePauw University since 1996. |
All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.
Supplementary Data
Supplementary data that is included in Note O — Quarterly Financial Data (unaudited) and Note Q — Supplementary Information for Oil and Gas Producing Activities (unaudited), appears under this Item, and reference is made thereto.
67
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of National Fuel Gas Company:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of National Fuel Gas Company and its subsidiaries at September 30, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2010, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note A to the consolidated financial statements, the Company changed the manner in which its oil and gas reserves are estimated, as well as the manner in which prices are determined to calculate the ceiling on capitalized oil and gas costs as of September 30, 2010.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
Buffalo, New York
November 24, 2010
68
NATIONAL FUEL GAS COMPANY
REINVESTED IN THE BUSINESS
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands of dollars, except per common share amounts) | |
| |
INCOME | | | | | | | | | | | | |
Operating Revenues | | $ | 1,760,503 | | | $ | 2,051,543 | | | $ | 2,396,837 | |
| | | | | | | | | | | | | |
Operating Expenses | | | | | | | | | | | | |
| Purchased Gas | | | 658,432 | | | | 997,216 | | | | 1,238,405 | |
| Operation and Maintenance | | | 394,569 | | | | 401,200 | | | | 429,394 | |
| Property, Franchise and Other Taxes | | | 75,852 | | | | 72,102 | | | | 75,525 | |
| Depreciation, Depletion and Amortization | | | 191,199 | | | | 170,620 | | | | 169,846 | |
| Impairment of Oil and Gas Producing Properties | | | — | | | | 182,811 | | | | — | |
| | | | | | | | | | | | | |
| | | | 1,320,052 | | | | 1,823,949 | | | | 1,913,170 | |
| | | | | | | | | | | | | |
Operating Income | | | 440,451 | | | | 227,594 | | | | 483,667 | |
Other Income (Expense): | | | | | | | | | | | | |
| Income from Unconsolidated Subsidiaries | | | 2,488 | | | | 3,366 | | | | 6,303 | |
| Impairment of Investment in Partnership | | | — | | | | (1,804 | ) | | | — | |
| Other Income | | | 3,638 | | | | 8,200 | | | | 7,164 | |
| Interest Income | | | 3,729 | | | | 5,776 | | | | 10,815 | |
| Interest Expense on Long-Term Debt | | | (87,190 | ) | | | (79,419 | ) | | | (70,099 | ) |
| Other Interest Expense | | | (6,756 | ) | | | (7,370 | ) | | | (3,271 | ) |
| | | | | | | | | | | | | |
Income from Continuing Operations Before Income Taxes | | | 356,360 | | | | 156,343 | | | | 434,579 | |
| Income Tax Expense | | | 137,227 | | | | 52,859 | | | | 167,672 | |
| | | | | | | | | | | | | |
Income from Continuing Operations | | | 219,133 | | | | 103,484 | | | | 266,907 | |
Discontinued Operations: | | | | | | | | | | | | |
| Income (Loss) from Operations, Net of Tax | | | 470 | | | | (2,776 | ) | | | 1,821 | |
| Gain on Disposal, Net of Tax | | | 6,310 | | | | — | | | | — | |
| | | | | | | | | | | | | |
Income (Loss) from Discontinued Operations, Net of Tax | | | 6,780 | | | | (2,776 | ) | | | 1,821 | |
| | | | | | | | | | | | | |
Net Income Available for Common Stock | | | 225,913 | | | | 100,708 | | | | 268,728 | |
| | | | | | | | | | | | | |
EARNINGS REINVESTED IN THE BUSINESS | | | | | | | | | | | | |
| Balance at Beginning of Year | | | 948,293 | | | | 953,799 | | | | 983,776 | |
| | | | | | | | | | | | | |
| | | | 1,174,206 | | | | 1,054,507 | | | | 1,252,504 | |
| Share Repurchases | | | — | | | | — | | | | (194,776 | ) |
| Cumulative Effect of Adoption of Authoritative Guidance for Income Taxes | | | — | | | | — | | | | (406 | ) |
| Adoption of Authoritative Guidance for Defined Benefit Pension and Other Post-Retirement Plans | | | — | | | | (804 | ) | | | — | |
| Dividends on Common Stock | | | (110,944 | ) | | | (105,410 | ) | | | (103,523 | ) |
| | | | | | | | | | | | | |
Balance at End of Year | | $ | 1,063,262 | | | $ | 948,293 | | | $ | 953,799 | |
| | | | | | | | | | | | | |
Earnings Per Common Share: | | | | | | | | | | | | |
| Basic: | | | | | | | | | | | | |
| Income from Continuing Operations | | $ | 2.70 | | | $ | 1.29 | | | $ | 3.25 | |
| Income (Loss) from Discontinued Operations | | | 0.08 | | | | (0.03 | ) | | | 0.02 | |
| | | | | | | | | | | | | |
Net Income Available for Common Stock | | $ | 2.78 | | | $ | 1.26 | | | $ | 3.27 | |
| | | | | | | | | | | | | |
| Diluted: | | | | | | | | | | | | |
| Income from Continuing Operations | | $ | 2.65 | | | $ | 1.28 | | | $ | 3.16 | |
| Income (Loss) from Discontinued Operations | | | 0.08 | | | | (0.03 | ) | | | 0.02 | |
| | | | | | | | | | | | | |
Net Income Available for Common Stock | | $ | 2.73 | | | $ | 1.25 | | | $ | 3.18 | |
| | | | | | | | | | | | | |
Weighted Average Common Shares Outstanding: | | | | | | | | | | | | |
| Used in Basic Calculation | | | 81,380,434 | | | | 79,649,965 | | | | 82,304,335 | |
| | | | | | | | | | | | | |
| Used in Diluted Calculation | | | 82,660,598 | | | | 80,628,685 | | | | 84,474,839 | |
| | | | | | | | | | | | | |
See Notes to Consolidated Financial Statements
69
NATIONAL FUEL GAS COMPANY
| | | | | | | | | |
| | | At September 30 | |
| | | 2010 | | | 2009 | |
| | | (Thousands of dollars) | |
| |
ASSETS |
Property, Plant and Equipment | | $ | 5,637,498 | | | $ | 5,184,844 | |
| Less — Accumulated Depreciation, Depletion and Amortization | | | 2,187,269 | | | | 2,051,482 | |
| | | | | | | | | |
| | | | 3,450,229 | | | | 3,133,362 | |
| | | | | | | | | |
Current Assets | | | | | | | | |
| Cash and Temporary Cash Investments | | | 395,171 | | | | 408,053 | |
| Cash Held in Escrow | | | 2,000 | | | | 2,000 | |
| Hedging Collateral Deposits | | | 11,134 | | | | 848 | |
| Receivables — Net of Allowance for Uncollectible Accounts of $30,961 and $38,334, Respectively | | | 132,136 | | | | 144,466 | |
| Unbilled Utility Revenue | | | 20,920 | | | | 18,884 | |
| Gas Stored Underground | | | 48,584 | | | | 55,862 | |
| Materials and Supplies — at average cost | | | 24,987 | | | | 24,520 | |
| Other Current Assets | | | 115,969 | | | | 68,474 | |
| Deferred Income Taxes | | | 24,476 | | | | 53,863 | |
| | | | | | | | | |
| | | | 775,377 | | | | 776,970 | |
| | | | | | | | | |
Other Assets | | | | | | | | |
| Recoverable Future Taxes | | | 149,712 | | | | 138,435 | |
| Unamortized Debt Expense | | | 12,550 | | | | 14,815 | |
| Other Regulatory Assets | | | 542,801 | | | | 530,913 | |
| Deferred Charges | | | 9,646 | | | | 2,737 | |
| Other Investments | | | 77,839 | | | | 78,503 | |
| Investments in Unconsolidated Subsidiaries | | | 14,828 | | | | 14,940 | |
| Goodwill | | | 5,476 | | | | 5,476 | |
| Intangible Assets | | | 1,677 | | | | 21,536 | |
| Fair Value of Derivative Financial Instruments | | | 65,184 | | | | 44,817 | |
| Other | | | 306 | | | | 6,625 | |
| | | | | | | | | |
| | | | 880,019 | | | | 858,797 | |
| | | | | | | | | |
Total Assets | | $ | 5,105,625 | | | $ | 4,769,129 | |
| | | | | | | | | |
| |
CAPITALIZATION AND LIABILITIES |
Capitalization: | | | | | | | | |
Comprehensive Shareholders’ Equity | | | | | | | | |
| Common Stock, $1 Par Value | | | | | | | | |
| Authorized — 200,000,000 Shares; Issued and Outstanding — 82,075,470 Shares and 80,499,915 Shares, Respectively | | $ | 82,075 | | | $ | 80,500 | |
| Paid In Capital | | | 645,619 | | | | 602,839 | |
| Earnings Reinvested in the Business | | | 1,063,262 | | | | 948,293 | |
| | | | | | | | | |
| Total Common Shareholders’ Equity Before Items Of Other Comprehensive Loss | | | 1,790,956 | | | | 1,631,632 | |
| Accumulated Other Comprehensive Loss | | | (44,985 | ) | | | (42,396 | ) |
| | | | | | | | | |
Total Comprehensive Shareholders’ Equity | | | 1,745,971 | | | | 1,589,236 | |
Long-Term Debt, Net of Current Portion | | | 1,049,000 | | | | 1,249,000 | |
| | | | | | | | | |
Total Capitalization | | | 2,794,971 | | | | 2,838,236 | |
| | | | | | | | | |
Current and Accrued Liabilities | | | | | | | | |
| Notes Payable to Banks and Commercial Paper | | | — | | | | — | |
| Current Portion of Long-Term Debt | | | 200,000 | | | | — | |
| Accounts Payable | | | 145,223 | | | | 90,723 | |
| Amounts Payable to Customers | | | 38,109 | | | | 105,778 | |
| Dividends Payable | | | 28,316 | | | | 26,967 | |
| Interest Payable on Long-Term Debt | | | 30,512 | | | | 32,031 | |
| Customer Advances | | | 27,638 | | | | 24,555 | |
| Customer Security Deposits | | | 18,320 | | | | 17,430 | |
| Other Accruals and Current Liabilities | | | 16,046 | | | | 18,875 | |
| Fair Value of Derivative Financial Instruments | | | 20,160 | | | | 2,148 | |
| | | | | | | | | |
| | | | 524,324 | | | | 318,507 | |
| | | | | | | | | |
Deferred Credits | | | | | | | | |
| Deferred Income Taxes | | | 800,758 | | | | 663,876 | |
| Taxes Refundable to Customers | | | 69,585 | | | | 67,046 | |
| Unamortized Investment Tax Credit | | | 3,288 | | | | 3,989 | |
| Cost of Removal Regulatory Liability | | | 124,032 | | | | 105,546 | |
| Other Regulatory Liabilities | | | 89,334 | | | | 120,229 | |
| Pension and Other Post-Retirement Liabilities | | | 446,082 | | | | 415,888 | |
| Asset Retirement Obligations | | | 101,618 | | | | 91,373 | |
| Other Deferred Credits | | | 151,633 | | | | 144,439 | |
| | | | | | | | | |
| | | | 1,786,330 | | | | 1,612,386 | |
| | | | | | | | | |
Commitments and Contingencies | | | — | | | | — | |
| | | | | | | | | |
Total Capitalization and Liabilities | | $ | 5,105,625 | | | $ | 4,769,129 | |
| | | | | | | | | |
See Notes to Consolidated Financial Statements
70
NATIONAL FUEL GAS COMPANY
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands of dollars) | |
| |
Operating Activities | | | | | | | | | | | | |
| Net Income Available for Common Stock | | $ | 225,913 | | | $ | 100,708 | | | $ | 268,728 | |
| Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | | | | | | | | | | | | |
| Gain on Sale of Discontinued Operations | | | (10,334 | ) | | | — | | | | — | |
| Impairment of Oil and Gas Producing Properties | | | — | | | | 182,811 | | | | — | |
| Depreciation, Depletion and Amortization | | | 191,809 | | | | 173,410 | | | | 170,623 | |
| Deferred Income Taxes | | | 134,679 | | | | (2,521 | ) | | | 72,496 | |
| Income from Unconsolidated Subsidiaries, Net of Cash Distributions | | | 112 | | | | (466 | ) | | | 1,977 | |
| Impairment of Investment in Partnership | | | — | | | | 1,804 | | | | — | |
| Excess Tax Benefits Associated with Stock-Based Compensation Awards | | | (13,207 | ) | | | (5,927 | ) | | | (16,275 | ) |
| Other | | | 9,108 | | | | 19,829 | | | | 4,858 | |
| Change in: | | | | | | | | | | | | |
| Hedging Collateral Deposits | | | (10,286 | ) | | | (847 | ) | | | 4,065 | |
| Receivables and Unbilled Utility Revenue | | | 10,262 | | | | 47,658 | | | | (16,815 | ) |
| Gas Stored Underground and Materials and Supplies | | | 6,546 | | | | 43,598 | | | | (22,116 | ) |
| Unrecovered Purchased Gas Costs | | | — | | | | 37,708 | | | | (22,939 | ) |
| Prepayments and Other Current Assets | | | (34,288 | ) | | | 2,921 | | | | (36,376 | ) |
| Accounts Payable | | | 8,047 | | | | (61,149 | ) | | | 32,763 | |
| Amounts Payable to Customers | | | (67,669 | ) | | | 103,025 | | | | (7,656 | ) |
| Customer Advances | | | 3,083 | | | | (8,462 | ) | | | 10,154 | |
| Customer Security Deposits | | | 890 | | | | 3,383 | | | | 609 | |
| Other Accruals and Current Liabilities | | | (3,649 | ) | | | 13,676 | | | | (4,250 | ) |
| Other Assets | | | 7,237 | | | | (35,140 | ) | | | (11,887 | ) |
| Other Liabilities | | | 1,442 | | | | (4,201 | ) | | | 54,817 | |
| | | | | | | | | | | | | |
Net Cash Provided by Operating Activities | | | 459,695 | | | | 611,818 | | | | 482,776 | |
| | | | | | | | | | | | | |
Investing Activities | | | | | | | | | | | | |
| Capital Expenditures | | | (455,764 | ) | | | (313,633 | ) | | | (397,734 | ) |
| Investment in Subsidiary, Net of Cash Acquired | | | — | | | | (34,933 | ) | | | — | |
| Net Proceeds from Sale of Timber Mill and Related Assets | | | 15,770 | | | | — | | | | — | |
| Net Proceeds from Sale of Landfill Gas Pipeline Assets | | | 38,000 | | | | — | | | | — | |
| Cash Held in Escrow | | | — | | | | (2,000 | ) | | | 58,397 | |
| Net Proceeds from Sale of Oil and Gas Producing Properties | | | — | | | | 3,643 | | | | 5,969 | |
| Other | | | (251 | ) | | | (2,806 | ) | | | 4,376 | |
| | | | | | | | | | | | | |
Net Cash Used in Investing Activities | | | (402,245 | ) | | | (349,729 | ) | | | (328,992 | ) |
| | | | | | | | | | | | | |
Financing Activities | | | | | | | | | | | | |
| Excess Tax Benefits Associated with Stock-Based Compensation Awards | | | 13,207 | | | | 5,927 | | | | 16,275 | |
| Shares Repurchased under Repurchase Plan | | | — | | | | — | | | | (237,006 | ) |
| Net Proceeds from Issuance of Long-Term Debt | | | — | | | | 247,780 | | | | 296,655 | |
| Reduction of Long-Term Debt | | | — | | | | (100,000 | ) | | | (200,024 | ) |
| Net Proceeds from Issuance of Common Stock | | | 26,057 | | | | 28,176 | | | | 17,432 | |
| Dividends Paid on Common Stock | | | (109,596 | ) | | | (104,158 | ) | | | (103,683 | ) |
| | | | | | | | | | | | | |
Net Cash Provided By (Used in) Financing Activities | | | (70,332 | ) | | | 77,725 | | | | (210,351 | ) |
| | | | | | | | | | | | | |
Net Increase (Decrease) in Cash and Temporary Cash Investments | | | (12,882 | ) | | | 339,814 | | | | (56,567 | ) |
Cash and Temporary Cash Investments At Beginning of Year | | | 408,053 | | | | 68,239 | | | | 124,806 | |
| | | | | | | | | | | | | |
Cash and Temporary Cash Investments At End of Year | | $ | 395,171 | | | $ | 408,053 | | | $ | 68,239 | |
| | | | | | | | | | | | | |
Supplemental Disclosure of Cash Flow Information | | | | | | | | | | | | |
Cash Paid For: | | | | | | | | | | | | |
| Interest | | $ | 93,333 | | | $ | 75,640 | | | $ | 69,841 | |
| | | | | | | | | | | | | |
| Income Taxes | | $ | 30,975 | | | $ | 40,638 | | | $ | 103,154 | |
| | | | | | | | | | | | | |
See Notes to Consolidated Financial Statements
71
NATIONAL FUEL GAS COMPANY
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands of dollars) | |
| |
| Net Income Available for Common Stock | | $ | 225,913 | | | $ | 100,708 | | | $ | 268,728 | |
| | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Before Tax: | | | | | | | | | | | | |
| Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | (30,155 | ) | | | (71,771 | ) | | | (13,584 | ) |
| Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | 5,000 | | | | 1,008 | | | | 1,924 | |
| Foreign Currency Translation Adjustment | | | 53 | | | | (33 | ) | | | 12 | |
| Unrealized Loss on Securities Available for Sale Arising During the Period | | | (2,195 | ) | | | (6,118 | ) | | | (4,856 | ) |
| Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | | | 65,366 | | | | 119,210 | | | | (31,490 | ) |
| Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income | | | (41,320 | ) | | | (114,380 | ) | | | 64,645 | |
| | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Before Tax | | | (3,251 | ) | | | (72,084 | ) | | | 16,651 | |
| | | | | | | | | | | | | |
| Income Tax Benefit Related to the Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | (11,379 | ) | | | (27,082 | ) | | | (5,127 | ) |
| Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | 1,887 | | | | 380 | | | | 726 | |
| Income Tax Benefit Related to Unrealized Loss on Securities Available for Sale Arising During the Period | | | (831 | ) | | | (2,311 | ) | | | (1,434 | ) |
| Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | | | 26,628 | | | | 48,293 | | | | (13,228 | ) |
| Reclassification Adjustment for Income Tax (Expense) Benefit on Realized (Gains) Losses on Derivative Financial Instruments In Net Income | | | (16,967 | ) | | | (46,005 | ) | | | 26,548 | |
| | | | | | | | | | | | | |
| Income Taxes — Net | | | (662 | ) | | | (26,725 | ) | | | 7,485 | |
| | | | | | | | | | | | | |
| Other Comprehensive Income (Loss) | | | (2,589 | ) | | | (45,359 | ) | | | 9,166 | |
| | | | | | | | | | | | | |
| Comprehensive Income | | $ | 223,324 | | | $ | 55,349 | | | $ | 277,894 | |
| | | | | | | | | | | | | |
See Notes to Consolidated Financial Statements
72
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note A — Summary of Significant Accounting Policies
Principles of Consolidation
The Company consolidates its majority owned entities. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.
The preparation of the consolidated financial statements in conformity with GAAP 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.
Reclassification
Certain prior year amounts have been reclassified to conform with current year presentation.
Regulation
The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note C — Regulatory Matters for further discussion.
Revenue Recognition
The Company’s Utility segment records revenue as bills are rendered, except that service supplied but not billed is reported as unbilled utility revenue and is included in operating revenues for the year in which service is furnished.
The Company’s Energy Marketing segment records revenue as bills are rendered for service supplied on a monthly basis.
The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services. Revenue from reservation charges on firm contracted capacity is recognized through equal monthly charges over the contract period regardless of the amount of gas that is transported or stored. Commodity charges on firm contracted capacity and interruptible contracts are recognized as revenue when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage field. The point of delivery into the pipeline or injection or withdrawal from storage is the point at which ownership and risk of loss transfers to the buyer of such transportation and storage services.
The Company’s Exploration and Production segment records revenue based on entitlement, which means that revenue is recorded based on the actual amount of gas or oil that is delivered to a pipeline and the Company’s ownership interest in the producing well. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance.
Allowance for Uncollectible Accounts
The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age and other specific information about customer accounts. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered.
73
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Regulatory Mechanisms
The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.
Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note C — Regulatory Matters for further discussion.
The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s revenues.
The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers’ bills. Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers’ bills. The surcharge or credit is calculated over a twelve-month period ending December 31st, and applied to customer bills annually, beginning March 1st.
In the Pipeline and Storage segment, the allowed rates that Supply Corporation bills its customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, including return on equity and income taxes, through fixed monthly reservation charges. Because of this rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation.
Prior to December 10, 2008, the allowed rates that Empire billed its customers were based on a modified fixed-variable rate design, which recovered return on equity and income taxes through variable charges. Because of this rate design, changes in throughput due to weather variations could have had a significant impact on Empire’s revenues. On December 10, 2008, Empire became FERC regulated. As a result, Empire now bills its customers based on a straight fixed-variable rate design. Changes in throughput due to weather variations no longer have a significant impact on Empire’s revenue.
Property, Plant and Equipment
The principal assets of the Utility and Pipeline and Storage segments, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service in the regulated businesses, as required by regulatory authorities.
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 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.
74
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Capitalized costs include costs related to unproved properties, which are excluded from amortization 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.
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying 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. In accordance with the SEC final rule on Modernization of Oil and Gas Reporting, the natural gas and oil prices used to calculate the full cost ceiling (as of September 30, 2010) are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2010, 2009, and 2008, estimated future net cash flows were increased by $65.4 million, $143.3 million and $34.5 million, respectively. The Company’s capitalized costs exceeded the full cost ceiling for the Company’s oil and gas properties at December 31, 2008. As such, the Company recognized a pre-tax impairment of $182.8 million at December 31, 2008 (utilizing period end pricing as required by the SEC full cost rules then in effect). Deferred income taxes of $74.6 million were recorded associated with this impairment.
Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
Depreciation, Depletion and Amortization
For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. In the All Other category, for timber properties, depletion, determined on a property by property basis, is charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. For all other property, plant and equipment, depreciation, depletion and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment:
| | | | | | | | | |
| | | As of September 30 | |
| | | 2010 | | | 2009 | |
| | | (Thousands) | |
| |
| Utility | | $ | 1,657,686 | | | $ | 1,616,908 | |
| Pipeline and Storage | | | 1,241,179 | | | | 1,196,937 | |
| Exploration and Production | | | 2,294,235 | | | | 1,972,353 | |
| Energy Marketing | | | 1,634 | | | | 1,241 | |
| All Other and Corporate | | | 127,939 | | | | 154,512 | |
| | | | | | | | | |
| | | $ | 5,322,673 | | | $ | 4,941,951 | |
| | | | | | | | | |
75
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Average depreciation, depletion and amortization rates are as follows:
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| |
| Utility | | | 2.6 | % | | | 2.6 | % | | | 2.6 | % |
| Pipeline and Storage | | | 3.0 | % | | | 3.0 | % | | | 3.2 | % |
| Exploration and Production, per Mcfe(1) | | $ | 2.14 | | | $ | 2.14 | | | $ | 2.26 | |
| Energy Marketing | | | 2.9 | % | | | 3.4 | % | | | 3.5 | % |
| All Other and Corporate | | | 6.6 | % | | | 5.2 | % | | | 4.3 | % |
| | |
| (1) | | Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note Q — Supplementary Information for Oil and Gas Producing Properties, depletion of March 12,oil and gas producing properties amounted to $2.10, $2.10 and $2.23 per Mcfe of production in 2010, 2009 and 2008, respectively. |
Goodwill
The Company has recognized goodwill of $5.5 million as of September 30, 2010, 2009 and 2008 on its Consolidated Balance Sheets related to the Company’s acquisition of Empire in 2003. The Company accounts for goodwill in accordance with the current authoritative guidance, which requires the Company to test goodwill for impairment annually. At September 30, 2010, 2009 and 2008, the fair value of Empire was greater than its book value. As such, the goodwill was not considered impaired at those dates. Going back to the origination of the goodwill in 2003, the Company has never recorded an impairment of its goodwill balance.
Financial Instruments
Unrealized gains or losses from the Company’s investments in an equity mutual fund and the stock of an insurance company (securities available for sale) are recorded as a component of accumulated other comprehensive income (loss). Reference is made to Note G — Financial Instruments for further discussion.
The Company 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 include price swap agreements and futures contracts. The Company accounts for these instruments as either cash flow hedges or fair value hedges. In both cases, the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled Fair Value of Derivative Financial Instruments. Reference is made to Note F — Fair Value Measurements for further discussion concerning the fair value of derivative financial instruments.
For effective cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues or purchased gas expense on the Consolidated Statements of Income. Any ineffectiveness associated with the cash flow hedges is recorded in the Consolidated Statements of Income. The Company did not experience any material ineffectiveness with regard to its cash flow hedges during 2010, 2009 or 2008.
For fair value hedges, the offset to the asset or liability that is recorded is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheets representing the change in fair value of the asset or firm commitment that is being hedged (see Other Current Assets section in this footnote). The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income as well. If the fair value hedge is effective, the gain or loss
3
76
| | | | | | |
Name and Year | | | | |
Became a Director | | | | |
of the Company | | Age(1) | | Principal Occupation |
| | | | | | |
Directors Whose Terms Expire in 2010NATIONAL FUEL GAS COMPANY
|
| | | | | | |
Philip C. Ackerman
1994 | | | 65 | | | Former Chief Executive Officer of the Company from October 2001 until February 21, 2008. Chairman of the Board effective January 3, 2002 to present. President of the Company from July 1999 until February 2006. Senior Vice President of the Company from June 1989 until July 1999 and Vice President from 1980 to June 1989. President of National Fuel Gas Distribution Corporation (2) from October 1995 until July 1999 and Executive Vice President from June 1989 to October 1995. Executive Vice President of National Fuel Gas Supply Corporation (2) from October 1994 to March 2002. President of Seneca Resources Corporation (2) from June 1989 to October 1996. President of Horizon Energy Development, Inc. (2) from September 1995 to March 2008 and certain other non-regulated subsidiaries of the Company since prior to 1992 to March 2008. Director of Associated Electric and Gas Insurance Services Limited. Mr. Ackerman is also the Chair of the Erie County Industrial Development Agency. |
| | | | | | |
Craig G. Matthews
2005 | | | 66 | | | Former President, CEO and Director of NUI Corporation, a diversified energy company acquired by AGL Resources Inc. on November 30, 2004, from February 2004 until December 2004. Vice Chairman, Chief Operating Officer and Director of KeySpan Corporation (previously Brooklyn Union Gas Co.) from March 2001 until March 2002. Director of Hess Corporation (formerly Amerada Hess Corporation) since 2002. Member and Former Chairman of the Board of Trustees, Polytechnic University. Board member of Republic Financial Corporation since May 2007. |
| | | | | | |
Richard G. Reiten
2004 | | | 69 | | | Chairman from September 2000 through February 2005 and also from May 2006 through May 2008 and Director from March 1996 to May 2008 of Northwest Natural Gas Company, a natural gas local distribution company headquartered in Portland, Oregon. Chief Executive Officer of Northwest Natural Gas Company from January 1997 until December 2002 and President from January 1996 through May 2001. Director of Associated Electric and Gas Insurance Services Limited since 1997. Director of US Bancorp since 1998, Building Materials Holding Corp. since 2001 and IDACORP Inc. since January 2004. Mr. Reiten also served in executive positions at Portland General Electric Company (President, 1992 to 1995) and Portland General Corporation (President, 1989 to 1992). Mr. Reiten also served 25 years in the wood products industry including in leadership positions at the DiGiorgio Corporation (President, Building Materials Group, 1974 to 1980) and the Nicolai Company (President and Chief Executive Officer, 1980 to 1987). |
| | | | | | |
David F. Smith
2007 | | | 55 | | | Chief Executive Officer of the Company since February 2008 and President of the Company since February 2006, Vice President from April 2005 until February 2006. President of National Fuel Gas Supply Corporation (2) from April 2005 to July 1, 2008, Senior Vice President from June 2000 until April 2005. President of National Fuel Gas Distribution Corporation (2) from July 1999 to April 2005, Senior Vice President from January 1993 until July 1999. Chairman of Seneca Resources Corporation (2) since April 2008. Also president of Empire State Pipeline (2) from April 2005 through July 2008, and president or chairman of various non-regulated subsidiaries of the Company. Board member of the Interstate Natural Gas Association of America (INGAA), the INGAA Foundation, American Gas Foundation and Chairman of the Northeast Gas Association. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. The Company did not experience any material ineffectiveness with regard to its fair value hedges during 2010, 2009 or 2008.
Accumulated Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) are as follows:
| | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | |
| | | (Thousands) | |
| |
| Funded Status of the Pension and Other Post-Retirement Benefit Plans | | $ | (79,465 | ) | | $ | (63,802 | ) |
| Cumulative Foreign Currency Translation Adjustment | | | (51 | ) | | | (104 | ) |
| Net Unrealized Gain on Derivative Financial Instruments | | | 32,876 | | | | 18,491 | |
| Net Unrealized Gain on Securities Available for Sale | | | 1,655 | | | | 3,019 | |
| | | | | | | | | |
| Accumulated Other Comprehensive Loss | | $ | (44,985 | ) | | $ | (42,396 | ) |
| | | | | | | | | |
At September 30, 2010, it is estimated that of the $32.9 million net unrealized gain on derivative financial instruments shown in the table above, $23.6 million of unrealized gains will be reclassified into the Consolidated Statement of Income during 2011. The remaining unrealized gains on derivative financial instruments of $9.3 million will be reclassified into the Consolidated Statement of Income in subsequent years. The Company’s derivative financial instruments extend out to 2014.
The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company’s pension and other post-retirement benefit plans consist of prior service costs and accumulated losses. The total amount for prior service costs was $0.3 million at September 30, 2010 and 2009. The total amount for accumulated losses was $79.2 million and $63.5 million at September 30, 2010 and 2009, respectively.
Gas Stored Underground — Current
In the Utility segment, gas stored underground — current in the amount of $24.9 million is carried at lower of cost or market, on a LIFO method. Based upon the average price of spot market gas purchased in September 2010, including transportation costs, the current cost of replacing this inventory of gas stored underground — current exceeded the amount stated on a LIFO basis by approximately $82.5 million at September 30, 2010. All other gas stored underground — current, which is in the Energy Marketing segment, is carried at an average cost method, subject to lower of cost or market adjustments.
Purchased Timber Cutting Rights
In September 2010, the Company sold all of its purchased timber cutting rights in connection with the sale of its sawmill in Marienville, Pennsylvania. The Company continues to maintain a forestry operation, but will no longer be processing lumber products. Prior to the sale, the Company purchased the right to harvest timber from land owned by other parties. These rights, which extended from several months to several years, were purchased to ensure an adequate supply of timber for the Company’s sawmill and kiln operations. The historical value of timber rights expected to be harvested during the following year were included in Materials and Supplies on the Consolidated Balance Sheets while the historical value of timber rights expected to be harvested beyond one
77
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
year were included in Other Assets on the Consolidated Balance Sheets. The components of the Company’s purchased timber cutting rights are as follows:
| | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | |
| | | (Thousands) | |
| |
| Materials and Supplies | | $ | — | | | $ | 6,349 | |
| Other Assets | | | — | | | | 6,343 | |
| | | | | | | | | |
| | | $ | — | | | $ | 12,692 | |
| | | | | | | | | |
Unamortized Debt Expense
Costs associated with the issuance of debt by the Company are deferred and amortized over the lives of the related debt. Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment.
Foreign Currency Translation
The functional currency for the Company’s foreign operations is the local currency of the country where the operations are located. Asset and liability accounts are translated at the rate of exchange on the balance sheet date. Revenues and expenses are translated at the average exchange rate during the period. Foreign currency translation adjustments are recorded as a component of accumulated other comprehensive income (loss). With the sale of SECI on August 31, 2007, the Company eliminated its major foreign operation. While the Company is in the process of winding up or selling certain power development projects in Europe, the investment in such projects is not significant and the Company does not expect to have any significant foreign currency translation adjustments in the future.
Income Taxes
The Company and its domestic subsidiaries file a consolidated federal income tax return. Investment tax credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction.
Consolidated Statements of Cash Flows
For purposes of the Consolidated Statements of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.
At September 30, 2010, the Company accrued $55.5 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2010 since it represented a non-cash investing activity at that date.
At September 30, 2009, the Company accrued $9.1 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $0.7 million of capital expenditures in the All Other category related to the construction of the Midstream Covington Gathering System at September 30, 2009. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represent non-cash investing activities at that date. These capital expenditures were paid during the quarter ended December 31, 2009 and have been included in the Consolidated Statement of Cash Flows for the year ended September 30, 2010.
78
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
At September 30, 2008, the Company accrued $16.8 million of capital expenditures related to the construction of the Empire Connector project. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2008 and have been included in the Consolidated Statement of Cash Flows for the year ended September 30, 2009.
Hedging Collateral Account
This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. At September 30, 2010, the Company had hedging collateral deposits of $10.1 million related to its exchange-traded futures contracts and $1.0 million related to itsover-the-counter crude oil swap agreements. At September 30, 2009, the Company had hedging collateral deposits of $0.8 million related to its exchange-traded futures contracts. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instrument liability or asset balances.
Cash Held in Escrow
On July 20, 2009, the Company’s wholly-owned subsidiary in the Exploration and Production segment, Seneca, acquired Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million in cash (including cash acquired of $4.3 million). The cash acquired at acquisition includes $2 million held in escrow at September 30, 2010 and 2009. Seneca placed this amount in escrow as part of the purchase price. Currently, the Company and Ivanhoe Energy are negotiating a final resolution to the issue of whether Ivanhoe Energy is entitled to some or all of the amount held in escrow.
On August 31, 2007, the Company received approximately $232.1 million of proceeds from the sale of SECI, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. The escrow account was a Canadian dollar denominated account. On a U.S. dollar basis, the value of this account was $62.0 million at September 30, 2007. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. To hedge against foreign currency exchange risk related to the cash being held in escrow, the Company held a forward contract to sell Canadian dollars. For presentation purposes on the Consolidated Statement of Cash Flows, for the year ended September 30, 2008, the Cash Held in Escrow line item within Investing Activities reflects the net proceeds to the Company (received on January 8, 2008) after adjusting for the impact of the foreign currency hedge.
Other Current Assets
The components of the Company’s Other Current Assets are as follows:
| | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | |
| | | (Thousands) | |
| |
| Prepayments | | $ | 13,884 | | | $ | 12,096 | |
| Prepaid Property and Other Taxes | | | 12,413 | | | | 12,059 | |
| Federal Income Taxes Receivable | | | 56,334 | | | | 23,325 | |
| State Income Taxes Receivable | | | 18,007 | | | | 13,469 | |
| Fair Values of Firm Commitments | | | 15,331 | | | | 7,525 | |
| | | | | | | | | |
| | | $ | 115,969 | | | $ | 68,474 | |
| | | | | | | | | |
79
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Customer Advances
The Company’s Utility and Energy Marketing segments have balanced billing programs whereby customers pay their estimated annual usage in equal installments over a twelve-month period. Monthly payments under the balanced billing programs are typically higher than current month usage during the summer months. During the winter months, monthly payments under the balanced billing programs are typically lower than current month usage. At September 30, 2010 and 2009, customers in the balanced billing programs had advanced excess funds of $27.6 million and $24.6 million, respectively.
Customer Security Deposits
The Company, in its Utility, Pipeline and Storage, and Energy Marketing segments, often times requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 2010 and 2009, the Company had received customer security deposits amounting to $18.3 million and $17.4 million, respectively.
Earnings Per Common Share
Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options and SARs. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these stock options and SARs as determined using the Treasury Stock Method. Stock options and SARs that are antidilutive are excluded from the calculation of diluted earnings per common share. For 2010, there were 314,910 SARs excluded as being antidilutive, and there were no stock options excluded as being antidilutive. For 2009, there were 365,000 SARs and 765,000 stock options excluded as being antidilutive. For 2008, there were 7,344 SARs excluded as being antidilutive, and there were no stock options excluded as being antidilutive.
Share Repurchases
The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is settled as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note E — Capitalization and Short-Term Borrowings for further discussion of the share repurchase program.
Stock-Based Compensation
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, SARs, restricted stock, restricted stock units, performance units or performance shares. Stock options and SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no stock option or SAR is exercisable less than one year or more than ten years after the date of each grant. Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant.
80
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments, including stock options and SARs. The Company has chosen the Black-Scholes-Merton closed form model to calculate the compensation expense associated with such share-based payments since it is easier to administer than the Binomial option-pricing model. Furthermore, since the Company does not have complex stock-based compensation awards, it does not believe that compensation expense would be materially different under either model.
The Company granted 520,500, 610,000 and 321,000 performance based SARs during the years ended September 30, 2010, 2009 and 2008, respectively. The Company did not grant any stock options or non-performance based SARs during the years ended September 30, 2010, 2009 and 2008. The accounting treatment for performance based and non-performance based SARs is the same as the accounting for stock options under the current authoritative guidance for stock-based compensation. The performance based SARs granted for the years ended September 30, 2010 and 2009 vest and become exercisable annually in one-third increments, provided that a performance condition is met. The performance condition for each fiscal year, generally stated, is an increase over the prior fiscal year of at least five percent in certain oil and natural gas production of the Exploration and Production segment. The performance based SARs granted for the year ended September 30, 2008 vest and become exercisable annually, in one-third increments, provided that a performance condition for diluted earnings per share is met for the prior fiscal year. The weighted average grant date fair value of the performance based SARs granted during 2010, 2009 and 2008 was estimated on the date of grant using the same accounting treatment that is applied for stock options, and assumes that the performance conditions specified will be achieved. If such conditions are not met or it is not considered probable that such conditions will be met, no compensation expense is recognized and any previously recognized compensation expense is reversed. During 2009, the Company reversed $0.5 million of previously recognized compensation expense associated with performance based SARs. The Company also granted 4,000, 63,000, and 25,000 restricted share awards (non-vested stock as defined by the current accounting literature) during the years ended September 30, 2010, 2009 and 2008, respectively.
Stock-based compensation expense for the years ended September 30, 2010, 2009 and 2008 was approximately $4.4 million, $2.1 million (net of the $0.5 million reversal of compensation expense discussed above), and $2.3 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statement of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2010, 2009 and 2008 was approximately $1.8 million, $0.8 million and $0.9 million, respectively. There were no capitalized stock-based compensation costs during the years ended September 30, 2010, 2009 and 2008.
Stock Options
The total intrinsic value of stock options exercised during the years ended September 30, 2010, 2009 and 2008 totaled approximately $53.6 million, $18.7 million, and $24.6 million, respectively. For 2010, 2009 and 2008, the amount of cash received by the Company from the exercise of such stock options was approximately $34.5 million, $29.2 million, and $18.5 million, respectively.
The Company realizes tax benefits related to the exercise of stock options on a calendar year basis as opposed to a fiscal year basis. As such, for stock options exercised during the quarters ended December 31, 2009, 2008, and 2007, the Company realized a tax benefit of $8.0 million, $1.6 million, and $4.4 million, respectively. For stock options exercised during the period of January 1, 2010 through September 30, 2010, the Company will realize a tax benefit of approximately $13.3 million in the quarter ended December 31, 2010. For stock options exercised during the period of January 1, 2009 through September 30, 2009, the Company realized a tax benefit of approximately $5.7 million in the quarter ended December 31, 2009. For stock options exercised during the period of January 1, 2008 through September 30, 2008, the Company realized a tax benefit of approximately $4.3 million in the quarter ended December 31, 2008. As stated above, there were no stock
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
options granted during the years ended September 30, 2010, 2009 and 2008. For the years ended September 30, 2010, 2009 and 2008, 100,000, 27,000 and 358,000 stock options became fully vested, respectively. The total fair value of the stock options that became vested during the years ended September 30, 2010, 2009 and 2008 was approximately $0.7 million, $0.2 million and $2.6 million, respectively. As of September 30, 2010, there was no unrecognized compensation expense related to stock options. For a summary of transactions during 2010 involving option shares for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
Non-Performance Based SARs
Participants in the stock option and award plans did not exercise any non-performance based SARs during the years ended September 30, 2010, 2009 and 2008. As stated above, the Company did not grant any non-performance based SARs during the years ended September 30, 2010, 2009 and 2008. For the year ended September 30, 2010, 50,000 non-performance based SARs became fully vested. Fiscal 2010 was the first year in which non-performance based SARs became vested. The total fair value of the non-performance based SARs that became vested during the year ended September 30, 2010 was approximately $0.4 million. As of September 30, 2010, there was no unrecognized compensation expense related to non-performance based SARs. For a summary of transactions during 2010 involving non-performance based SARs for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
Performance Based SARs
Participants in the stock option and award plans did not exercise any performance based SARs during the years ended September 30, 2010, 2009 and 2008. As stated above, there were 520,500, 610,000 and 321,000 performance based SARs granted during the years ended September 30, 2010, 2009 and 2008, respectively. The weighted average grant date fair value of performance based SARs granted in 2010, 2009 and 2008 is $12.06 per share, $4.09 per share and $9.06 per share, respectively. For the years ended September 30, 2010 and 2009, 203,324 and 96,984 performance based SARs became fully vested. Fiscal 2009 was the first year in which performance based SARs became vested. The total fair value of the performance based SARs that became vested during each of the years ended September 30, 2010 and 2009 was approximately $0.8 million. As of September 30, 2010, unrecognized compensation expense related to performance based SARs totaled approximately $4.0 million, which will be recognized over a weighted average period of 10.3 months. For a summary of transactions during 2010 involving performance based SARs for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
The fair value of performance based SARs at the date of grant was estimated using the Black-Scholes-Merton closed form model. The following weighted average assumptions were used in estimating the fair value of performance based SARs at the date of grant:
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| |
| Risk Free Interest Rate | | | 3.55 | % | | | 2.56 | % | | | 3.78 | % |
| Expected Life (Years) | | | 7.75 | | | | 7.50 | | | | 7.25 | |
| Expected Volatility | | | 23.25 | % | | | 22.16 | % | | | 17.69 | % |
| Expected Dividend Yield (Quarterly) | | | 0.64 | % | | | 1.09 | % | | | 0.64 | % |
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the performance based SARs. The expected life and expected volatility are based on historical experience.
For grants during the years ended September 30, 2010, 2009 and 2008, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Restricted Share Awards
The weighted average fair value of restricted share awards granted in 2010, 2009 and 2008 is $52.10 per share, $47.46 per share and $48.41 per share, respectively. As of September 30, 2010, unrecognized compensation expense related to restricted share awards totaled approximately $3.4 million, which will be recognized over a weighted average period of 4.0 years. For a summary of transactions during 2010 involving restricted share awards, refer to Note E — Capitalization and Short-Term Borrowings.
New Authoritative Accounting and Financial Reporting Guidance
In September 2006, the FASB issued authoritative guidance for using fair value to measure assets and liabilities. This guidance serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. This guidance is to be applied whenever assets or liabilities are to be measured at fair value. On October 1, 2008, the Company adopted this guidance for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis. The FASB’s authoritative guidance for using fair value to measure nonfinancial assets and nonfinancial liabilities on a nonrecurring basis became effective during the quarter ended December 31, 2009. The Company’s nonfinancial assets and nonfinancial liabilities were not significantly impacted by this guidance during the year ended September 30, 2010. The Company had identified Goodwill as being the major nonfinancial asset that may have been impacted by the adoption of this guidance; however, the adoption of the guidance did not have a significant impact on the Company’s annual test for goodwill impairment. The Company had identified Asset Retirement Obligations as a nonfinancial liability that may have been impacted by the adoption of the guidance. The adoption of the guidance did not have a significant impact on the Company’s Asset Retirement Obligations. Refer to Note B — Asset Retirement Obligations for further disclosure. Additionally, in February 2010, the FASB issued updated guidance that includes additional requirements and disclosures regarding fair value measurements. The guidance now requires the gross presentation of activity within the Level 3 roll forward and requires disclosure of details on transfers in and out of Level 1 and 2 fair value measurements. It also provides further clarification on the level of disaggregation of fair value measurements and disclosures on inputs and valuation techniques. The Company has updated its disclosures to reflect the new requirements in Note F — Fair Value Measurements, except for the Level 3 roll forward gross presentation, which will be effective as of the Company’s first quarter of fiscal 2012.
On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting. The final rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves and aligns the full cost accounting rules with the revised disclosures. The most notable changes of the final rule include the replacement of the single day period-end pricing used to value oil and gas reserves with an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. Additionally, on January 6, 2010, the FASB amended the oil and gas accounting standards to conform to the SEC final rule on Modernization of Oil and Gas Reporting (final rule). The revised reporting and disclosure requirements became effective with thisForm 10-K for the period ended September 30, 2010. The Company has updated its disclosures to reflect the new requirements in Note Q — Supplementary Information for Oil and Gas Producing Activities. The Company chose not to disclose probable and possible reserves. In order to estimate the effect of adopting the final rule, the Company would be required to prepare two sets of reserve reports (applying both the final rule and previous rules). There would be significant time and expense associated with preparing two sets of reports to address changes between the different rules. Since the information obtained from the dual reserve reports would be relevant only for transitional purposes, the cost is deemed to exceed the benefit. As a result, the Company has determined it would be impractical to estimate the impact of adoption of the final rule.
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In March 2009, the FASB issued authoritative guidance that expands the disclosures required in an employer’s financial statements about pension and other post-retirement benefit plan assets. The additional disclosures include more details on how investment allocation decisions are made, the plan’s investment policies and strategies, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period, and disclosure regarding significant concentrations of risk within plan assets. The additional disclosure requirements became effective with thisForm 10-K for the period ended September 30, 2010. The Company has updated its disclosures to reflect the new requirements in Note H — Retirement Plan and Other Post-Retirement Benefits.
In June 2009, the FASB issued amended authoritative guidance to improve and clarify financial reporting requirements by companies involved with variable interest entities. The new guidance requires a company to perform an analysis to determine whether the company’s variable interest or interests give it a controlling financial interest in a variable interest entity. The analysis also assists in identifying the primary beneficiary of a variable interest entity. This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2011. Given the current organizational structure of the Company, the Company does not believe this authoritative guidance will have any impact on its consolidated financial statements.
Note B — Asset Retirement Obligations
The Company accounts for asset retirement obligations in accordance with the authoritative guidance that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. An asset retirement obligation is defined as a legal obligation associated with the retirement of a tangible long-lived asset in which the timingand/or method of settlement may or may not be conditional on a future event that may or may not be within the control of the Company. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The Company estimates the fair value of its asset retirement obligations based on the discounting of expected cash flows using various estimates, assumptions and judgments regarding certain factors such as the existence of a legal obligation for an asset retirement obligation; estimated amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements as the inputs used to measure the fair value are unobservable.
As previously disclosed, the Company follows the full cost method of accounting for its exploration and production costs. In accordance with the current authoritative guidance for asset retirement obligations, the Company has 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 has capitalized such costs in property, plant and equipment (i.e. the full cost pool). Under the current authoritative guidance for asset retirement obligations, since plugging and abandonment costs are already included in the full cost pool, theunits-of-production depletion calculation excludes from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.
The full cost method of accounting provides a limit to the amount of costs that can be capitalized in the full cost pool. This limit is referred to as the full cost ceiling. In accordance with current authoritative guidance, since the full cost pool includes an amount associated with plugging and abandoning the wells, as discussed in the preceding paragraph, the calculation of the full cost ceiling no longer reduces the future net cash flows from proved oil and gas reserves by an estimate of plugging and abandonment costs.
In addition to the asset retirement obligation recorded in the Exploration and Production segment, the Company has recorded future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
various facilities in the Utility and Pipeline and Storage segments. The Company has also recorded asset retirement obligations for certain costs connected with the retirement of the distribution mains and services components of the pipeline system in the Utility segment and with the transmission mains and other components in the pipeline system in the Pipeline and Storage segment. These retirement costs within the distribution and transmission systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for theclean-up of PCB contamination associated with the removal of certain pipe.
A reconciliation of the Company’s asset retirement obligation is shown below:
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | | | | (Thousands) | | | | |
| |
| Balance at Beginning of Year | | $ | 91,373 | | | $ | 93,247 | | | $ | 75,939 | |
| Liabilities Incurred and Revisions of Estimates | | | 16,140 | | | | 4,492 | | | | 18,739 | |
| Liabilities Settled | | | (12,622 | ) | | | (13,155 | ) | | | (6,871 | ) |
| Accretion Expense | | | 6,727 | | | | 6,789 | | | | 5,440 | |
| | | | | | | | | | | | | |
| Balance at End of Year | | $ | 101,618 | | | $ | 91,373 | | | $ | 93,247 | |
| | | | | | | | | | | | | |
Note C — Regulatory Matters
Regulatory Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
| | | | | | | | | |
| | | At September 30 | |
| | | 2010 | | | 2009 | |
| | | (Thousands) | |
| |
Regulatory Assets(1): | | | | | | | | |
| Pension Costs(2) (Note H) | | $ | 308,822 | | | $ | 262,370 | |
| Post-Retirement Benefit Costs(2) (Note H) | | | 159,498 | | | | 198,982 | |
| Recoverable Future Taxes (Note D) | | | 149,712 | | | | 138,435 | |
| Environmental Site Remediation Costs(2) (Note I) | | | 20,491 | | | | 21,456 | |
| NYPSC Assessment(2) | | | 19,229 | | | | 24,445 | |
| Asset Retirement Obligations(2) (Note B) | | | 12,529 | | | | 7,884 | |
| Unamortized Debt Expense (Note A) | | | 5,727 | | | | 6,610 | |
| Other(2) | | | 22,232 | | | | 15,776 | |
| | | | | | | | | |
| Total Regulatory Assets | | | 698,240 | | | | 675,958 | |
| | | | | | | | | |
Regulatory Liabilities: | | | | | | | | |
| Cost of Removal Regulatory Liability | | | 124,032 | | | | 105,546 | |
| Taxes Refundable to Customers (Note D) | | | 69,585 | | | | 67,046 | |
| Post-Retirement Benefit Costs(3) (Note H) | | | 42,461 | | | | 45,594 | |
| Amounts Payable to Customers (See Regulatory Mechanisms in Note A) | | | 38,109 | | | | 105,778 | |
| Pension Costs(3) (Note H) | | | 16,171 | | | | 15,409 | |
| Off-System Sales and Capacity Release Credits(3) | | | 11,594 | | | | 8,340 | |
| Tax Benefit on Medicare Part D Subsidy(3) | | | 4,842 | | | | 28,817 | |
| Deferred Insurance Proceeds(3) | | | 2,445 | | | | 3,804 | |
| Other(3) | | | 11,821 | | | | 18,265 | |
| | | | | | | | | |
| Total Regulatory Liabilities | | | 321,060 | | | | 398,599 | |
| | | | | | | | | |
| Net Regulatory Position | | $ | 377,180 | | | $ | 277,359 | |
| | | | | | | | | |
85
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | |
| (1) | | AsThe Company recovers the cost of March 12, 2009its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates. |
| |
| (2) | | Wholly-owned subsidiary ofIncluded in Other Regulatory Assets on the Company.Consolidated Balance Sheets. |
|
| (3) | | Included in Other Regulatory Liabilities on the Consolidated Balance Sheets. |
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 Consolidated Balance Sheets and included in income of the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item.
Cost of Removal Regulatory Liability
In the Company’s Utility and Pipeline and Storage segments, costs of removing assets (i.e. asset retirement costs) are collected from customers through depreciation expense. These amounts are not a legal retirement obligation as discussed in Note B — Asset Retirement Obligations. Rather, they are classified as a regulatory liability in recognition of the fact that the Company has collected dollars from the customer that will be used in the future to fund asset retirement costs.
Tax Benefit on Medicare Part D Subsidy
The Company has established a regulatory liability for the tax benefit it will receive under the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) amounting to $4.8 million and $28.8 million at September 30, 2010 and 2009, respectively. The Act provides a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Company reduced its deferred tax asset relating to the Medicare Part D subsidy by $27.5 million to reflect changes made by the fundamental health care reform legislation enacted on March 23, 2010. In conjunction with the reduction of the deferred tax asset, the Company reduced its Medicare Part D regulatory liability by $27.5 million. In the Company’s Utility and Pipeline and Storage segments, the Company’s post-retirement benefit plans are funded by a component of tariff rates charged to customers. As such, prior to the fundamental health care reform legislation, the $27.5 million tax benefit had been recorded as a regulatory liability in anticipation of flowing that tax benefit back to customers through adjusted tariff rates. Refer to Note H — Retirement Plan and Other Post-Retirement Benefits for further discussion of the Act and its impact on the Company.
Deferred Insurance Proceeds
The Company, in its Pipeline and Storage segment, has deferred environmental insurance settlement proceeds amounting to $2.4 million and $3.8 million at September 30, 2010 and 2009, respectively. Such proceeds have been deferred as a regulatory liability to be applied against any future environmental claims that may be incurred. The proceeds have been classified as a regulatory liability in recognition of the fact that customers funded the premiums on the former insurance policies.
NYPSC Assessment
On April 7, 2009, the Governor of the State of New York signed into law an amendment to the Public Service Law increasing the allowed utility assessment from the then current rate of one-third of one percent to one percent of a utility’s in-state gross operating revenue, together with a temporary surcharge (expiring March 31, 2014) equal, as applied, to an additional one percent of the utility’s in-state gross operating revenue.
4
86
| | | | | | |
Name and Year | | | | |
Became a Director | | | | |
of the Company | | Age(1) | | Principal Occupation |
| | | | | | |
Directors Whose Terms Expire in 2011NATIONAL FUEL GAS COMPANY
|
| | | | | | |
Robert T. Brady
1995 | | | 68 | | | Chairman of Moog Inc. since February 1996. Moog is a worldwide designer, manufacturer and integrator of precision control components and systems. President and Chief Executive Officer of Moog Inc. since 1988 and Board member since 1984. Director of Astronics Corporation, M&T Bank Corporation and Seneca Foods Corporation. Also, named to the UB Council in January of 2008. Chairs the regular executive sessions of non-management directors, and is the designated contact for stockholders and other interested parties to communicate with the non-management directors on the Board. |
| | | | | | |
Rolland E. Kidder
2002 | | | 68 | | | Executive Director of the Robert H. Jackson Center, Inc., in Jamestown, New York, from 2002 until 2006. Founder of Kidder Exploration, Inc., an independent Appalachian oil and gas company; Chairman and President from 1984 to 1994. Mr. Kidder is also a former Director of the Independent Oil and Gas Association of New York and the Pennsylvania Natural Gas Associates — both Appalachian-based energy associations. An elected member of the New York State Assembly from 1975 to 1982. Former Trustee of the New York Power Authority. On the Dean’s Advisory Council of the University at Buffalo School of Law from 1996 to 2001. Vice President and investment advisor for P.B. Sullivan & Co., Inc. from 1994 until 2001. |
| | | | | | |
Frederic V. Salerno
2008 | | | 65 | | | Mr. Salerno has since 2006 served as a Senior Advisor to New Mountain Capital, L.L.C. Mr. Salerno retired as Vice Chairman and CFO of Verizon, Inc. in September 2002 after more than 37 years in the telecommunications industry. Prior to the Bell Atlantic/GTE merger, which created Verizon, Mr. Salerno was Senior Vice Chairman and CFO of Bell Atlantic. Mr. Salerno joined New York Telephone in 1965. In 1983 Mr. Salerno became Vice President and in 1987, he was appointed President and CEO. Mr. Salerno serves as trustee of the Inner City Scholarship Fund and the Partnership for Quality Education. In 1990 Mr. Salerno was appointed Chairman of the Board of trustees of the State University of New York, a position he held until 1996. Mr. Salerno currently is a director of Akamai Technologies, Inc., Intercontinental Exchange, Inc., Popular, Inc., Viacom, Inc., and CBS Corp. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The NYPSC, in a generic proceeding initiated for the purpose of implementing the amended law, has authorized the recovery, through rates, of the full cost of the increased assessment. The assessment is currently being applied to customer bills in the Utility segment’s New York jurisdiction.
Off-System Sales and Capacity Release Credits
The Company, in its Utility segment, has entered into off-system sales and capacity release transactions. Most of the margins on such transactions are returned to the customer with only a small percentage being retained by the Company. The amount owed to the customer has been deferred as a regulatory liability.
Note D — Income Taxes
The components of federal, state and foreign income taxes included in the Consolidated Statements of Income are as follows:
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
| Current Income Taxes — | | | | | | | | | | | | |
| Federal | | $ | 2,074 | | | $ | 43,300 | | | $ | 75,169 | |
| State | | | 4,991 | | | | 10,341 | | | | 20,257 | |
| Deferred Income Taxes — | | | | | | | | | | | | |
| Federal | | | 110,515 | | | | (4,940 | ) | | | 56,668 | |
| State | | | 24,164 | | | | 2,419 | | | | 15,828 | |
| | | | | | | | | | | | | |
| | | | 141,744 | | | | 51,120 | | | | 167,922 | |
| Deferred Investment Tax Credit | | | (697 | ) | | | (697 | ) | | | (697 | ) |
| | | | | | | | | | | | | |
| Total Income Taxes | | $ | 141,047 | | | $ | 50,423 | | | $ | 167,225 | |
| | | | | | | | | | | | | |
| Presented as Follows: | | | | | | | | | | | | |
| Other Income | | $ | (697 | ) | | $ | (697 | ) | | $ | (697 | ) |
| Income Tax Expense — Continuing Operations | | | 137,227 | | | | 52,859 | | | | 167,672 | |
| Discontinued Operations — | | | | | | | | | | | | |
| Income From Operations | | | 493 | | | | (1,739 | ) | | | 250 | |
| Gain on Disposal | | | 4,024 | | | | — | | | | — | |
| | | | | | | | | | | | | |
| Total Income Taxes | | $ | 141,047 | | | $ | 50,423 | | | $ | 167,225 | |
| | | | | | | | | | | | | |
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
| U.S. Income Before Income Taxes | | $ | 366,960 | | | $ | 151,131 | | | $ | 435,953 | |
| | | | | | | | | | | | | |
| Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% | | $ | 128,436 | | | $ | 52,896 | | | $ | 152,584 | |
| Increase (Reduction) in Taxes Resulting from: | | | | | | | | | | | | |
| State Income Taxes | | | 18,951 | | | | 8,294 | | | | 23,455 | |
| Miscellaneous | | | (6,340 | ) | | | (10,767 | ) | | | (8,814 | ) |
| | | | | | | | | | | | | |
| Total Income Taxes | | $ | 141,047 | | | $ | 50,423 | | | $ | 167,225 | |
| | | | | | | | | | | | | |
87
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Significant components of the Company’s deferred tax liabilities and assets are as follows:
| | | | | | | | | |
| | | At September 30 | |
| | | 2010 | | | 2009 | |
| | | (Thousands) | |
| |
| Deferred Tax Liabilities: | | | | | | | | |
| Property, Plant and Equipment | | $ | 849,869 | | | $ | 733,581 | |
| Pension and Other Post-Retirement Benefit Costs | | | 177,853 | | | | 178,440 | |
| Other | | | 63,671 | | | | 54,977 | |
| | | | | | | | | |
| Total Deferred Tax Liabilities | | | 1,091,393 | | | | 966,998 | |
| | | | | | | | | |
| Deferred Tax Assets: | | | | | | | | |
| Pension and Other Post-Retirement Benefit Costs | | | (223,588 | ) | | | (212,299 | ) |
| Other | | | (91,523 | ) | | | (144,686 | ) |
| | | | | | | | | |
| Total Deferred Tax Assets | | | (315,111 | ) | | | (356,985 | ) |
| | | | | | | | | |
| Total Net Deferred Income Taxes | | $ | 776,282 | | | $ | 610,013 | |
| | | | | | | | | |
| Presented as Follows: | | | | | | | | |
| Net Deferred Tax Liability/(Asset) — Current | | $ | (24,476 | ) | | $ | (53,863 | ) |
| Net Deferred Tax Liability — Non-Current | | | 800,758 | | | | 663,876 | |
| | | | | | | | | |
| Total Net Deferred Income Taxes | | $ | 776,282 | | | $ | 610,013 | |
| | | | | | | | | |
Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $69.6 million and $67.0 million at September 30, 2010 and 2009, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $149.7 million and $138.4 million at September 30, 2010 and 2009, respectively. Included in the above are regulatory liabilities and assets relating to the tax accounting method change noted below. The amounts are as follows: regulatory liabilities of $47.3 million as of September 30, 2010 and 2009, and regulatory assets of $56.3 million and $51.1 million as of September 30, 2010 and 2009, respectively.
The Company reduced its deferred tax asset relating to the Medicare Part D subsidy by $27.5 million to reflect changes made by the fundamental health care reform legislation enacted on March 23, 2010. In conjunction with the reduction of the deferred tax asset, the Company reduced its Medicare Part D regulatory liability by $27.5 million. In the Company’s Utility and Pipeline and Storage segments, the Company’s post-retirement benefit plans are funded by a component of tariff rates charged to customers. As such, prior to the fundamental health care reform legislation, the $27.5 million tax benefit had been recorded as a regulatory liability in anticipation of flowing that tax benefit back to customers through adjusted tariff rates.
The Company adopted the FASB authoritative guidance for income tax uncertainties on October 1, 2007. As of the date of adoption, a cumulative effect adjustment was recorded that resulted in a decrease to retained earnings of $0.4 million. Upon adoption, the unrecognized tax benefits were $1.7 million.
88
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following is a reconciliation of the change in unrecognized tax benefits:
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
| Balance at Beginning of Year | | $ | 8,721 | | | $ | 1,700 | | | $ | 1,700 | |
| Additions for Tax Positions Related to Current Year | | | 699 | | | | 8,721 | | | | — | |
| Additions for Tax Positions of Prior Years | | | 45 | | | | — | | | | — | |
| Reductions for Tax Positions of Prior Years | | | (975 | ) | | | — | | | | — | |
| Settlements with Taxing Authorities | | | — | | | | (1,700 | ) | | | — | |
| Lapse of Statute of Limitations | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
| Balance at End of Year | | $ | 8,490 | | | $ | 8,721 | | | $ | 1,700 | |
| | | | | | | | | | | | | |
If the amount of unrecognized tax benefits recorded as of September 30, 2010 were recognized, there would not be a material impact on the effective tax rate. The Company anticipates that the unrecognized tax benefits will not significantly change within the next twelve months.
The Company recognizes interest relating to income taxes in Other Interest Expense and penalties relating to income taxes in Other Income. The Company recognized interest expense relating to income taxes of $0.2 million, $0.0 million and $0.5 million for fiscal 2010, 2009 and 2008, respectively. The Company has not accrued any penalties during fiscal 2010, 2009 and 2008.
The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting an examination of the Company for fiscal 2009 and fiscal 2010 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. While the federal statute of limitations remains open for fiscal 2007 and later years, IRS examinations for fiscal 2008 and prior years have been completed and the Company believes such years are effectively settled. During fiscal 2009, consent was received from the IRS National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property. During this year, local IRS examiners proposed to disallow most of the accounting method change. The Company has filed a protest with the IRS Appeals Office disputing the local IRS findings.
The Company is also subject to various routine state income tax examinations. The Company’s operating subsidiaries mainly operate in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.
As of September 30, 2010, the Company has a federal net operating loss carryover of $19.7 million, which expires in varying amounts between 2023 and 2029. Although this loss carryover is subject to certain annual limitations, no valuation allowance was recorded because of management’s determination that the amount will be fully utilized during the carryforward period.
89
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note E — Capitalization and Short-Term Borrowings
Summary of Changes in Common Stock Equity
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Earnings
| | | Accumulated
| |
| | | | | | | | | | | | Reinvested
| | | Other
| |
| | | | | | | | | Paid
| | | in
| | | Comprehensive
| |
| | | Common Stock | | | In
| | | the
| | | Income
| |
| | | Shares | | | Amount | | | Capital | | | Business | | | (Loss) | |
| | | (Thousands, except per share amounts) | |
| |
| Balance at September 30, 2007 | | | 83,461 | | | $ | 83,461 | | | $ | 569,085 | | | $ | 983,776 | | | $ | (6,203 | ) |
| Net Income Available for Common Stock | | | | | | | | | | | | | | | 268,728 | | | | | |
| Dividends Declared on Common Stock ($1.27 Per Share) | | | | | | | | | | | | | | | (103,523 | ) | | | | |
| Cumulative Effect of the Adoption of Authoritative Guidance for Income Taxes | | | | | | | | | | | | | | | (406 | ) | | | | |
| Other Comprehensive Income, Net of Tax | | | | | | | | | | | | | | | | | | | 9,166 | |
| Share-Based Payment Expense(2) | | | | | | | | | | | 2,332 | | | | | | | | | |
| Common Stock Issued Under Stock and Benefit Plans(1) | | | 854 | | | | 854 | | | | 33,335 | | | | | | | | | |
| Share Repurchases | | | (5,194 | ) | | | (5,194 | ) | | | (37,036 | ) | | | (194,776 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at September 30, 2008 | | | 79,121 | | | | 79,121 | | | | 567,716 | | | | 953,799 | | | | 2,963 | |
| | | | | | | | | | | | | | | | | | | | | |
| Net Income Available for Common Stock | | | | | | | | | | | | | | | 100,708 | | | | | |
| Dividends Declared on Common Stock ($1.32 Per Share) | | | | | | | | | | | | | | | (105,410 | ) | | | | |
| Adoption of Authoritative Guidance for Defined Benefit Pension and Other Post-Retirement Plans | | | | | | | | | | | | | | | (804 | ) | | | | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | | | | | | | | | | | (45,359 | ) |
| Share-Based Payment Expense(2) | | | | | | | | | | | 2,055 | | | | | | | | | |
| Common Stock Issued Under Stock and Benefit Plans(1) | | | 1,379 | | | | 1,379 | | | | 33,068 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at September 30, 2009 | | | 80,500 | | | | 80,500 | | | | 602,839 | | | | 948,293 | | | | (42,396 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net Income Available for Common Stock | | | | | | | | | | | | | | | 225,913 | | | | | |
| Dividends Declared on Common Stock ($1.36 Per Share) | | | | | | | | | | | | | | | (110,944 | ) | | | | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | | | | | | | | | | | (2,589 | ) |
| Share-Based Payment Expense(2) | | | | | | | | | | | 4,435 | | | | | | | | | |
| Common Stock Issued Under Stock and Benefit Plans(1) | | | 1,575 | | | | 1,575 | | | | 38,345 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at September 30, 2010 | | | 82,075 | | | $ | 82,075 | | | $ | 645,619 | | | $ | 1,063,262 | (3) | | $ | (44,985 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | AsPaid in Capital includes tax benefits of $13.2 million, $5.9 million and $16.3 million for September 30, 2010, 2009 and 2008, respectively, associated with the exercise of stock options. |
|
| (2) | | Paid in Capital includes compensation costs associated with stock option, SARs and/or restricted stock awards. The expense is included within Net Income Available For Common Stock, net of tax benefits. |
90
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | |
| (3) | | The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2010, $919.1 million of accumulated earnings was free of such limitations. |
Common Stock
The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives. Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent agent.
During 2010, the Company issued 1,975,853 original issue shares of common stock as a result of stock option exercises and 4,000 original issue shares for restricted stock awards (non-vested stock as defined by the current accounting literature for stock-based compensation). Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise pricesand/or applicable withholding taxes. During 2010, 417,987 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
The Company also has a director stock program under which it issues shares of Company common stock to the non-employee directors of the Company who receive compensation under the Company’s Retainer Policy for Non-Employee Directors, as partial consideration for the directors’ services during the fiscal year. Under this program, the Company issued 13,689 original issue shares of common stock during 2010.
In December 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of eight million shares in the open market or through privately negotiated transactions. The Company completed the repurchase of the eight million shares during 2008 for a total program cost of $324.2 million (of which 4,165,122 shares were repurchased during the year ended September 30, 2008 for $191.0 million). In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares. Under this new authorization, the Company repurchased 1,028,981 shares for $46.0 million through September 17, 2008. The Company, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. Since that time, the Company has increased its emphasis on Marcellus Shale development and pipeline expansion. As such, the Company does not anticipate repurchasing any shares in the near future. The share repurchases mentioned above were funded with cash provided by operating activitiesand/or through the use of the Company’s lines of credit.
Shareholder Rights Plan
In 1996, the Company’s Board of Directors adopted a shareholder rights plan (Plan). The Plan has been amended several times since it was adopted and is now embodied in an Amended and Restated Rights Agreement effective December 4, 2008, a copy of which was included as an exhibit to theForm 8-K filed by the Company on December 4, 2008.
Pursuant to the Plan, the holders of the Company’s common stock have one right (Right) for each of their shares. Each Right is initially evidenced by the Company’s common stock certificates representing the outstanding shares of common stock.
91
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Rights have anti-takeover effects because they will cause substantial dilution of the Company’s common stock if a person attempts to acquire the Company on terms not approved by the Board of Directors (an Acquiring Person).
The Rights become exercisable upon the occurrence of a Distribution Date as described below, but after a Distribution Date Rights that are owned by an Acquiring Person will be null and void. At any time following a Distribution Date, each holder of a Right may exercise its right to receive, upon payment of an amount calculated under the Rights Agreement, common stock of the Company (or, under certain circumstances, other securities or assets of the Company) having a value equal to two times the amount paid to exercise the Right. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.
A Distribution Date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company’s common stock or other voting stock (including Synthetic Long Positions as defined in the Plan) having 10% or more of the total voting power of the Company’s common stock and other voting stock and (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that person acquiring, or obtaining the right to acquire, beneficial ownership of the Company’s common stock or other voting stock having 10% or more of the total voting power of the Company’s common stock and other voting stock.
In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company’s stock as described above, each holder of a Right will have the right to exercise its Rights to receive, upon exercise of the right, common stock of the acquiring company having a value equal to two times the amount paid to exercise the right. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company’s assets or earning power are sold or transferred.
At any time prior to the end of the business day on the tenth day following the Distribution Date, the Company may redeem the Rights in whole, but not in part, at a price of $0.005 per Right, payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Company’s full Board of Directors. Also, at any time following the Distribution Date, 75% of the Company’s full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments.
Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expire on July 31, 2018, unless earlier than that date, they are exchanged or redeemed or the Plan is amended to extend the expiration date.
Stock Option and Stock Award Plans
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, SARs, restricted stock, performance units or performance shares. Stock options and SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option or SAR is exercisable less than one year or more than ten years after the date of each grant.
92
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Transactions involving option shares for all plans are summarized as follows:
| | | | | | | | | | | | | | | | | |
| | | | | | | | | Weighted
| | | | |
| | | | | | | | | Average
| | | | |
| | | Number of
| | | | | | Remaining
| | | Aggregate
| |
| | | Shares Subject
| | | Weighted Average
| | | Contractual
| | | Intrinsic
| |
| | | to Option | | | Exercise Price | | | Life (Years) | | | Value | |
| | | | | | | | | | | | (In thousands) | |
| |
| Outstanding at September 30, 2009 | | | 4,855,100 | | | $ | 27.18 | | | | | | | | | |
| Granted in 2010 | | | — | | | $ | — | | | | | | | | | |
| Exercised in 2010 | | | (1,975,853 | ) | | $ | 24.08 | | | | | | | | | |
| Forfeited in 2010 | | | — | | | $ | — | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Outstanding at September 30, 2010 | | | 2,879,247 | | | $ | 29.30 | | | | 2.80 | | | $ | 64,813 | |
| | | | | | | | | | | | | | | | | |
| Option shares exercisable at September 30, 2010 | | | 2,879,247 | | | $ | 29.30 | | | | 2.80 | | | $ | 64,813 | |
| | | | | | | | | | | | | | | | | |
| Option shares available for future grant at September 30, 2010(1) | | | 2,645,304 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | |
| (1) | | Includes shares available for SARs and restricted stock grants. |
Transactions involving non-performance based SARs for all plans are summarized as follows:
| | | | | | | | | | | | | | | | | |
| | | | | | | | | Weighted
| | | | |
| | | | | | | | | Average
| | | | |
| | | Number of
| | | | | | Remaining
| | | Aggregate
| |
| | | Shares Subject
| | | Weighted Average
| | | Contractual
| | | Intrinsic
| |
| | | To Option | | | Exercise Price | | | Life (Years) | | | Value | |
| | | | | | | | | | | | (In thousands) | |
| |
| Outstanding at September 30, 2009 | | | 50,000 | | | $ | 41.20 | | | | | | | | | |
| Granted in 2010 | | | — | | | $ | — | | | | | | | | | |
| Exercised in 2010 | | | — | | | $ | — | | | | | | | | | |
| Forfeited in 2010 | | | — | | | $ | — | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Outstanding at September 30, 2010 | | | 50,000 | | | $ | 41.20 | | | | 6.45 | | | $ | 531 | |
| | | | | | | | | | | | | | | | | |
| SARs exercisable at September 30, 2010 | | | 50,000 | | | $ | 41.20 | | | | 6.45 | | | $ | 531 | |
| | | | | | | | | | | | | | | | | |
93
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Transactions involving performance based SARs for all plans are summarized as follows:
| | | | | | | | | | | | | | | | | |
| | | | | | | | | Weighted
| | | | |
| | | | | | | | | Average
| | | | |
| | | Number of
| | | | | | Remaining
| | | Aggregate
| |
| | | Shares Subject
| | | Weighted Average
| | | Contractual
| | | Intrinsic
| |
| | | To Option | | | Exercise Price | | | Life (Years) | | | Value | |
| | | | | | | | | | | | (In thousands) | |
| |
| Outstanding at September 30, 2009 | | | 925,000 | | | $ | 36.14 | | | | | | | | | |
| Granted in 2010 | | | 520,500 | | | $ | 52.10 | | | | | | | | | |
| Exercised in 2010 | | | — | | | $ | — | | | | | | | | | |
| Forfeited in 2010 | | | — | | | $ | — | | | | | | | | | |
| Canceled in 2010(1) | | | (97,007 | ) | | $ | 47.37 | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Outstanding at September 30, 2010 | | | 1,348,493 | | | $ | 41.49 | | | | 8.57 | | | $ | 13,915 | |
| | | | | | | | | | | | | | | | | |
| SARs exercisable at September 30, 2010 | | | 300,308 | | | $ | 35.53 | | | | 7.96 | | | $ | 4,890 | |
| | | | | | | | | | | | | | | | | |
| | |
| (1) | | Shares were canceled during 2010 due to performance condition not being met. |
Restricted Share Awards
Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the vesting period. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective.
Transactions involving restricted shares for all plans are summarized as follows:
| | | | | | | | | |
| | | Number of
| | | Weighted Average
| |
| | | Restricted
| | | Fair Value per
| |
| | | Share Awards | | | Award | |
| |
| Restricted Share Awards Outstanding at September 30, 2009 | | | 118,000 | | | $ | 45.58 | |
| Granted in 2010 | | | 4,000 | | | $ | 52.10 | |
| Vested in 2010 | | | (27,500 | ) | | $ | 39.70 | |
| Forfeited in 2010 | | | — | | | $ | — | |
| | | | | | | | | |
| Restricted Share Awards Outstanding at September 30, 2010 | | | 94,500 | | | $ | 47.57 | |
| | | | | | | | | |
Vesting restrictions for the outstanding shares of non-vested restricted stock at September 30, 2010 will lapse as follows: 2011 — 2,500 shares; 2012 — 5,000 shares; 2013 — 5,000 shares; 2014 — 5,000 shares; 2015 — 17,000 shares; 2016 — 5,000 shares; 2018 — 35,000 shares; and 2021 — 20,000 shares.
Redeemable Preferred Stock
As of September 30, 2010, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.
94
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Long-Term Debt
The outstanding long-term debt is as follows:
| | | | | | | | | |
| | | At September 30 | |
| | | 2010 | | | 2009 | |
| | | (Thousands) | |
| |
| Medium-Term Notes(1): | | | | | | | | |
| 6.7% to 7.50% due November 2010 to June 2025 | | $ | 449,000 | | | $ | 449,000 | |
| Notes(1): | | | | | | | | |
| 5.25% to 8.75% due March 2013 to May 2019 | | | 800,000 | | | | 800,000 | |
| | | | | | | | | |
| Total Long-Term Debt | | | 1,249,000 | | | | 1,249,000 | |
| Less Current Portion(2) | | | 200,000 | | | | — | |
| | | | | | | | | |
| | | $ | 1,049,000 | | | $ | 1,249,000 | |
| | | | | | | | | |
| | |
| (1) | | The Medium-Term Notes and Notes are unsecured. |
|
| (2) | | Current Portion of Long-Term Debt at September 30, 2010 consists of $200 million of 7.50% medium-term notes that mature in November 2010. |
In April 2009, the Company issued $250.0 million of 8.75% notes due in May 2019. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $247.8 million. These notes were registered under the Securities Act of 1933. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including to replenish cash that was used to pay the $100 million due at the maturity of the Company’s 6.0% medium-term notes on March 1, 2009.
The Company has $300.0 million of 6.50% notes that mature in April 2018. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.
As of September 30, 2010, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $200.0 million in 2011, $150.0 million in 2012, $250.0 million in 2013, zero in 2014, zero in 2015 and $649.0 million thereafter.
Short-Term Borrowings
The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. As for the former, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines, which aggregate to $405.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed, or substantially replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million, which commitment extends through September 30, 2013.
At September 30, 2010 and 2009, the Company did not have any outstanding short-term notes payable to banks or commercial paper.
95
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Debt Restrictions
Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through September 30, 2013. At September 30, 2010, the Company’s debt to capitalization ratio (as calculated under the facility) was .42. The constraints specified in the committed credit facility would permit an additional $1.99 billion in short-termand/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio would exceed .65. If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its committed credit facility, uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.
Under the Company’s existing indenture covenants, at September 30, 2010, the Company would have been permitted to issue up to a maximum of $1.3 billion in additional long-term unsecured indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands. However, if the Company were to experience a significant loss in the future (for example, as a result of an impairment of oil and gas properties), it is possible, depending on factors including the magnitude of the loss, that these indenture covenants would restrict the Company’s ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not at any time preclude the Company from issuing new indebtedness to replace maturing debt.
The Company’s 1974 indenture pursuant to which $99.0 million (or 7.9%) of the Company’s long-term debt (as of September 30, 2010) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
The Company’s $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2010, the Company had no debt outstanding under the committed credit facility.
Note F — Fair Value Measurements
The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
96
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of September 30, 2010 and 2009. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. In January 2010, the FASB issued amended authoritative guidance respecting disclosures related to fair value measurements. The amended guidance requires disclosure of financial instruments and liabilities by class of assets and liabilities (not major category of assets and liabilities). In addition, this amended guidance also requires enhanced disclosures about the valuation techniques and inputs used to measure fair value and disclosures of transfers in and out of Level 1 or 2. During the quarter ended March 31, 2010, the Company adopted this amended guidance.
| | | | | | | | | | | | | | | | | |
| | | At Fair Value as of September 30, 2010 | |
| Recurring Fair Value Measures | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (Dollars in thousands) | |
| |
| Assets: | | | | | | | | | | | | | | | | |
| Cash Equivalents — Money Market Mutual Funds | | $ | 277,423 | | | $ | — | | | $ | — | | | $ | 277,423 | |
| Derivative Financial Instruments: | | | | | | | | | | | | | | | | |
| Over the Counter Swaps — Gas | | | — | | | | 67,387 | | | | — | | | | 67,387 | |
| Over the Counter Swaps — Oil | | | — | | | | — | | | | (2,203 | ) | | | (2,203 | ) |
| Other Investments: | | | | | | | | | | | | | | | | |
| Balanced Equity Mutual Fund | | | 17,256 | | | | — | | | | — | | | | 17,256 | |
| Common Stock — Financial Services Industry | | | 4,991 | | | | — | | | | — | | | | 4,991 | |
| Other Common Stock | | | 241 | | | | — | | | | — | | | | 241 | |
| Hedging Collateral Deposits | | | 11,134 | | | | — | | | | — | | | | 11,134 | |
| | | | | | | | | | | | | | | | | |
| Total | | $ | 311,045 | | | $ | 67,387 | | | $ | (2,203 | ) | | $ | 376,229 | |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | |
| Derivative Financial Instruments: | | | | | | | | | | | | | | | | |
| Commodity Futures Contracts — Gas | | $ | 5,840 | | | $ | — | | | $ | — | | | $ | 5,840 | |
| Over the Counter Swaps — Oil | | | — | | | | — | | | | 14,280 | | | | 14,280 | |
| Over the Counter Swaps — Gas | | | — | | | | 40 | | | | — | | | | 40 | |
| | | | | | | | | | | | | | | | | |
| Total | | $ | 5,840 | | | $ | 40 | | | $ | 14,280 | | | $ | 20,160 | |
| | | | | | | | | | | | | | | | | |
| Total Net Assets/(Liabilities) | | $ | 305,205 | | | $ | 67,347 | | | $ | (16,483 | ) | | $ | 356,069 | |
| | | | | | | | | | | | | | | | | |
97
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | |
| | | At Fair Value as of September 30, 2009 | |
| Recurring Fair Value Measures | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (Dollars in thousands) | |
| |
| Assets: | | | | | | | | | | | | | | | | |
| Cash Equivalents | | $ | 390,462 | | | $ | — | | | $ | — | | | $ | 390,462 | |
| Derivative Financial Instruments | | | 5,312 | | | | 12,536 | | | | 26,969 | | | | 44,817 | |
| Other Investments | | | 24,276 | | | | — | | | | — | | | | 24,276 | |
| Hedging Collateral Deposits | | | 848 | | | | — | | | | — | | | | 848 | |
| | | | | | | | | | | | | | | | | |
| Total | | $ | 420,898 | | | $ | 12,536 | | | $ | 26,969 | | | $ | 460,403 | |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | |
| Derivative Financial Instruments | | $ | — | | | $ | 2,148 | | | $ | — | | | $ | 2,148 | |
| | | | | | | | | | | | | | | | | |
| Total | | $ | — | | | $ | 2,148 | | | $ | — | | | $ | 2,148 | |
| | | | | | | | | | | | | | | | | |
| Total Net Assets/(Liabilities) | | $ | 420,898 | | | $ | 10,388 | | | $ | 26,969 | | | $ | 458,255 | |
| | | | | | | | | | | | | | | | | |
Derivative Financial Instruments
At September 30, 2010 and 2009, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX futures contracts used in the Company’s Energy Marketing segment. Hedging collateral deposits of $10.1 million (at September 30, 2010) and $0.8 million (at September 30, 2009), which are associated with these futures contracts have been reported in Level 1 as well. The derivative financial instruments reported in Level 2, at September 30, 2010 and 2009, consist of natural gas swap agreements used in the Company’s Exploration and Production and Energy Marketing segments. The fair value of these swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas trading markets). At September 30, 2010 and 2009, the derivative financial instruments reported in Level 3 consist of all of the Exploration and Production segment’s crude oil swap agreements. Hedging collateral deposits of $1.0 million associated with these oil swap agreements have been reported in Level 1 at September 30, 2010. The fair value of the crude oil swap agreements is based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume). Based on an assessment of the counterparties’ credit risk, the fair market value of the price swap agreements reported as Level 2 and Level 3 assets have been reduced by $1.0 million and $0.9 million at September 30, 2010 and September 30, 2009, respectively. The fair market value of the price swap agreements reported as Level 2 and Level 3 liabilities at September 30, 2010 have been reduced by $0.3 million and the price swap agreements reported as Level 2 liabilities at September 30, 2009 have been reduced by less than $0.1 million based on an assessment of the Company’s credit risk. These credit reserves were determined by applying default probabilities to the anticipated cash flows that the Company is either expecting from its counterparties or expecting to pay to its counterparties.
The tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3. For the 12 months ended September 30, 2010, no transfers in or out of Level 1 or Level 2 occurred.
98
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Fair Value Measurements Using Unobservable Inputs (Level 3)
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | Total Gains/Losses—
| | | | | | | |
| | | | | | Realized and Unrealized | | | | | | | |
| | | | | | | | | Included in Other
| | | Transfer
| | | | |
| | | October 1,
| | | Included in
| | | Comprehensive Income
| | | In/(Out) of
| | | September 30,
| |
| | | 2009 | | | Earnings | | | (Loss) | | | Level 3 | | | 2010 | |
| | | (Dollars in thousands) | |
| |
| Derivative Financial Instruments(2) | | $ | 26,969 | | | $ | (9,372 | )(1) | | $ | (34,080 | ) | | $ | — | | | $ | (16,483 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2010. |
|
| (2) | | Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3)
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | Total Gains/Losses —
| | | | | | | |
| | | | | | Realized and Unrealized | | | | | | | |
| | | | | | | | | Included in Other
| | | Transfer
| | | | |
| | | October 1,
| | | Included in
| | | Comprehensive Income
| | | In/(Out) of
| | | September 30,
| |
| | | 2008 | | | Earnings | | | (Loss) | | | Level 3 | | | 2009 | |
| | | (Dollars in thousands) | |
| |
| Derivative Financial Instruments(2) | | $ | 6,333 | | | $ | (59,180 | )(1) | | $ | 87,147 | | | $ | (7,331 | )(3) | | $ | 26,969 | |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2009. |
|
| (2) | | Derivative Financial Instruments are shown on a net basis. |
|
| (3) | | These transfers occurred because the Company was able to obtain and utilize forward-looking, observable basis differential information for its hedges on southern California natural gas production. |
EXECUTIVE OFFICERSNote G — Financial Instruments
Long-Term Debt
The fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:
| | | | | | | | | | | | | | | | | |
| | | At September 30 | |
| | | 2010 Carrying
| | | 2010 Fair
| | | 2009 Carrying
| | | 2009 Fair
| |
| | | Amount | | | Value | | | Amount | | | Value | |
| | | (Thousands) | |
| |
| Long-Term Debt | | $ | 1,249,000 | | | $ | 1,423,349 | | | $ | 1,249,000 | | | $ | 1,347,368 | |
| | | | | | | | | | | | | | | | | |
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value. The increase in the fair value of the Company’s debt is attributable to a decrease in the estimated rate at which the Company could issue debt at September 30, 2010 relative to September 30, 2009.
99
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Other Investments
Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity securities. The values of the insurance contracts amounted to $55.4 million and $54.2 million at September 30, 2010 and 2009, respectively. The fair value of the equity mutual fund was $17.3 million and $15.8 million at September 30, 2010 and 2009, respectively. The unrealized gain on the equity mutual fund at September 30, 2010 was negligible as the fair market value was approximately equal to the cost basis. The gross unrealized loss on this equity mutual fund was $1.0 million at September 30, 2009. The fair value of the stock of an insurance company was $5.0 million and $8.3 million at September 30, 2010 and 2009, respectively. The gross unrealized gain on this stock was $2.6 million and $5.9 million at September 30, 2010 and 2009, respectively. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.
Derivative Financial Instruments
The Company is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is commodity price risk in the Exploration and Production and Energy Marketing segments. The Company enters into futures contracts andover-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. The Company also enters into futures contracts and swaps to manage the risk associated with forecasted gas purchases, storage of gas, withdrawal of gas from storage to meet customer demand, and the potential decline in the value of gas held in storage. The duration of the Company’s hedges do not typically exceed 3 years.
The Company has presented its net derivative assets and liabilities on its Consolidated Balance Sheet at September 30, 2010 and September 30, 2009 as shown in the table below.
| | | | | | | | | | | | | |
| | | Fair Values of Derivative Instruments
|
| | | (Dollar Amounts in Thousands) |
Derivatives
| | Asset Derivatives | | Liability Derivatives |
Designated as
| | Consolidated
| | | | Consolidated
| | |
Hedging
| | Balance Sheet
| | | | Balance Sheet
| | |
| Instruments | | Location | | Fair Value | | Location | | Fair Value |
| |
Commodity
Contracts — at September 30,
2010 | | Fair Value of
Derivative
Financial
Instruments | | $ | 65,184 | | | Fair Value of
Derivative
Financial
Instruments | | $ | 20,160 | |
Commodity
Contracts — at September 30,
2009 | | Fair Value of
Derivative
Financial
Instruments | | $ | 44,817 | | | Fair Value of
Derivative
Financial
Instruments | | $ | 2,148 | |
100
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation on the Consolidated Balance Sheet at September 30, 2010 and September 30, 2009.
| | | | | |
Derivatives
| | | | |
Designated as
| | Fair Values of Derivative Instruments
|
Hedging
| | (Dollar Amounts in Thousands) |
| Instruments | | Gross Asset Derivatives | | Gross Liability Derivatives |
| |
| | | Fair Value | | Fair Value |
| Commodity Contracts at September 30, 2010 | | $77,837 | | $32,813 |
| Commodity Contracts at September 30, 2009 | | $63,601 | | $20,932 |
Cash Flow Hedges
For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.
As of September 30, 2010, the Company’s Exploration and Production segment had the following commodity derivative contracts (swaps) outstanding to hedge forecasted sales (where the Company uses short positions (i.e. positions that pay-off in the event of commodity price decline) to mitigate the risk of decreasing revenues and earnings):
| | |
| Commodity | | Units |
|
| Natural Gas | | 37.5 Bcf (all short positions) |
| Crude Oil | | 2,688,000 Bbls (all short positions) |
As of September 30, 2010, the Company’s Energy Marketing segment had the following commodity derivative contracts (futures contracts and swaps) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings) and purchases (where the Company uses long positions (i.e. positions that pay-off in the event of commodity price increases) to mitigate the risk of increasing natural gas prices, which would lead to increased purchased gas expense and decreased earnings):
| | |
| Commodity | | Units |
|
| Natural Gas | | 6.2 Bcf (6.1 Bcf short positions (forecasted storage withdrawals) and 0.1 Bcf long positions (forecasted storage injections)) |
As of September 30, 2010, the Company’s Exploration and Production segment had $49.1 million ($28.9 million after tax) of gains included in the accumulated other comprehensive income (loss) balance. It is expected that $33.3 million ($19.6 million after tax) of these gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodities occur. See Note A, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note A includes the Exploration and Production and Energy Marketing segments).
As of September 30, 2010, the Company’s Energy Marketing segment had $6.5 million ($4.0 million after tax) of gains included in the accumulated other comprehensive income (loss) balance. It is expected that all of these gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the sales and purchases of the underlying commodities occur. See Note A, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain (Loss)
101
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
on Derivative Financial Instruments in Note A includes the Exploration and Production and Energy Marketing segments).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
| |
| | | Year Ended September 30, 2010 and 2009 (Dollar Amounts in Thousands) | |
| | | Amount of
| | | | | Amount of
| | | | | | |
| | | Derivative Gain or
| | | | | Derivative Gain or
| | | | | | |
| | | (Loss) Recognized
| | | Location of
| | (Loss) Reclassified
| | | | | | |
| | | in Other
| | | Derivative Gain or
| | from Accumulated
| | | | | Derivative Gain or
| |
| | | Comprehensive
| | | (Loss) Reclassified
| | Other Comprehensive
| | | Location of
| | (Loss) Recognized
| |
| | | Income (Loss) on
| | | from Accumulated
| | Income (Loss) on
| | | Derivative Gain or
| | in the Consolidated
| |
| | | the Consolidated
| | | Other Comprehensive
| | the Consolidated
| | | (Loss) Recognized
| | Statement of Income
| |
| | | Statement of
| | | Income (Loss) on
| | Balance Sheet into
| | | in the Consolidated
| | (Ineffective
| |
| | | Comprehensive
| | | the Consolidated
| | the Consolidated
| | | Statement of Income
| | Portion and Amount
| |
| | | Income (Loss)
| | | Balance Sheet into
| | Statement of Income
| | | (Ineffective
| | Excluded from
| |
Derivatives in Cash
| | (Effective Portion)
| | | the Consolidated
| | (Effective Portion)
| | | Portion and Amount
| | Effectiveness Testing)
| |
Flow Hedging
| | for the Year Ended
| | | Statement of Income
| | for the Year Ended
| | | Excluded from
| | for the Year Ended
| |
| Relationships | | September 30, | | | (Effective Portion) | | September 30, | | | Effectiveness Testing) | | September 30, | |
| | | 2010 | | | 2009 | | | | | 2010 | | | 2009 | | | | | 2010 | | | 2009 | |
| |
| Commodity Contracts — Exploration & Production segment | | $ | 52,786 | | | $ | 110,883 | | | Operating Revenue | | $ | 39,898 | | | $ | 91,808 | | | Operating Revenue | | $ | — | | | $ | — | |
| Commodity Contracts — Energy Marketing segment | | $ | 11,200 | | | $ | 7,492 | | | Purchased Gas | | $ | 52 | | | $ | 21,301 | | | Operating Revenue | | $ | — | | | $ | — | |
| Commodity Contracts — Pipeline & Storage Segment(1) | | $ | 1,380 | | | $ | 652 | | | Operating Revenue | | $ | 1,370 | | | $ | 1,952 | | | Operating Revenue | | $ | — | | | $ | — | |
| Commodity Contracts — All Other(1) | | $ | — | | | $ | 183 | | | Purchased Gas | | $ | — | | | $ | (681 | ) | | Purchased Gas | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 65,366 | | | $ | 119,210 | | | | | $ | 41,320 | | | $ | 114,380 | | | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | There were no open hedging positions at September 30, 2010 or 2009. As such there is no mention of these positions in the preceding sections of this footnote. |
Fair value hedges
The Company’s Energy Marketing segment utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or market writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of September 30, 2010, the Company’s Energy Marketing segment had fair value hedges covering approximately 15.3 Bcf (14.2 Bcf of fixed price sales commitments (all long positions), 0.9 Bcf of fixed price purchase commitments (all short positions), and 0.2 Bcf of storage hedges (all short positions)). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.
| | | | | | | | | |
| Consolidated Statement of Income | | Gain/(Loss) on Derivative | | Gain/(Loss) on Commitment |
| |
| Operating Revenues | | $ | (9,807,701 | ) | | $ | 9,807,701 | |
| Purchased Gas | | $ | 62,352 | | | $ | (62,352 | ) |
102
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | |
| | | | | | Amount of
| |
| | | | | | Derivative Gain or
| |
| | | Location of
| | | (Loss) Recognized
| |
| | | Derivative Gain or
| | | in the Consolidated
| |
| | | (Loss) Recognized
| | | Statement of Income
| |
| | | in the Consolidated
| | | for the Year Ended
| |
| Derivatives in Fair Value Hedging Relationships | | Statement of Income | | | September 30, 2010 | |
| | | | | | (In thousands) | |
| |
| Commodity Contracts — Energy Marketing segment(1) | | | Operating Revenues | | | $ | (9,808 | ) |
| Commodity Contracts — Energy Marketing segment(2) | | | Purchased Gas | | | $ | (144 | ) |
| Commodity Contracts — Energy Marketing segment(3) | | | Purchased Gas | | | $ | 207 | |
| | | | | | | | | |
| | | | | | | $ | (9,745 | ) |
| | | | | | | | | |
| | |
| (1) | | Represents hedging of fixed price sales commitments of natural gas. |
|
| (2) | | Represents hedging of fixed price purchase commitments of natural gas. |
|
| (3) | | Represents hedging of natural gas held in storage. |
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company hasover-the-counter swap positions with eleven counterparties of which ten of the eleven counterparties are in a net gain position. On average, the Company had $6.5 million of credit exposure per counterparty in a gain position at September 30, 2010. The maximum credit exposure per counterparty at September 30, 2010 was $11.9 million. BP Energy Company (an affiliate of BP Corporation North America, Inc.) was one of the ten counterparties in a gain position. At September 30, 2010, the Company had an $11.3 million receivable with BP Energy Company. The Company considered the credit quality of BP Energy Company (as it does with all of its counterparties) in determining hedge effectiveness and believes the hedges remain effective. The Company had not received any collateral from these counterparties at September 30, 2010 since the Company’s gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral.
As of September 30, 2010, nine of the eleven counterparties to the Company’s outstanding derivative instrument contracts (specifically theover-the-counter swaps) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (the lower of the S&P or Moody’s Debt Rating), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position and the Company’s credit rating declined, then additional hedging collateral deposits would be required. At September 30, 2010, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $42.1 million according to the Company’s internal model (discussed in Note F — Fair Value Measurements). At September 30, 2010, the fair market value of the derivative financial instrument liability with a credit-risk related contingency feature was $14.3 million according to the Company’s internal model (discussed in Note F — Fair Value Measurements). For itsover-the-counter crude oil swap agreements, which are in a liability position, the Company was required to post $1.0 million in hedging collateral deposits at September 30, 2010. This is discussed in Note A under Hedging Collateral Deposits.
103
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For its exchange traded futures contracts which are in a liability position, the Company had posted $10.1 million in hedging collateral as of September 30, 2010. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.
The Company’s requirement to post hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note A under Hedging Collateral Deposits.
Note H — Retirement Plan and Other Post-Retirement Benefits
The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan) that covers a majority of the full-time employees of the Company. The Retirement Plan covers certain non-collectively bargained employees hired before July 1, 2003 and certain collectively bargained employees hired before November 1, 2003. Certain non-collectively bargained employees hired after June 30, 2003 and certain collectively bargained employees hired after October 31, 2003 are eligible for a Retirement Savings Account benefit provided under the Company’s defined contribution Tax-Deferred Savings Plans. Costs associated with the Retirement Savings Account were $0.6 million, $0.4 million and $0.2 million for the years ended September 30, 2010, 2009 and 2008, respectively. Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans, exclusive of the costs associated with the Retirement Savings Account, were $4.2 million, $4.1 million, and $4.0 million for the years ended September 30, 2010, 2009 and 2008, respectively.
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees hired before January 1, 2003 and certain collectively bargained employees hired before October 31, 2003.
The Company’s policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established VEBA trusts for its other post-retirement benefits. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ other post-retirement benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its other post-retirement benefits. They are separate accounts within the Retirement Plan trust used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan trust, for funding status purposes as shown below, the 401(h) accounts are included in Fair Value of Assets under Other Post-Retirement Benefits. Contributions are tax-deductible when made, subject to limitations contained in the Internal Revenue Code and regulations. Retirement Plan, VEBA trust and 401(h) account assets primarily consist of equity and fixed income investments or units in commingled funds or money market funds.
The expected return on plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets. The market-related value of plan assets is the market value as of the measurement date adjusted for variances between actual returns and expected returns (from previous years) that have not been reflected in net periodic benefit costs.
Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement
104
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
benefits are shown in the tables below. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30, 2010, September 30, 2009 and June 30, 2008, for fiscal year 2010, 2009 and 2008, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Retirement Plan | | | Other Post-Retirement Benefits | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
Change in Benefit Obligation | | | | | | | | | | | | | | | | | | | | | | | | |
| Benefit Obligation at Beginning of Period | | $ | 831,496 | | | $ | 719,059 | | | $ | 742,519 | | | $ | 467,295 | | | $ | 411,545 | | | $ | 444,545 | |
| Service Cost | | | 12,997 | | | | 10,913 | | | | 12,597 | | | | 4,298 | | | | 3,801 | | | | 5,104 | |
| Interest Cost | | | 44,308 | | | | 46,836 | | | | 44,949 | | | | 25,017 | | | | 27,499 | | | | 27,081 | |
| Plan Participants’ Contributions | | | — | | | | — | | | | — | | | | 1,644 | | | | 2,185 | | | | 1,990 | |
| Retiree Drug Subsidy Receipts | | | — | | | | — | | | | — | | | | 1,354 | | | | 1,427 | | | | 1,532 | |
| Amendments(1) | | | — | | | | — | | | | — | | | | — | | | | (10,765 | ) | | | (31,874 | ) |
| Actuarial (Gain) Loss | | | 85,831 | | | | 102,430 | | | | (34,189 | ) | | | (3,635 | ) | | | 55,776 | | | | (14,390 | ) |
| Adjustment for Change in Measurement Date | | | — | | | | 14,438 | | | | — | | | | — | | | | 7,825 | | | | — | |
| Benefits Paid | | | (50,139 | ) | | | (62,180 | ) | | | (46,817 | ) | | | (23,566 | ) | | | (31,998 | ) | | | (22,443 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Benefit Obligation at End of Period | | $ | 924,493 | | | $ | 831,496 | | | $ | 719,059 | | | $ | 472,407 | | | $ | 467,295 | | | $ | 411,545 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value of Assets at Beginning of Period | | $ | 563,881 | | | $ | 695,089 | | | $ | 765,144 | | | $ | 319,022 | | | $ | 377,640 | | | $ | 412,371 | |
| Actual Return on Plan Assets | | | 61,625 | | | | (99,511 | ) | | | (39,206 | ) | | | 30,478 | | | | (62,368 | ) | | | (43,478 | ) |
| Employer Contributions | | | 22,182 | | | | 15,993 | | | | 3,817 | | | | 25,691 | | | | 25,659 | | | | 29,200 | |
| Employer Contributions During Period from Measurement Date to Fiscal Year End | | | N/A | | | | N/A | | | | 12,151 | | | | N/A | | | | N/A | | | | — | |
| Plan Participants’ Contributions | | | — | | | | — | | | | — | | | | 1,644 | | | | 2,185 | | | | 1,990 | |
| Adjustment for Change in Measurement Date | | | — | | | | 14,490 | | | | — | | | | — | | | | 7,904 | | | | — | |
| Benefits Paid | | | (50,139 | ) | | | (62,180 | ) | | | (46,817 | ) | | | (23,566 | ) | | | (31,998 | ) | | | (22,443 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Assets at End of Period | | $ | 597,549 | | | $ | 563,881 | | | $ | 695,089 | | | $ | 353,269 | | | $ | 319,022 | | | $ | 377,640 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Net Amount Recognized at End of Period (Funded Status) | | $ | (326,944 | ) | | $ | (267,615 | ) | | $ | (23,970 | ) | | $ | (119,138 | ) | | $ | (148,273 | ) | | $ | (33,905 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Amounts Recognized in the Balance Sheets Consist of: | | | | | | | | | | | | | | | | | | | | | | | | |
| Accrued Benefit Liability | | $ | (326,944 | ) | | $ | (267,615 | ) | | $ | (23,970 | ) | | $ | (119,138 | ) | | $ | (148,273 | ) | | $ | (54,939 | ) |
| Prepaid Benefit Cost | | | — | | | | — | | | | — | | | | — | | | | — | | | | 21,034 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Amount Recognized at End of Period | | $ | (326,944 | ) | | $ | (267,615 | ) | | $ | (23,970 | ) | | $ | (119,138 | ) | | $ | (148,273 | ) | | $ | (33,905 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Accumulated Benefit Obligation | | $ | 843,526 | | | $ | 758,658 | | | $ | 659,004 | | | | N/A | | | | N/A | | | | N/A | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Retirement Plan | | | Other Post-Retirement Benefits | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount Rate | | | 4.75 | % | | | 5.50 | % | | | 6.75 | % | | | 4.75 | % | | | 5.50 | % | | | 6.75 | % |
| Rate of Compensation Increase | | | 4.75 | % | | | 5.00 | % | | | 5.00 | % | | | 4.75 | % | | | 5.00 | % | | | 5.00 | % |
Components of Net Periodic Benefit Cost | | | | | | | | | | | | | | | | | | | | | | | | |
| Service Cost | | $ | 12,997 | | | $ | 10,913 | | | $ | 12,597 | | | $ | 4,298 | | | $ | 3,801 | | | $ | 5,104 | |
| Interest Cost | | | 44,308 | | | | 46,836 | | | | 44,949 | | | | 25,017 | | | | 27,499 | | | | 27,081 | |
| Expected Return on Plan Assets | | | (58,342 | ) | | | (57,958 | ) | | | (55,000 | ) | | | (26,334 | ) | | | (31,615 | ) | | | (33,715 | ) |
| Amortization of Prior Service Cost | | | 655 | | | | 732 | | | | 808 | | | | (1,710 | ) | | | (1,074 | ) | | | 4 | |
| Amortization of Transition Amount | | | — | | | | — | | | | — | | | | 541 | | | | 2,265 | | | | 7,127 | |
| Recognition of Actuarial Loss(2) | | | 21,641 | | | | 5,676 | | | | 11,064 | | | | 25,881 | | | | 9,271 | | | | 2,927 | |
| Net Amortization and Deferral for Regulatory Purposes | | | (30 | ) | | | 12,817 | | | | 6,008 | | | | 351 | | | | 18,037 | | | | 22,264 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Periodic Benefit Cost | | $ | 21,229 | | | $ | 19,016 | | | $ | 20,426 | | | $ | 28,044 | | | $ | 28,184 | | | $ | 30,792 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount Rate | | | 5.50 | % | | | 6.75 | % | | | 6.25 | % | | | 5.50 | % | | | 6.75 | % | | | 6.25 | % |
| Expected Return on Plan Assets | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % |
| Rate of Compensation Increase | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % |
| | |
| (1) | | In fiscal 2008 and 2009, the Company passed amendments, for most of the subsidiaries, which increased the participant contributions for active employees at the time of the amendment. This decreased the benefit obligation. |
|
| (2) | | Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach. |
The Net Periodic Benefit Cost in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under the existing authoritative guidance as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets and liabilities) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above.
As noted above, through 2008, the Company used June 30th as the measurement date for financial reporting purposes. In 2009, in accordance with the current authoritative guidance for defined benefit pension and other postretirement plans, the Company began measuring the Plan’s assets and liabilities for its pension and other post-retirement benefit plans as of September 30th, its fiscal year end. In making this change and as
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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
permitted by the current authoritative guidance, the Company recorded fifteen months of pension and post-retirement benefits expense during the fiscal year ended September 30, 2009. As allowed by the authoritative guidance, these costs were calculated using June 30, 2008 measurement date data. Three of those months pertained to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $3.8 million and were recorded by the Company during the year ended September 30, 2009 as a $3.4 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $0.4 million ($0.2 million after tax) adjustment to earnings reinvested in the business. In addition, for the Company’s non-qualified benefit plan, benefit costs of $1.3 million were recorded by the Company during the year ended September 30, 2009 as a $0.4 million increase to Other Regulatory Assets in the Company’s Utility segment and a $0.9 million ($0.6 million after tax) adjustment to earnings reinvested in the business.
The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2010, the changes in such amounts during 2010, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2011 are presented in the table below:
| | | | | | | | | | | | | |
| | | | | | Other
| | | | |
| | | Retirement
| | | Post-Retirement
| | | Non-Qualified
| |
| | | Plan | | | Benefits | | | Benefit Plans | |
| | | (Thousands) | |
| |
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) | | | | | | | | | | | | |
| Net Actuarial Loss | | $ | (385,522 | ) | | $ | (157,700 | ) | | $ | (33,949 | ) |
| Transition Obligation | | | — | | | | (1,487 | ) | | | — | |
| Prior Service (Cost) Credit | | | (3,925 | ) | | | 8,807 | | | | — | |
| | | | | | | | | | | | | |
| Net Amount Recognized | | $ | (389,447 | ) | | $ | (150,380 | ) | | $ | (33,949 | ) |
| | | | | | | | | | | | | |
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2010(1) | | | | | | | | | | | | |
| Increase in Net Actuarial Gain/(Loss) | | $ | (60,907 | ) | | $ | 33,660 | | | $ | (9,258 | ) |
| Reduction in Transition Obligation | | | — | | | | 540 | | | | — | |
| Prior Service (Cost) Credit | | | 656 | | | | (1,710 | ) | | | — | |
| | | | | | | | | | | | | |
| Net Change | | $ | (60,251 | ) | | $ | 32,490 | | | $ | (9,258 | ) |
| | | | | | | | | | | | | |
Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) | | | | | | | | | | | | |
| Net Actuarial Loss | | $ | (34,873 | ) | | $ | (23,793 | ) | | $ | (3,860 | ) |
| Transition Obligation | | | — | | | | (541 | ) | | | — | |
| Prior Service (Cost) Credit | | | (589 | ) | | | 1,710 | | | | — | |
| | | | | | | | | | | | | |
| Net Amount Expected to be Recognized | | $ | (35,462 | ) | | $ | (22,624 | ) | | $ | (3,860 | ) |
| | | | | | | | | | | | | |
| | |
| (1) | | Amounts presented are shown before recognizing deferred taxes. |
In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, 2010, the Company recorded an $11.8 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $25.2 million (pre-tax) increase to Accumulated Other Comprehensive Loss.
107
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The effect of the discount rate change for the Retirement Plan in 2010 was to increase the projected benefit obligation of the Retirement Plan by $75.1 million. In 2010, other actuarial experience increased the projected benefit obligation for the Retirement Plan by $10.8 million. The effect of the discount rate change for the Retirement Plan in 2009 was to increase the projected benefit obligation of the Retirement Plan by $102.6 million. The effect of the discount rate change for the Retirement Plan in 2008 was to decrease the projected benefit obligation of the Retirement Plan by $38.6 million.
The Company made cash contributions totaling $22.2 million to the Retirement Plan during the year ended September 30, 2010. The Company expects that the annual contribution to the Retirement Plan in 2011 will be in the range of $40.0 million to $45.0 million. Changes in the discount rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund larger amounts to the Retirement Plan in 2011 in order to be in compliance with the Pension Protection Act of 2006.
The following benefit payments, which reflect expected future service, are expected to be paid during the next five years and the five years thereafter: $52.1 million in 2011; $52.9 million in 2012; $53.8 million in 2013; $54.9 million in 2014; $56.3 million in 2015; and $305.4 million in the five years thereafter.
In addition to the Retirement Plan discussed above, the Company also has Non-Qualified benefit plans that cover a group of management employees designated by the Chief Executive Officer of the Company. These plans provide for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit cost associated with these plans were $7.4 million, $5.4 million and $5.2 million in 2010, 2009 and 2008, respectively. The accumulated benefit obligations for the plans were $41.8 million and $37.4 million at September 30, 2010 and 2009, respectively. The projected benefit obligations for the plans were $73.9 million and $64.6 million at September 30, 2010 and 2009, respectively. The actuarial valuations for the plans were determined based on a discount rate of 4.25%, 5.25% and 6.75% as of September 30, 2010, 2009 and 2008, respectively and a weighted average rate of compensation increase of 8.0%, 8.25% and 8.75% as of September 30, 2010, 2009 and 2008, respectively.
The effect of the discount rate change in 2010 was to increase the other post-retirement benefit obligation by $39.4 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2010 by $43.1 million, primarily attributable to updated pharmaceutical drug rebate experience as well as updated claim costs assumptions based on experience.
The effect of the discount rate change in 2009 was to increase the other post-retirement benefit obligation by $60.9 million. Effective October 1, 2009, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $27.0 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2009 by $32.1 million.
The effect of the discount rate change in 2008 was to decrease the other post-retirement benefit obligation by $26.3 million. Effective July 1, 2008, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $20.0 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2008 by $8.1 million.
On December 8, 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law. This Act introduced a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Since the Company is assumed to continue to provide a prescription drug benefit to retirees in the point of service and indemnity plans that is at least actuarially equivalent to Medicare Part D, the impact of the Act was reflected as of December 8, 2003.
108
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The estimated gross other post-retirement benefit payments and gross amount of Medicare Part D prescription drug subsidy receipts are as follows:
| | | | | | | | | |
| | | Benefit Payments | | Subsidy Receipts |
| |
| 2011 | | $ | 25,375,000 | | | $ | (2,001,000 | ) |
| 2012 | | $ | 26,795,000 | | | $ | (2,275,000 | ) |
| 2013 | | $ | 28,116,000 | | | $ | (2,575,000 | ) |
| 2014 | | $ | 29,520,000 | | | $ | (2,871,000 | ) |
| 2015 | | $ | 31,002,000 | | | $ | (3,169,000 | ) |
| 2016 through 2020 | | $ | 175,195,000 | | | $ | (20,370,000 | ) |
| | | | | | | | | | | | | |
| | | 2010 | | 2009 | | 2008 |
| |
| Rate of Increase for Pre Age 65 Participants | | | 7.82 | %(1) | | | 8.0 | %(1) | | | 9.0 | %(2) |
| Rate of Increase for Post Age 65 Participants | | | 6.95 | %(1) | | | 7.0 | %(1) | | | 7.0 | %(2) |
| Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits | | | 8.69 | %(1) | | | 9.0 | %(1) | | | 10.0 | %(2) |
| Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement | | | 6.95 | %(1) | | | 7.0 | %(1) | | | 7.0 | %(2) |
| Annual Rate of Increase in the Per Capita Medicare Part D Subsidy | | | 7.60 | %(1) | | | 7.9 | %(1) | | | 10.0 | %(2) |
| | |
| (1) | | It was assumed that this rate would gradually decline to 4.5% by 2028. |
|
| (2) | | It was assumed that this rate would gradually decline to 5.0% by 2018. |
The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2010 would increase by $57.6 million. This 1% change would also have increased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2010 by $4.0 million. If the health care cost trend rates were decreased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2010 would decrease by $48.6 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2010 by $3.3 million.
The Company made cash contributions totaling $25.5 million to its VEBA trusts and 401(h) accounts during the year ended September 30, 2010. In addition, the Company made direct payments of $0.2 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2010. The Company expects that the annual contribution to its VEBA trusts and 401(h) accounts in 2011 will be in the range of $25.0 million to $30.0 million.
Investment Valuation
The Retirement Plan assets and other post-retirement benefit assets are valued under the current fair value framework. See Note F “Fair Value Measurements” for further discussion regarding the definition and levels of fair value hierarchy established by the authoritative guidance.
The inputs or methodology used for valuing securities are not necessarily an indication of the risk associated with investing in those securities. Below is a listing of the major categories of plan assets held as of September 30, 2010, as well as the associated level within the fair value hierarchy in which the fair value
109
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
measurements in their entirety fall (based on the lowest level input that is significant to the fair value measurement in its entirety). (Dollars in Thousands):
| | | | | | | | | | | | | | | | | |
| | | Total Fair Value
| | | | | | | | | | |
| | | Amounts at
| | | | | | | | | | |
| | | September 30, 2010 | | | Level 1 | | | Level 2 | | | Level 3 | |
| |
Retirement Plan Investments | | | | | | | | | | | | | | | | |
| Equities | | | | | | | | | | | | | | | | |
| Collective Trust Funds — Domestic | | $ | 131,313 | | | $ | — | | | $ | 131,313 | | | $ | — | |
| Collective Trust Funds — International | | | 72,612 | | | | — | | | | 72,612 | | | | — | |
| Common Stock — Domestic | | | 158,215 | | | | 158,215 | | | | — | | | | — | |
| Common Stock — International | | | 19,351 | | | | 19,351 | | | | — | | | | — | |
| Convertible Securities — Domestic | | | 32,911 | | | | 4,403 | | | | 28,189 | | | | 319 | |
| Convertible Securities — International | | | 2,175 | | | | 548 | | | | 1,627 | | | | — | |
| Preferred Stock | | | 765 | | | | 765 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | |
| Total Equities | | | 417,342 | | | | 183,282 | | | | 233,741 | | | | 319 | |
| Fixed Income | | | | | | | | | | | | | | | | |
| Collective Trust Funds — Domestic | | | 75,455 | | | | — | | | | 75,455 | | | | — | |
| Collective Trust Funds — International | | | 69,511 | | | | — | | | | 69,511 | | | | — | |
| Corporate Bonds — Domestic | | | 572 | | | | — | | | | 572 | | | | — | |
| Exchange Traded Funds | | | 17,911 | | | | 17,911 | | | | — | | | | — | |
| Other | | | 83 | | | | — | | | | 83 | | | | — | |
| | | | | | | | | | | | | | | | | |
| Total Fixed Income | | | 163,532 | | | | 17,911 | | | | 145,621 | | | | — | |
| Real Estate | | | 5,812 | | | | — | | | | — | | | | 5,812 | |
| Limited Partnerships | | | 232 | | | | — | | | | — | | | | 232 | |
| Cash & Cash Equivalents | | | | | | | | | | | | | | | | |
| Cash Held in Collective Trust Funds | | | 10,413 | | | | — | | | | 10,413 | | | | — | |
| Cash Held in Savings/Checking Accounts, Commercial Paper, etc. | | | 123 | | | | — | | | | 123 | | | | — | |
| | | | | | | | | | | | | | | | | |
| Total Cash & Cash Equivalents | | | 10,536 | | | | — | | | | 10,536 | | | | — | |
| | | | | | | | | | | | | | | | | |
| Total Retirement Plan Investments | | $ | 597,454 | | | $ | 201,193 | | | $ | 389,898 | | | $ | 6,363 | |
| | | | | | | | | | | | | | | | | |
| Accrued Income Receivable | | | 699 | | | | | | | | | | | | | |
| Accrued Administrative Costs | | | (604 | ) | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Total Retirement Plan Assets | | $ | 597,549 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
110
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | |
| | | Total Fair Value
| | | | | | | | | | |
| | | Amounts at
| | | | | | | | | | |
| | | September 30, 2010 | | | Level 1 | | | Level 2 | | | Level 3 | |
| |
VEBA Investments | | | | | | | | | | | | | | | | |
| Equities | | | | | | | | | | | | | | | | |
| Collective Trust Funds — Domestic | | $ | 217,637 | | | $ | — | | | $ | 217,637 | | | $ | — | |
| Collective Trust Funds — International | | | 85,799 | | | | — | | | | 85,799 | | | | — | |
| | | | | | | | | | | | | | | | | |
| Total Equities | | | 303,436 | | | | — | | | | 303,436 | | | | — | |
| Real Estate | | | 3,824 | | | | — | | | | — | | | | 3,824 | |
| Cash Held in Collective Trust Funds | | | 7,622 | | | | — | | | | 7,622 | | | | — | |
| | | | | | | | | | | | | | | | | |
| Total VEBA Investments | | $ | 314,882 | | | $ | — | | | $ | 311,058 | | | $ | 3,824 | |
| | | | | | | | | | | | | | | | | |
| Accrued Income Receivable | | | 600 | | | | | | | | | | | | | |
| Accrued Administrative Costs | | | (196 | ) | | | | | | | | | | | | |
| Claims Incurred But Not Reported | | | (1,736 | ) | | | | | | | | | | | | |
| Prepaid Federal Taxes | | | 2,866 | | | | | | | | | | | | | |
| Deferred Tax Asset | | | 2,230 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Total Fair Value of VEBA Assets | | $ | 318,646 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
401(h) Investments | | | | | | | | | | | | | | | | |
| Equities | | | | | | �� | | | | | | | | | | |
| Collective Trust Funds — Domestic | | $ | 7,601 | | | $ | — | | | $ | 7,601 | | | $ | — | |
| Collective Trust Funds — International | | | 4,203 | | | | — | | | | 4,203 | | | | — | |
| Common Stock — Domestic | | | 9,158 | | | | 9,158 | | | | — | | | | — | |
| Common Stock — International | | | 1,120 | | | | 1,120 | | | | — | | | | — | |
| Convertible Securities — Domestic | | | 1,905 | | | | 255 | | | | 1,632 | | | | 18 | |
| Convertible Securities — International | | | 126 | | | | 32 | | | | 94 | | | | — | |
| Preferred Stock | | | 45 | | | | 45 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | |
| Total Equities | | | 24,158 | | | | 10,610 | | | | 13,530 | | | | 18 | |
| Fixed Income | | | | | | | | | | | | | | | | |
| Collective Trust Funds — Domestic | | | 4,368 | | | | — | | | | 4,368 | | | | — | |
| Collective Trust Funds — International | | | 4,024 | | | | — | | | | 4,024 | | | | — | |
| Corporate Bonds — Domestic | | | 33 | | | | — | | | | 33 | | | | — | |
| Exchange Traded Funds | | | 1,037 | | | | 1,037 | | | | — | | | | — | |
| Other | | | 4 | | | | — | | | | 4 | | | | — | |
| | | | | | | | | | | | | | | | | |
| Total Fixed Income | | | 9,466 | | | | 1,037 | | | | 8,429 | | | | — | |
| Real Estate | | | 336 | | | | — | | | | — | | | | 336 | |
| Limited Partnerships | | | 13 | | | | — | | | | — | | | | 13 | |
| Cash Held in Collective Trust Funds | | | 610 | | | | — | | | | 610 | | | | — | |
| | | | | | | | | | | | | | | | | |
| Total 401(h) Investments | | $ | 34,583 | | | $ | 11,647 | | | $ | 22,569 | | | $ | 367 | |
| | | | | | | | | | | | | | | | | |
| Accrued Income Receivable | | | 40 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Total Fair Value of Assets | | $ | 34,623 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Total Other Post-Retirement Benefit Assets | | $ | 353,269 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
111
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Retirement Plan and 401(h) Account Investments:
Equities: Level 1 equities consist of individual publicly traded stocks (common and preferred) and convertible securities. These are valued using quoted market values as of the end of the year. Level 2 equities consist primarily of investments in collective trusts. The fair value of such trusts is derived from the fair value of the underlying investments. In addition, there are Level 2 equities that consist of convertible securities, for which quoted market values are unavailable or are not used because the associated trading volumes are lower, that are valued using observable market data. Level 3 equities consist of investments in convertible securities where there are no readily obtainable market values. These investments are valued using unobservable market data.
Fixed Income: Level 1 fixed income securities consist of exchange-traded bond funds and are valued using quoted market values as of the end of the year. Level 2 fixed income securities consist primarily of investments in collective trusts, corporate bonds and other investments (typically guaranteed investment contracts, collateralized mortgage obligations, asset backed securities, etc). The collective trusts are carried at the stated unit value of funds, which are derived from the fair value of the underlying investments. The corporate bonds and other investments are valued using observable market data. Level 3 fixed income securities typically consist of collateralized mortgage obligations, asset backed securities, and corporate/government bonds that are not actively traded. At September 30, 2010, there are no such investments.
Real Estate: Level 3 real estate investments consist primarily of commercial and residential properties that are valued at the Plan’s proportionate interest in the total current value of the underlying net assets of these investments. This fair value is determined using unobservable market data.
Limited Partnerships: Level 3 limited partnerships consist of cash held in the partnerships and private equity holdings. The Plan’s interest in these partnerships is valued based on the fair value as determined by the general partner or board of directors. The fair value of the private equity holdings is determined using unobservable market data.
Cash and Cash Equivalents: The cash and cash equivalents in Level 2 consists of collective trusts that invest in various cash and money market investments as well as treasury bills, notes, and bonds. In addition, cash held in checking/savings accounts and commercial paper are included as well.
VEBA Investments:
Collective Trust Funds: The fair value of collective trust funds classified as Level 2 are derived from the fair value of the underlying investments in equities (primarily publicly traded stocks).
Cash and Cash Equivalents: The cash equivalents reported in Level 2 consists of an institutional fund that invests in high quality, short-term municipal instruments. This fund is valued at amortized cost, which the investment advisor has determined approximates fair value.
Real Estate: Level 3 real estate investments consist primarily of commercial and residential properties that are valued at the VEBA’s proportionate interest in the total current value of the underlying net assets of these investments. This fair value is determined using unobservable market data.
The preceding methods may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.
The following tables provide a reconciliation of the beginning and ending balances of the Retirement Plan and other post-retirement benefit assets measured at fair value on a recurring basis where the determination of
112
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
fair value includes significant unobservable inputs (Level 3). Note: For the year-ended September 30, 2010, there were no significant transfers in or out of Level 1 or Level 2. In addition, as shown in the following tables, there were no transfers in or out of Level 3.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Retirement Plan Level 3 Assets
| |
| | | Year Ended September 30, 2010
| |
| | | (Thousands of Dollars) | |
| | | Equities | | | Fixed Income | | | | | | | | | | |
| | | | | | | | | Collateralized
| | | | | | | | | | |
| | | Convertible
| | | | | | Mortgage
| | | | | | | | | | |
| | | Securities
| | | Preferred
| | | Obligations
| | | Limited
| | | Real
| | | | |
| | | (Domestic) | | | Stock | | | (Part of Other) | | | Partnerships | | | Estate | | | Total | |
| |
| Balance, Beginning of Year | | $ | 733 | | | $ | 362 | | | $ | 542 | | | $ | 372 | | | $ | 7,518 | | | $ | 9,527 | |
| Realized Gains/(Losses) | | | 50 | | | | (108 | ) | | | 1 | | | | (1,495 | ) | | | — | | | | (1,552 | ) |
| Unrealized Gains/(Losses) | | | (4 | ) | | | (3 | ) | | | (24 | ) | | | 1,510 | | | | (2,350 | ) | | | (871 | ) |
| Purchases, Sales, Issuances, and Settlements (Net) | | | (460 | ) | | | (251 | ) | | | (519 | ) | | | (155 | ) | | | 644 | | | | (741 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at September 30, 2010 (End of Year) | | $ | 319 | | | $ | — | | | $ | — | | | $ | 232 | | | $ | 5,812 | | | $ | 6,363 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Other Post-Retirement Benefit Level 3 Assets
| |
| | | Year Ended September 30, 2010
| |
| | | (Thousands of Dollars) | |
| | | VEBA
| | | 401(h) Investments | |
| | | Investments | | | Equities | | | Fixed Income | | | | | | | | | | |
| | | | | | | | | | | | Collateralized
| | | | | | | | | | |
| | | | | | Convertible
| | | | | | Mortgage
| | | | | | | | | Total
| |
| | | Real
| | | Securities
| | | Preferred
| | | Obligations
| | | Limited
| | | Real
| | | 401(h)
| |
| | | Estate | | | (Domestic) | | | Stock | | | (Part of Other) | | | Partnerships | | | Estate | | | Investments | |
| |
| Balance, Beginning of Year | | $ | 3,816 | | | $ | 37 | | | $ | 18 | | | $ | 27 | | | $ | 19 | | | $ | 376 | | | $ | 477 | |
| Realized Gains/(Losses) | | | — | | | | 3 | | | | (6 | ) | | | — | | | | (87 | ) | | | — | | | | (90 | ) |
| Unrealized Gains/(Losses) | | | 8 | | | | 5 | | | | 3 | | | | 3 | | | | 90 | | | | (77 | ) | | | 24 | |
| Purchases, Sales, Issuances, and Settlements (Net) | | | — | | | | (27 | ) | | | (15 | ) | | | (30 | ) | | | (9 | ) | | | 37 | | | | (44 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at September 30, 2010 (End of Year) | | $ | 3,824 | | | $ | 18 | | | $ | — | | | $ | — | | | $ | 13 | | | $ | 336 | | | $ | 367 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The Company’s Retirement Plan weighted average asset allocations (excluding the 401(h) accounts) at September 30, 2010, 2009 and 2008 by asset category are as follows:
| | | | | | | | | | | | | | | | | |
| | | | | | Percentage of Plan
| |
| | | Target Allocation
| | | Assets at September 30 | |
| Asset Category | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| |
| Equity Securities | | | 60-75 | % | | | 70 | % | | | 73 | % | | | 74 | % |
| Fixed Income Securities | | | 20-35 | % | | | 27 | % | | | 21 | % | | | 23 | % |
| Other | | | 0-15 | % | | | 3 | % | | | 6 | % | | | 3 | % |
| | | | | | | | | | | | | | | | | |
| Total | | | | | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | | | |
113
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company’s weighted average asset allocations for its VEBA trusts and 401(h) accounts at September 30, 2010, 2009 and 2008 by asset category are as follows:
| | | | | | | | | | | | | | | | | |
| | | | | | Percentage of Plan
| |
| | | Target Allocation
| | | Assets at September 30 | |
| Asset Category | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| |
| Equity Securities | | | 85-100 | % | | | 93 | % | | | 93 | % | | | 93 | % |
| Fixed Income Securities | | | 0-15 | % | | | 3 | % | | | 2 | % | | | 2 | % |
| Other | | | 0-15 | % | | | 4 | % | | | 5 | % | | | 5 | % |
| | | | | | | | | | | | | | | | | |
| Total | | | | | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | | | |
The Company’s assumption regarding the expected long-term rate of return on plan assets is 8.25%. The return assumption 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.
The long-term investment objective of the Retirement Plan trust, the VEBA trusts and the 401(h) accounts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing a mix of equities, fixed income and other securities (including real estate). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. The assets of the Retirement Plan trusts, VEBA trusts and the 401(h) accounts have no significant concentrations of risk in any one country (other than the United States), industry or entity.
Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis.
The discount rate which is used to present value the future benefit payment obligations of the Retirement Plan and the Company’s other post-retirement benefits is 4.75% as of September 30, 2010. The discount rate which is used to present value the future benefit payment obligations of the Non-Qualified benefit plans is 4.25% as of September 30, 2010. The Company utilizes a yield curve model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year’s anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments.
Note I — Commitments and Contingencies
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.
It is the Company’s policy to accrue estimated environmentalclean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, 2010, the Company has estimated its remainingclean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $17.3 million to $21.5 million. The minimum estimated liability of $17.3 million has been recorded on the Consolidated Balance Sheet at September 30, 2010. The Company expects to recover its environmentalclean-up costs through rate recovery. Other than as discussed below, the Company is currently not aware of any material exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.
114
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
| (i) | Former Manufactured Gas Plant Sites |
The Company has incurred investigationand/orclean-up costs at several former manufactured gas plant sites in New York and Pennsylvania. The Company continues to be responsible for future ongoing monitoring and long-term maintenance at two sites.
The Company has agreed with the NYDEC to remediate another former manufactured gas plant site located in New York. The Company has received approval from the NYDEC of a Remedial Design work plan for this site and has recorded an estimated minimum liability for remediation of this site of $14.7 million.
In June 2007, the NYDEC notified the Company, as well as a number of other companies, of their potential liability with respect to a remedial action at a waste disposal site in New York. The notification identified the Company as one of approximately 500 other companies considered to be PRPs related to this site and requested that the remedy the NYDEC proposed in a Record of Decision issued in March 2006 be performed. The estimatedclean-up costs under the remedy selected by the NYDEC are estimated to be approximately $13.0 million if implemented. The Company participates in an organized group with other PRPs who are addressing this site.
In November 2010, the NYDEC notified the Company of its potential liability with respect to a remedial action at former industrial sites in New York. Along with the Company, notifications were sent to the City of Buffalo and the New York State Thruway Authority. Estimatedclean-up costs associated with these sites have not been completed and the Company cannot estimate its liability, if any, regarding these sites at this time.
Other
The Company, in its Utility segment, Energy Marketing segment, and All Other category, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Substantially all of these contracts expire within the next five years. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $380.1 million in 2011, $86.3 million in 2012, $51.6 million in 2013, $34.7 million in 2014, $19.8 million in 2015 and $14.5 million thereafter. Gas prices within the gas purchase contracts are variable based on NYMEX prices adjusted for basis. In the Utility segment, these costs are subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.
The Company has entered into leases for the use of buildings, vehicles, construction tools, meters, computer equipment and other items. These leases are accounted for as operating leases. The future lease commitments during the next five years and thereafter are as follows: $5.1 million in 2011, $4.6 million in 2012, $3.5 million in 2013, $3.2 million in 2014, $2.8 million in 2015, and $8.2 million thereafter.
The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note C — Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business. These other litigation and regulatory matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and 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 period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
115
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note J — Discontinued Operations
On September 1, 2010, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. Those operations consisted of short distance landfill gas pipeline companies engaged in the purchase, sale and transportation of landfill gas. The Company’s landfill gas operations were maintained under the Company’s wholly-owned subsidiary, Horizon LFG. The Company received approximately $38.0 million of proceeds from the sale. The sale resulted in the recognition of a gain of approximately $6.3 million, net of tax, during the fourth quarter of 2010. The decision to sell was based on progressing the Company’s strategy of divesting its smaller, non-core assets in order to focus on its core businesses, including the development of the Marcellus Shale and the construction of key pipeline infrastructure projects throughout the Appalachian region. As a result of the decision to sell the landfill gas operations, the Company began presenting these operations as discontinued operations during the fourth quarter of 2010.
The following is selected financial information of the discontinued operations for the sale of the Company’s landfill gas operations:
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
| Operating Revenues | | $ | 9,919 | | | $ | 6,309 | | | $ | 3,524 | |
| Operating Expenses | | | 8,933 | | | | 10,705 | | | | 883 | |
| | | | | | | | | | | | | |
| Operating Income (Loss) | | | 986 | | | | (4,396 | ) | | | 2,641 | |
| Other Income | | | 4 | | | | 8 | | | | 29 | |
| Interest Income | | | 2 | | | | — | | | | — | |
| Interest Expense | | | 29 | | | | 127 | | | | 599 | |
| | | | | | | | | | | | | |
| Income (Loss) before Income Taxes | | | 963 | | | | (4,515 | ) | | | 2,071 | |
| Income Tax Expense (Benefit) | | | 493 | | | | (1,739 | ) | | | 250 | |
| | | | | | | | | | | | | |
| Income (Loss) from Discontinued Operations | | | 470 | | | | (2,776 | ) | | | 1,821 | |
| Gain on Disposal, Net of Taxes of $4,024 | | | 6,310 | | | | — | | | | — | |
| | | | | | | | | | | | | |
| Income (Loss) from Discontinued Operations | | $ | 6,780 | | | $ | (2,776 | ) | | $ | 1,821 | |
| | | | | | | | | | | | | |
Note K — Business Segment Information
The Company reports financial results for four segments: Utility, Pipeline and Storage, Exploration and Production, and Energy Marketing. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.
The Pipeline and Storage segment operations are regulated by the FERC for both Supply Corporation and Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers (including NFR), exploration and production companies (including Seneca) and pipeline companies in the northeastern United States markets. Empire transports natural gas from the United States/Canadian border near Buffalo, New York into Central New York just north of Syracuse, New York. Empire’s new facilities (the Empire Connector), which consists of a compressor station and a pipeline extension from near Rochester, New York to an interconnection near Corning, New York with the unaffiliated Millennium Pipeline,
116
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
were placed into service on December 10, 2008. Empire transports gas to major industrial companies, utilities (including Distribution Corporation) and power producers.
The Exploration and Production segment, through Seneca, is engaged in exploration for, and development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, and in the shallow waters of the Gulf Coast region of Texas and Louisiana. Seneca’s production is, for the most part, sold to purchasers located in the vicinity of its wells. As disclosed in Note M — Acquisition, on July 20, 2009, Seneca acquired Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million (including cash acquired). Ivanhoe Energy’s United States oil and gas operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on July 20, 2009.
The Energy Marketing segment is comprised of NFR’s operations. NFR markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. The accounting policies of the segments are the same as those described in Note A — Summary of Significant Accounting Policies. Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. The Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30, 2010 |
| | | | | | | | | | | | | | | Corporate
| | |
| | | | | Pipeline
| | Exploration
| | | | Total
| | | | and
| | |
| | | | | and
| | and
| | Energy
| | Reportable
| | All
| | Intersegment
| | Total
|
| | | Utility | | Storage | | Production | | Marketing | | Segments | | Other | | Eliminations | | Consolidated |
| | | (Thousands) |
| |
| Revenue from External Customers | | $ | 804,466 | | | $ | 138,905 | | | $ | 438,028 | | | $ | 344,802 | | | $ | 1,726,201 | | | $ | 33,428 | | | $ | 874 | | | $ | 1,760,503 | |
| Intersegment Revenues | | $ | 15,324 | | | $ | 79,978 | | | $ | — | | | $ | — | | | $ | 95,302 | | | $ | 2,315 | | | $ | (97,617 | ) | | $ | — | |
| Interest Income | | $ | 2,144 | | | $ | 199 | | | $ | 980 | | | $ | 44 | | | $ | 3,367 | | | $ | 137 | | | $ | 225 | | | $ | 3,729 | |
| Interest Expense | | $ | 35,831 | | | $ | 26,328 | | | $ | 30,853 | | | $ | 27 | | | $ | 93,039 | | | $ | 2,152 | | | $ | (1,245 | ) | | $ | 93,946 | |
| Depreciation, Depletion and Amortization | | $ | 40,370 | | | $ | 35,930 | | | $ | 106,182 | | | $ | 42 | | | $ | 182,524 | | | $ | 7,907 | | | $ | 768 | | | $ | 191,199 | |
| Income Tax Expense (Benefit) | | $ | 31,858 | | | $ | 22,634 | | | $ | 78,875 | | | $ | 4,806 | | | $ | 138,173 | | | $ | 464 | | | $ | (1,410 | ) | | $ | 137,227 | |
| Income from Unconsolidated Subsidiaries | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 2,488 | | | $ | — | | | $ | 2,488 | |
| Segment Profit: Income (Loss) from Continuing Operations | | $ | 62,473 | | | $ | 36,703 | | | $ | 112,531 | | | $ | 8,816 | | | $ | 220,523 | | | $ | 3,396 | | | $ | (4,786 | ) | | $ | 219,133 | |
Expenditures for Additions toLong-Lived Assets from Continuing Operations | | $ | 57,973 | | | $ | 37,894 | | | $ | 398,174 | | | $ | 407 | | | $ | 494,448 | | | $ | 6,694 | | | $ | 210 | | | $ | 501,352 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | At September 30, 2010 |
| | | (Thousands) |
| Segment Assets | | $ | 2,071,530 | | | $ | 1,094,914 | | | $ | 1,539,705 | | | $ | 69,561 | | | $ | 4,775,710 | | | $ | 198,706 | | | $ | 131,209 | | | $ | 5,105,625 | |
117
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30, 2009 |
| | | | | | | | | | | | | | | Corporate
| | |
| | | | | Pipeline
| | Exploration
| | | | Total
| | | | and
| | |
| | | | | and
| | and
| | Energy
| | Reportable
| | All
| | Intersegment
| | Total
|
| | | Utility | | Storage | | Production | | Marketing | | Segments | | Other | | Eliminations | | Consolidated |
| | | (Thousands) |
| |
| Revenue from External Customers | | $ | 1,097,550 | | | $ | 137,478 | | | $ | 382,758 | | | $ | 397,763 | | | $ | 2,015,549 | | | $ | 35,100 | | | $ | 894 | | | $ | 2,051,543 | |
| Intersegment Revenues | | $ | 15,474 | | | $ | 81,795 | | | $ | — | | | $ | 558 | | | $ | 97,827 | | | $ | — | | | $ | (97,827 | ) | | $ | — | |
| Interest Income | | $ | 2,486 | | | $ | 995 | | | $ | 2,430 | | | $ | 79 | | | $ | 5,990 | | | $ | 583 | | | $ | (797 | ) | | $ | 5,776 | |
| Interest Expense | | $ | 32,417 | | | $ | 21,580 | | | $ | 33,368 | | | $ | 215 | | | $ | 87,580 | | | $ | 2,344 | | | $ | (3,135 | ) | | $ | 86,789 | |
| Depreciation, Depletion and Amortization | | $ | 39,675 | | | $ | 35,115 | | | $ | 90,816 | | | $ | 42 | | | $ | 165,648 | | | $ | 4,276 | | | $ | 696 | | | $ | 170,620 | |
| Income Tax Expense (Benefit) | | $ | 37,097 | | | $ | 30,579 | | | $ | (14,616 | ) | | $ | 4,470 | | | $ | 57,530 | | | $ | (3,482 | ) | | $ | (1,189 | ) | | $ | 52,859 | |
| Income from Unconsolidated Subsidiaries | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 3,366 | | | $ | — | | | $ | 3,366 | |
| Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | | $ | — | | | $ | — | | | $ | 182,811 | | | $ | — | | | $ | 182,811 | | | $ | — | | | $ | — | | | $ | 182,811 | |
| Significant Non-Cash Item: Impairment of Investment in Partnership | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,804 | (1) | | $ | — | | | $ | 1,804 | |
| Segment Profit: Income (Loss) from Continuing Operations | | $ | 58,664 | | | $ | 47,358 | | | $ | (10,238 | ) | | $ | 7,166 | | | $ | 102,950 | | | $ | 705 | | | $ | (171 | ) | | $ | 103,484 | |
| Expenditures for Additions to Long-Lived Assets from Continuing Operations | | $ | 56,178 | | | $ | 52,504 | | | $ | 223,223 | (2) | | $ | 25 | | | $ | 331,930 | | | $ | 9,507 | | | $ | (47 | ) | | $ | 341,390 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | At September 30, 2009 |
| | | (Thousands) |
| |
| Segment Assets | | $ | 2,132,610 | | | $ | 1,046,372 | | | $ | 1,265,678 | | | $ | 52,469 | | | $ | 4,497,129 | | | $ | 210,809 | (3) | | $ | 61,191 | | | $ | 4,769,129 | |
| | |
| (1) | | Amount represents the impairment in the value of the Company’s 50% investment in ESNE, a partnership that owns an 80-megawatt, combined cycle, natural gas-fired power plant in the town of North East, Pennsylvania. |
|
| (2) | | Amount includes the acquisition of Ivanhoe Energy’s United States oil and gas operation for $34.9 million, net of cash acquired, and is discussed in Note M — Acquisition. |
|
| (3) | | Amount includes $28,761 of assets of the Company’s landfill gas operations, which have been classified as discontinued operations as of September 30, 2010. (See Note J — Discontinued Operations). |
118
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30, 2008 |
| | | | | | | | | | | | | | | Corporate
| | |
| | | | | Pipeline
| | Exploration
| | | | Total
| | | | and
| | |
| | | | | and
| | and
| | Energy
| | Reportable
| | All
| | Intersegment
| | Total
|
| | | Utility | | Storage | | Production | | Marketing | | Segments | | Other | | Eliminations | | Consolidated |
| | | (Thousands) |
| |
| Revenue from External Customers | | $ | 1,194,657 | | | $ | 135,052 | | | $ | 466,760 | | | $ | 549,932 | | | $ | 2,346,401 | | | $ | 49,741 | | | $ | 695 | | | $ | 2,396,837 | |
| Intersegment Revenues | | $ | 15,612 | | | $ | 81,504 | | | $ | — | | | $ | 1,300 | | | $ | 98,416 | | | $ | 9 | | | $ | (98,425 | ) | | $ | — | |
| Interest Income | | $ | 1,836 | | | $ | 843 | | | $ | 10,921 | | | $ | 323 | | | $ | 13,923 | | | $ | 1,232 | | | $ | (4,340 | ) | | $ | 10,815 | |
| Interest Expense | | $ | 27,683 | | | $ | 13,783 | | | $ | 41,645 | | | $ | 175 | | | $ | 83,286 | | | $ | 3,183 | | | $ | (13,099 | ) | | $ | 73,370 | |
| Depreciation, Depletion and Amortization | | $ | 39,113 | | | $ | 32,871 | | | $ | 92,221 | | | $ | 42 | | | $ | 164,247 | | | $ | 4,910 | | | $ | 689 | | | $ | 169,846 | |
| Income Tax Expense (Benefit) | | $ | 36,303 | | | $ | 34,008 | | | $ | 92,686 | | | $ | 3,180 | | | $ | 166,177 | | | $ | 1,936 | | | $ | (441 | ) | | $ | 167,672 | |
| Income from Unconsolidated Subsidiaries | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 6,303 | | | $ | — | | | $ | 6,303 | |
| Segment Profit: Income (Loss) from Continuing Operations | | $ | 61,472 | | | $ | 54,148 | | | $ | 146,612 | | | $ | 5,889 | | | $ | 268,121 | | | $ | 3,958 | | | $ | (5,172 | ) | | $ | 266,907 | |
| Expenditures for Additions to Long-Lived Assets from Continuing Operations | | $ | 57,457 | | | $ | 165,520 | | | $ | 192,187 | | | $ | 39 | | | $ | 415,203 | | | $ | 1,354 | | | $ | (2,186 | ) | | $ | 414,371 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | At September 30, 2008 |
| | | (Thousands) |
| |
| Segment Assets | | $ | 1,643,665 | | | $ | 948,984 | | | $ | 1,416,120 | | | $ | 89,527 | | | $ | 4,098,296 | | | $ | 217,874 | (1) | | $ | (185,983 | ) | | $ | 4,130,187 | |
| | |
| (1) | | Amount includes $35,521 of assets of the Company’s landfill gas operations, which have been classified as discontinued operations as of September 30, 2010. (See Note J — Discontinued Operations). |
| | | | | | | | | | | | | |
| | | For the Year Ended September 30 | |
| Geographic Information | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
Revenues from External Customers(1): | | | | | | | | | | | | |
| United States | | $ | 1,760,503 | | | $ | 2,051,543 | | | $ | 2,396,837 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | At September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
Long-Lived Assets: | | | | | | | | | | | | |
| United States | | $ | 4,330,248 | | | $ | 3,963,398 | | | $ | 3,595,188 | |
| Assets of Discontinued Operations | | | — | | | | 28,761 | | | | 35,521 | |
| | | | | | | | | | | | | |
| | | $ | 4,330,248 | | | $ | 3,992,159 | | | $ | 3,630,709 | |
| | | | | | | | | | | | | |
| | |
| (1) | | Revenue is based upon the country in which the sale originates. This table excludes revenues from discontinued operations of $9,919, $6,309 and $3,524 for September 30, 2010, 2009 and 2008, respectively. |
Note L — Investments in Unconsolidated Subsidiaries
The Company’s unconsolidated subsidiaries consist of equity method investments in Seneca Energy, Model City, and ESNE. The Company has 50% interests in each of these entities. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE is an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania that is in the process of
119
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
being dismantled. The Company expects to recover its investment in ESNE through the sale of ESNE’s major assets, such as the turbines.
During the quarter ended December 31, 2008, the Company recorded a pre-tax impairment of $1.8 million ($1.1 million on an after-tax basis) of its equity investment in ESNE due to a decline in the fair market value of ESNE. The impairment was driven by a significant decrease in “run time” for the plant given the economic downturn and the resulting decrease in demand for electric power.
A summary of the Company’s investments in unconsolidated subsidiaries at September 30, 2010 and 2009 is as follows:
| | | | | | | | | |
| | | At September 30 | |
| | | 2010 | | | 2009 | |
| | | (Thousands) | |
| |
| Seneca Energy | | $ | 11,007 | | | $ | 10,924 | |
| Model City | | | 2,017 | | | | 2,136 | |
| ESNE | | | 1,804 | | | | 1,880 | |
| | | | | | | | | |
| | | $ | 14,828 | | | $ | 14,940 | |
| | | | | | | | | |
Note M — Acquisition
On July 20, 2009, the Company’s wholly-owned subsidiary in the Exploration and Production segment, Seneca, acquired all of the shares of Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million in cash (including cash acquired), of which $2.0 million was held in escrow at September 30, 2010 and 2009. Seneca placed this amount in escrow as part of the purchase price. Currently, the Company and Ivanhoe Energy are negotiating a final resolution to the issue of whether Ivanhoe Energy is entitled to some or all of the amount held in escrow. Ivanhoe Energy’s United States oil and gas operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on July 20, 2009. As of the acquisition date, these assets produced approximately 645 (595 net) barrels per day of oil in California and Texas. The purchase also included certain exploration acreage in California. This acquisition added to the Company’s existing oil producing assets in the Midway Sunset Field in California. The acquisition consisted of approximately $37.1 million in property, plant and equipment, $6.2 million of current assets (including $2.0 million of cash held in escrow), $0.3 million of current liabilities and $3.8 million of deferred credits. Details of the acquisition are as follows (all figures in thousands):
| | | | | |
| Assets Acquired | | $ | 43,282 | |
| Liabilities Assumed | | | (4,082 | ) |
| Cash Acquired at Acquisition | | | (4,267 | ) |
| | | | | |
| Cash Paid, Net of Cash Acquired | | $ | 34,933 | |
| | | | | |
Note N — Intangible Assets
As a result of the Empire and Toro acquisitions in 2003, the Company acquired certain intangible assets. In the case of the Empire acquisition, the intangible assets represent the fair value of various long-term transportation contracts with Empire’s customers. These intangible assets are being amortized over the lives of the transportation contracts with no residual value at the end of the amortization period. The weighted-average amortization period for the gross carrying amount of the transportation contracts is 8 years. In the case of the Toro acquisition, the intangible assets represented the fair value of various long-term gas purchase contracts with the various landfills. On September 1, 2010, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana and these operations have been presented
120
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
as discontinued operations in the Company’s financial statements as of September 30, 2010. Refer to Note J — Discontinued Operations for further details. Details of these intangible assets are as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| | | | | | At September 30,
| |
| | | At September 30, 2010 | | | 2009 | |
| | | Gross Carrying
| | | Accumulated
| | | Net Carrying
| | | Net Carrying
| |
| | | Amount | | | Amortization | | | Amount | | | Amount | |
| |
| Intangible Assets Subject to Amortization: | | | | | | | | | | | | | | | | |
| Long-Term Transportation Contracts | | $ | 4,701 | | | $ | (3,024 | ) | | $ | 1,677 | | | $ | 2,071 | |
| Long-Term Gas Purchase Contracts | | | — | | | | — | | | | — | | | | 19,465 | |
| | | | | | | | | | | | | | | | | |
| | | $ | 4,701 | | | $ | (3,024 | ) | | $ | 1,677 | | | $ | 21,536 | |
| | | | | | | | | | | | | | | | | |
| Aggregate Amortization Expense: | | | | | | | | | | | | | | | | |
| For the Year Ended September 30, 2010 | | $ | 394 | | | | | | | | | | | | | |
| For the Year Ended September 30, 2009 | | $ | 4,638 | (1) | | | | | | | | | | | | |
| For the Year Ended September 30, 2008 | | $ | 2,662 | (1) | | | | | | | | | | | | |
| | |
| (1) | | Amount includes amortization expense from discontinued operations of $4,186 and $1,593 for September 30, 2009 and 2008, respectively. At September 30, 2010, the 11 months of amortization expense for discontinued operations was $1,286. |
In September 2009, the Company recorded a pre-tax impairment of $4.6 million in the value of certain long-lived assets in the All Other category due to the loss of the primary customer at one of Toro’s landfill gas sites and the anticipated shut-down of the site. The impairment was comprised of a $2.6 million reduction in intangible assets related to long-term gas purchase contracts and a $2.0 million reduction in property, plant and equipment. The $2.6 million intangible assets impairment was recorded to Purchased Gas expense and the $2.0 million property, plant and equipment impairment was recorded to Depreciation, Depletion and Amortization expense on the Consolidated Statement of Income. The $2.6 million impairment of the intangible asset is included in amortization expense for the year ended September 30, 2009 in the table shown above. As noted above, the Company’s landfill gas operations were sold in September 2010 and have been presented as discontinued operations on the Company’s financial statements. Therefore, this impairment has been included in discontinued operations.
In conjunction with the sale of the Company’s landfill gas operations, the carrying amount of intangible assets subject to amortization related to the long-term gas purchase contracts was reduced from a $31.9 million gross carrying amount ($19.5 million net carrying amount) at September 30, 2009 to zero at September 30, 2010. Aside from this change, the only activity with regard to intangible assets subject to amortization was amortization expense as shown in the table above. Amortization expense for the long-term transportation contracts is estimated to be $0.4 million annually for 2011, 2012, 2013 and 2014 and $0.1 million in 2015.
121
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note O — Quarterly Financial Data (unaudited)
In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Per common share amounts are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statements of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Net
| | Earnings from
| | | | |
| | | | | | | Income
| | Income
| | Income
| | Continuing
| | | | |
| | | | | | | (Loss) from
| | (Loss) from
| | (Loss)
| | Operations per
| | Earnings per
|
Quarter
| | Operating
| | Operating
| | Continuing
| | Discontinued
| | Available for
| | Common Share | | Common Share |
| Ended | | Revenues | | Income (Loss) | | Operations | | Operations | | Common Stock | | Basic | | Diluted | | Basic | | Diluted |
| | | (Thousands, except per common share amounts) |
| |
2010 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 9/30/2010 | | $ | 286,396 | | | $ | 73,995 | | | $ | 32,393 | | | $ | 6,009 | (1) | | $ | 38,402 | (1) | | $ | 0.40 | | | $ | 0.39 | | | $ | 0.47 | | | $ | 0.46 | |
| 6/30/2010 | | $ | 351,992 | | | $ | 89,188 | | | $ | 42,641 | | | $ | (57 | ) | | $ | 42,584 | | | $ | 0.52 | | | $ | 0.51 | | | $ | 0.52 | | | $ | 0.51 | |
| 3/31/2010 | | $ | 667,980 | | | $ | 151,631 | | | $ | 79,874 | | | $ | 554 | | | $ | 80,428 | | | $ | 0.98 | | | $ | 0.96 | | | $ | 0.99 | | | $ | 0.97 | |
| 12/31/2009 | | $ | 454,135 | | | $ | 125,637 | | | $ | 64,225 | | | $ | 274 | | | $ | 64,499 | | | $ | 0.80 | | | $ | 0.78 | | | $ | 0.80 | | | $ | 0.78 | |
2009 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 9/30/2009 | | $ | 276,795 | | | $ | 68,943 | | | $ | 29,943 | | | $ | (2,945 | )(2) | | $ | 26,998 | (2) | | $ | 0.37 | | | $ | 0.37 | | | $ | 0.34 | | | $ | 0.33 | |
| 6/30/2009 | | $ | 365,579 | | | $ | 87,472 | | | $ | 43,061 | | | $ | (157 | ) | | $ | 42,904 | | | $ | 0.54 | | | $ | 0.53 | | | $ | 0.54 | | | $ | 0.53 | |
| 3/31/2009 | | $ | 803,049 | | | $ | 137,818 | | | $ | 73,270 | | | $ | 214 | | | $ | 73,484 | | | $ | 0.92 | | | $ | 0.92 | | | $ | 0.92 | | | $ | 0.92 | |
| 12/31/2008 | | $ | 606,120 | | | $ | (66,639 | ) | | $ | (42,790 | )(3) | | $ | 112 | | | $ | (42,678 | )(3) | | $ | (0.54 | ) | | $ | (0.53 | ) | | $ | (0.54 | ) | | $ | (0.53 | ) |
| | |
| (1) | | Includes a $6.3 million gain on the sale of the Company’s landfill gas operations. |
|
| (2) | | Includes a non-cash $4.6 million impairment charge ($2.8 million after tax) associated with landfill gas assets. |
|
| (3) | | Includes a non-cash $182.8 million impairment charge ($108.2 million after tax) associated with the Exploration and Production segment’s oil and gas producing properties; a non-cash $1.8 million impairment charge ($1.1 million after tax) associated with an equity investment in the All Other category and a $2.3 million gain realized on life insurance policies in the Corporate category. |
Note P — Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 2010, there were 15,549 registered shareholders of Company common stock. The common stock is listed and traded on the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note E — Capitalization and Short-Term Borrowings. The quarterly price
122
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
ranges (based onintra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 2010 and 2009, are shown below:
| | | | | | | | | | | | | |
| | | Price Range | | |
| Quarter Ended | | High | | Low | | Dividends Declared |
| |
2010 | | | | | | | | | | | | |
| 9/30/2010 | | $ | 52.29 | | | $ | 42.83 | | | $ | .345 | |
| 6/30/2010 | | $ | 54.42 | | | $ | 44.27 | | | $ | .345 | |
| 3/31/2010 | | $ | 52.48 | | | $ | 45.64 | | | $ | .335 | |
| 12/31/2009 | | $ | 52.00 | | | $ | 43.62 | | | $ | .335 | |
2009 | | | | | | | | | | | | |
| 9/30/2009 | | $ | 48.30 | | | $ | 33.77 | | | $ | .335 | |
| 6/30/2009 | | $ | 37.61 | | | $ | 29.83 | | | $ | .335 | |
| 3/31/2009 | | $ | 34.34 | | | $ | 26.67 | | | $ | .325 | |
| 12/31/2008 | | $ | 41.99 | | | $ | 26.83 | | | $ | .325 | |
Note Q — Supplementary Information for Oil and Gas Producing Activities (unaudited)
As of September 30, 2010, the Company adopted the revisions to authoritative guidance related to oil and gas exploration and production activities that aligned the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also adopted. The new SEC rules require companies to value their year-end reserves using an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve month period prior to the end of the reporting period.
The following supplementary information is presented in accordance with the authoritative guidance regarding disclosures about oil and gas producing activities and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars.
Capitalized Costs Relating to Oil and Gas Producing Activities
| | | | | | | | | |
| | | At September 30 | |
| | | 2010 | | | 2009 | |
| | | (Thousands) | |
| |
| Proved Properties(1) | | $ | 2,267,009 | | | $ | 1,953,720 | |
| Unproved Properties | | | 151,232 | | | | 70,061 | |
| | | | | | | | | |
| | | | 2,418,241 | | | | 2,023,781 | |
| Less — Accumulated Depreciation, Depletion and Amortization | | | 1,094,377 | | | | 990,284 | |
| | | | | | | | | |
| | | $ | 1,323,864 | | | $ | 1,033,497 | |
| | | | | | | | | |
| | |
| (1) | | Includes asset retirement costs of $69.8 million and $65.9 million at September 30, 2010 and 2009, respectively. |
Costs related to unproved properties are excluded from amortization 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
123
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
capitalized costs being amortized. Following is a summary of costs excluded from amortization at September 30, 2010:
| | | | | | | | | | | | | | | | | | | | | |
| | | Total
| | | | | | | | | | | | | |
| | | as of
| | | | | | | | | | | | | |
| | | September 30,
| | | Year Costs Incurred | |
| | | 2010 | | | 2010 | | | 2009 | | | 2008 | | | Prior | |
| | | (Thousands) | |
| |
| Acquisition Costs | | $ | 131,039 | | | $ | 75,130 | | | $ | 40,978 | | | $ | 6,135 | | | $ | 8,796 | |
| Development Costs | | | 12,120 | | | | 12,120 | | | | — | | | | — | | | | — | |
| Exploration Costs | | | 7,017 | | | | 7,017 | | | | — | | | | — | | | | — | |
| Capitalized Interest | | | 1,056 | | | | 1,056 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| | | $ | 151,232 | (1) | | $ | 95,323 | | | $ | 40,978 | | | $ | 6,135 | | | $ | 8,796 | |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Costs related to unproved properties excluded from amortization includes $137.2 million related to onshore properties and $14.0 million related to offshore properties at September 30, 2010. |
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
United States | | | | | | | | | | | | |
| Property Acquisition Costs: | | | | | | | | | | | | |
| Proved | | $ | 790 | | | $ | 35,803 | | | $ | 16,474 | |
| Unproved | | | 80,221 | | | | 44,528 | | | | 8,449 | |
| Exploration Costs | | | 75,155 | (1) | | | 11,724 | | | | 56,274 | |
| Development Costs | | | 234,094 | (2) | | | 125,109 | | | | 106,975 | |
| Asset Retirement Costs | | | 3,901 | | | | 2,877 | | | | 20,048 | |
| | | | | | | | | | | | | |
| | | $ | 394,161 | | | $ | 220,041 | | | $ | 208,220 | |
| | | | | | | | | | | | | |
| | |
| (1) | | Amount for 2010 includes $0.2 million of capitalized interest. |
|
| (2) | | Amount for 2010 includes $0.9 million of capitalized interest. |
For the years ended September 30, 2010, 2009 and 2008, the Company spent $28.9 million, $24.2 million and $25.4 million, respectively, developing proved undeveloped reserves.
124
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Results of Operations for Producing Activities
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands, except per Mcfe amounts) | |
| |
United States | | | | | | | | | | | | |
| Operating Revenues: | | | | | | | | | | | | |
| Natural Gas (includes revenues from sales to affiliates of $253, $239 and $443, respectively) | | $ | 152,163 | | | $ | 106,815 | | | $ | 216,623 | |
| Oil, Condensate and Other Liquids | | | 233,569 | | | | 174,356 | | | | 305,887 | |
| | | | | | | | | | | | | |
| Total Operating Revenues(1) | | | 385,732 | | | | 281,171 | | | | 522,510 | |
| Production/Lifting Costs | | | 61,398 | | | | 53,957 | | | | 55,335 | |
| Franchise/Ad Valorem Taxes | | | 10,592 | | | | 8,657 | | | | 11,350 | |
| Accretion Expense | | | 5,444 | | | | 5,437 | | | | 4,056 | |
| Depreciation, Depletion and Amortization ($2.10, $2.10 and $2.23 per Mcfe of production) | | | 104,092 | | | | 89,307 | | | | 91,093 | |
| Impairment of Oil and Gas Producing Properties(2) | | | — | | | | 182,811 | | | | — | |
| Income Tax Expense (Benefit) | | | 83,946 | | | | (27,055 | ) | | | 144,922 | |
| | | | | | | | | | | | | |
| Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | | $ | 120,260 | | | $ | (31,943 | ) | | $ | 215,754 | |
| | | | | | | | | | | | | |
| | |
| (1) | | Exclusive of hedging gains and losses. See further discussion in Note G — Financial Instruments. |
|
| (2) | | See discussion of impairment in Note A — Summary of Significant Accounting Policies. |
Reserve Quantity Information
The Company’s proved oil and gas reserves are located in the United States. The Company’s proved oil and gas reserve estimates are prepared by the Company’s reservoir engineers who meet the qualifications of Reserve Estimator per the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance.
The Company’s Vice President of Reservoir Engineering is the primary technical person responsible for overseeing the Company’s reserve estimation process and engaging and overseeing the third party reserve audit. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 25 years of Petroleum Engineering experience with both major and independent oil and gas companies. He has maintained oversight of the Company’s reserve estimation process for the past seven years. He is a member of the Society of Petroleum Engineers and a Registered Professional Engineer in the State of Texas.
The Company maintains a system of internal controls over the reserve estimation process. Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model to determine the reserves. The Vice President of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions. Access to the Reserve database is restricted. Significant changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the Company’s internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls.
All of the Company’s reserve estimates are audited annually by Netherland, Sewell and Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve
125
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
quantities in the United States and internationally under the Texas Board of Professional Engineers RegistrationNo. F-002699. The primary technical persons (employed by NSAI) that are responsible for leading the audit include an engineer registered with the State of Texas (with 12 years of experience in petroleum engineering and six years of experience in the estimation and evaluation of reserves) and a Certified Petroleum Geologist and Geophysicist in the State of Texas (with 32 years of experience in petroleum geosciences and 21 years of experience in the estimation and evaluation of reserves).
The reliable technologies that were utilized in estimating the reserves include wire line open-hole log data, performance data, log cross sections, core data, and statistical analysis. The statistical method utilized production performance from both the Company’s and competitor’s wells. Geophysical data include data from the Company’s wells, published documents, and state data-sites and were used to confirm continuity of the formation. Extension and discovery reserves added as a result of reliable technologies were not material.
| | | | | | | | | | | | | | | | | |
| | | Gas MMcf | |
| | | U. S. | | | | |
| | | Gulf
| | | West
| | | | | | | |
| | | Coast
| | | Coast
| | | Appalachian
| | | Total
| |
| | | Region | | | Region | | | Region | | | Company | |
| |
| Proved Developed and Undeveloped Reserves: | | | | | | | | | | | | | | | | |
| September 30, 2007 | | | 25,136 | | | | 73,175 | | | | 107,078 | | | | 205,389 | |
| Extensions and Discoveries | | | 8,759 | | | | — | | | | 31,322 | | | | 40,081 | |
| Revisions of Previous Estimates | | | 2,156 | | | | 566 | | | | (3,460 | ) | | | (738 | ) |
| Production | | | (11,033 | ) | | | (4,039 | ) | | | (7,269 | ) | | | (22,341 | ) |
| Purchases of Minerals in Place | | | — | | | | 4,539 | | | | 727 | | | | 5,266 | |
| Sales of Minerals in Place | | | (377 | ) | | | (1,381 | ) | | | — | | | | (1,758 | ) |
| | | | | | | | | | | | | | | | | |
| September 30, 2008 | | | 24,641 | | | | 72,860 | | | | 128,398 | | | | 225,899 | |
| Extensions and Discoveries | | | 6,698 | | | | 3,282 | | | | 49,249 | | | | 59,229 | |
| Revisions of Previous Estimates | | | 9,407 | | | | 488 | | | | (19,484 | ) | | | (9,589 | )(1) |
| Production | | | (9,886 | ) | | | (4,063 | ) | | | (8,335 | ) | | | (22,284 | ) |
| Purchases of Minerals in Place | | | — | | | | 392 | | | | — | | | | 392 | |
| Sales of Minerals in Place | | | (4,693 | ) | | | — | | | | — | | | | (4,693 | ) |
| | | | | | | | | | | | | | | | | |
| September 30, 2009 | | | 26,167 | | | | 72,959 | | | | 149,828 | | | | 248,954 | |
| Extensions and Discoveries | | | 2,881 | | | | 269 | | | | 189,979 | (2) | | | 193,129 | |
| Revisions of Previous Estimates | | | 6,683 | | | | 2,315 | | | | 7,677 | | | | 16,675 | |
| Production | | | (10,304 | ) | | | (3,819 | ) | | | (16,222 | )(3) | | | (30,345 | ) |
| | | | | | | | | | | | | | | | | |
| September 30, 2010 | | | 25,427 | | | | 71,724 | | | | 331,262 | | | | 428,413 | |
| | | | | | | | | | | | | | | | | |
126
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | |
| | | Gas MMcf | |
| | | U. S. | | | | |
| | | Gulf
| | | West
| | | | | | | |
| | | Coast
| | | Coast
| | | Appalachian
| | | Total
| |
| | | Region | | | Region | | | Region | | | Company | |
| |
| Proved Developed Reserves: | | | | | | | | | | | | | | | | |
| September 30, 2007 | | | 25,136 | | | | 66,017 | | | | 96,674 | | | | 187,827 | |
| September 30, 2008 | | | 18,242 | | | | 68,453 | | | | 115,824 | | | | 202,519 | |
| September 30, 2009 | | | 18,051 | | | | 67,603 | | | | 120,579 | | | | 206,233 | |
| September 30, 2010 | | | 19,293 | | | | 66,178 | | | | 210,817 | | | | 296,288 | |
| Proved Undeveloped Reserves: | | | | | | | | | | | | | | | | |
| September 30, 2007 | | | — | | | | 7,158 | | | | 10,404 | | | | 17,562 | |
| September 30, 2008 | | | 6,399 | | | | 4,407 | | | | 12,574 | | | | 23,380 | |
| September 30, 2009 | | | 8,116 | | | | 5,356 | | | | 29,249 | | | | 42,721 | |
| September 30, 2010 | | | 6,134 | | | | 5,546 | | | | 120,445 | | | | 132,125 | |
| | |
| (1) | | During 2009, the Company made a downward revision of its proved developed and undeveloped reserves amounting to 9,589 MMcf. This was primarily attributable to a 19,484 MMcf reduction in the Appalachian region offset by a 9,407 MMcf increase in the Gulf Coast region. The reduction in the Appalachian region was mainly due to declining natural gas prices, which made certain reserves uneconomical. The improvement in the Gulf Coast region was due to improved performance of Gulf Coast properties. |
|
| (2) | | Extensions and discoveries include 182 Bcf of Marcellus Shale gas in the Appalachian Region. |
|
| (3) | | Production includes 7,180 MMcf from Marcellus Shale fields (which exceed 15% of total reserves). |
127
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | |
| | | Oil Mbbl | |
| | | U. S. | | | | |
| | | Gulf
| | | West
| | | | | | | |
| | | Coast
| | | Coast
| | | Appalachian
| | | Total
| |
| | | Region | | | Region | | | Region | | | Company | |
| |
| Proved Developed and Undeveloped Reserves: | | | | | | | | | | | | | | | | |
| September 30, 2007 | | | 1,435 | | | | 45,644 | | | | 507 | | | | 47,586 | |
| Extensions and Discoveries | | | 298 | | | | 471 | | | | 58 | | | | 827 | |
| Revisions of Previous Estimates | | | 203 | | | | (34 | ) | | | (64 | ) | | | 105 | |
| Production | | | (505 | ) | | | (2,460 | )(1) | | | (105 | ) | | | (3,070 | ) |
| Purchases of Minerals in Place | | | — | | | | 2,084 | | | | — | | | | 2,084 | |
| Sales of Minerals in Place | | | (73 | ) | | | (1,261 | ) | | | — | | | | (1,334 | ) |
| | | | | | | | | | | | | | | | | |
| September 30, 2008 | | | 1,358 | | | | 44,444 | | | | 396 | | | | 46,198 | |
| Extensions and Discoveries | | | 302 | | | | 896 | | | | 15 | | | | 1,213 | |
| Revisions of Previous Estimates | | | 447 | | | | 43 | | | | (41 | ) | | | 449 | |
| Production | | | (640 | ) | | | (2,674 | )(1) | | | (59 | ) | | | (3,373 | ) |
| Purchases of Minerals in Place | | | — | | | | 2,115 | | | | — | | | | 2,115 | |
| Sales of Minerals in Place | | | (15 | ) | | | — | | | | — | | | | (15 | ) |
| | | | | | | | | | | | | | | | | |
| September 30, 2009 | | | 1,452 | | | | 44,824 | | | | 311 | | | | 46,587 | |
| Extensions and Discoveries | | | 222 | | | | 828 | | | | 4 | | | | 1,054 | |
| Revisions of Previous Estimates | | | 332 | | | | 484 | | | | 2 | | | | 818 | |
| Production | | | (502 | ) | | | (2,669 | )(1) | | | (49 | ) | | | (3,220 | ) |
| | | | | | | | | | | | | | | | | |
| September 30, 2010 | | | 1,504 | | | | 43,467 | | | | 268 | | | | 45,239 | |
| | | | | | | | | | | | | | | | | |
| Proved Developed Reserves: | | | | | | | | | | | | | | | | |
| September 30, 2007 | | | 1,435 | | | | 36,509 | | | | 483 | | | | 38,427 | |
| September 30, 2008 | | | 1,313 | | | | 37,224 | | | | 357 | | | | 38,894 | |
| September 30, 2009 | | | 1,194 | | | | 37,711 | | | | 285 | | | | 39,190 | |
| September 30, 2010 | | | 1,066 | | | | 36,353 | | | | 263 | | | | 37,682 | |
| Proved Undeveloped Reserves: | | | | | | | | | | | | | | | | |
| September 30, 2007 | | | — | | | | 9,135 | | | | 24 | | | | 9,159 | |
| September 30, 2008 | | | 45 | | | | 7,220 | | | | 39 | | | | 7,304 | |
| September 30, 2009 | | | 258 | | | | 7,113 | | | | 26 | | | | 7,397 | |
| September 30, 2010 | | | 438 | | | | 7,114 | | | | 5 | | | | 7,557 | |
| | |
| (1) | | The Midway Sunset North fields (which exceed 15% of total reserves) contributed 1,583 Mbbls, 1,680 Mbbls, and 1,543 Mbbls of production during 2008, 2009, and 2010, respectively. |
The Company’s proved undeveloped (PUD) reserves increased from 87 Bcfe at September 30, 2009 to 177 Bcfe at September 30, 2010. Undeveloped reserves in the Marcellus Shale increased from 11 Bcf at September 30, 2009 to 110 Bcf at September 30, 2010. There was a material increase in undeveloped reserves at September 30, 2010 as a result of its Marcellus Shale reserve additions. The increase in undeveloped reserves in the Marcellus Shale is partially attributable to the change in SEC regulations allowing the recognition of PUD reserves more than one direct offset location away from existing production with reasonable certainty using reliable technology. The Company’s total PUD reserves are 25% of total proved reserves at September 30, 2010, up from 16% of total proved reserves at September 30, 2009.
128
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The increase in PUD reserves in 2010 of 90 Bcfe is a result of 111 Bcfe in new PUD reserve additions (105 Bcfe from the Marcellus Shale), offset by 17 Bcfe in PUD conversions to developed reserves and 4 Bcfe in downward PUD revisions. The downward revisions were primarily from the removal of 51 PUD locations in the Upper Devonian play. This was the result of Seneca’s decision in 2010 to significantly reduce its5-year investment plan for the Upper Devonian as a result of lower forward gas price expectations. The Company invested $28.9 million during the year ended September 30, 2010 to convert 17 Bcfe of PUD reserves to developed reserves. This represents 19% of the PUD reserves booked at September 30, 2009. In 2011, the Company estimates that it will invest approximately $140 million to develop the PUD reserves. The Company is committed to developing its PUD reserves within five years of being recorded as PUD reserves as required by the SEC’s final rule on Modernization of Oil and Gas Reporting.
At September 30, 2010, the Company does not have a material concentration of proved undeveloped reserves that have been on the books for more than five years at the corporate level or country level. All of the Company’s proved reserves are in the United States. At the field level, only at the North Lost Hills Field in Kern County, California, does the Company have a material concentration of undeveloped reserves that have been on the books for more than five years. The Company has reduced the concentration of undeveloped reserves in this field from 61% of total field level reserves at September 30, 2005 to 24% of total field level reserves at September 30, 2010. The Company has been actively drilling undeveloped locations in this field for four out of the past five years, drilling 53 undeveloped locations and converting 3.1 million barrels of proved reserves from undeveloped to developed reserves. The undeveloped reserves in this field represent less than 2% of the Company’s proved reserves at the corporate level. The Company is committed to drilling the remaining proved undeveloped locations within five years of being recorded as PUD reserves.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, as a result of the SEC’s final rule on Modernization of Oil and Gas Reporting (effective fiscal 2010), it is based on the unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period and costs adjusted only for existing contractual changes. It assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.
129
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
United States | | | | | | | | | | | | |
| Future Cash Inflows | | $ | 5,273,605 | | | $ | 3,972,026 | | | $ | 5,845,214 | |
| Less: | | | | | | | | | | | | |
| Future Production Costs | | | 1,347,855 | | | | 1,010,851 | | | | 1,231,705 | |
| Future Development Costs | | | 445,413 | | | | 312,717 | | | | 265,515 | |
| Future Income Tax Expense at Applicable Statutory Rate | | | 1,186,567 | | | | 916,466 | | | | 1,645,351 | |
| | | | | | | | | | | | | |
| Future Net Cash Flows | | | 2,293,770 | | | | 1,731,992 | | | | 2,702,643 | |
| Less: | | | | | | | | | | | | |
| 10% Annual Discount for Estimated Timing of Cash Flows | | | 1,120,182 | | | | 856,015 | | | | 1,434,799 | |
| | | | | | | | | | | | | |
| Standardized Measure of Discounted Future Net Cash Flows | | $ | 1,173,588 | | | $ | 875,977 | | | $ | 1,267,844 | |
| | | | | | | | | | | | | |
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (Thousands) | |
| |
United States | | | | | | | | | | | | |
| Standardized Measure of Discounted Future | | | | | | | | | | | | |
| Net Cash Flows at Beginning of Year | | $ | 875,977 | | | $ | 1,267,844 | | | $ | 1,060,462 | |
| Sales, Net of Production Costs | | | (313,742 | ) | | | (218,557 | ) | | | (455,825 | ) |
| Net Changes in Prices, Net of Production Costs | | | 176,530 | | | | (699,217 | ) | | | 509,705 | |
| Purchases of Minerals in Place | | | — | | | | 38,902 | | | | 67,768 | |
| Sales of Minerals in Place | | | — | | | | (20,141 | ) | | | (31,642 | ) |
| Extensions and Discoveries | | | 329,555 | | | | 66,002 | | | | 143,394 | |
| Changes in Estimated Future Development Costs | | | (17,353 | ) | | | (22,392 | ) | | | (100,684 | ) |
| Previously Estimated Development Costs Incurred | | | 47,539 | | | | 53,285 | | | | 65,156 | |
| Net Change in Income Taxes at Applicable Statutory Rate | | | (85,703 | ) | | | 331,251 | | | | (119,585 | ) |
| Revisions of Previous Quantity Estimates | | | 46,246 | | | | (27,864 | ) | | | (3,936 | ) |
| Accretion of Discount and Other | | | 114,539 | | | | 106,864 | | | | 133,031 | |
| | | | | | | | | | | | | |
| Standardized Measure of Discounted Future Net Cash Flows at End of Year | | $ | 1,173,588 | | | $ | 875,977 | | | $ | 1,267,844 | |
| | | | | | | | | | | | | |
130
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | Additions
| | | | | | | | | | |
| | | Balance
| | | Charged
| | | Additions
| | | | | | Balance
| |
| | | at
| | | to
| | | Charged
| | | | | | at
| |
| | | Beginning
| | | Costs
| | | to
| | | | | | End
| |
| | | of
| | | and
| | | Other
| | | | | | of
| |
| Description | | Period | | | Expenses | | | Accounts(1) | | | Deductions(2) | | | Period | |
| |
Year Ended September 30, 2010 | | | | | | | | | | | | | | | | | | | | |
| Allowance for Uncollectible Accounts | | $ | 38,334 | | | $ | 15,422 | | | $ | 2,268 | | | $ | 25,063 | | | $ | 30,961 | |
| | | | | | | | | | | | | | | | | | | | | |
Year Ended September 30, 2009 | | | | | | | | | | | | | | | | | | | | |
| Allowance for Uncollectible Accounts | | $ | 33,117 | | | $ | 31,464 | | | $ | 2,751 | | | $ | 28,998 | | | $ | 38,334 | |
| | | | | | | | | | | | | | | | | | | | | |
Year Ended September 30, 2008 | | | | | | | | | | | | | | | | | | | | |
| Allowance for Uncollectible Accounts | | $ | 28,654 | | | $ | 27,274 | | | $ | 2,734 | | | $ | 25,545 | | | $ | 33,117 | |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate agreement. |
|
| (2) | | Amounts represent net accounts receivable written-off. |
| |
| Item 9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None
| |
| Item 9A | Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
The term “disclosure controls and procedures” is defined inRules 13a-15(e) and15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2010.
Management’s Annual Report on Internal Control over Financial Reporting
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined inRules 13a-15(f) and15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2010. In making this assessment, management used the framework and criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control — Integrated Framework.Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of September 30, 2010.
131
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this Annual Report onForm 10-K, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2010. The report appears in Part II, Item 8 of this Annual Report onForm 10-K.
Changes in Internal Control over Financial Reporting
On October 1, 2010, the Company replaced The Northern Trust Company with JPMorgan Chase Bank, NA as trustee and custodian of assets held in trust for the beneficiaries of the Company’s qualified defined-benefit retirement plan and other post-retirement benefit plans. The change in trustee is a result of an appraisal by the Company’s Retirement Committee of outsourced trust and custodial services and is not the result of any actual or perceived deficiencies in internal controls at the previous trustee. The impact of the change, including the transfer of trust assets on October 1, 2010, has been evaluated by management and adequately incorporated into management’s ongoing monitoring of internal controls over financial reporting.
On November 1, 2010, Seneca implemented Quorum Business Solutions software as its Enterprise Resource Planning Accounting System and Land/Geographical Information System to help support the growth of the Exploration and Production segment. These system changes are a result of an evaluation of the previous accounting and land systems and related processes to support evolving needs and are not the result of any actual or perceived deficiencies in the previous systems. These implementations resulted in certain changes to Seneca’s processes and internal controls impacting financial reporting. While there are inherent risks involved with the implementation of any new system, management believes that it is adequately monitoring and managing the transition.
There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, 2010 and no changes through the filing date of this Annual Report onForm 10-K with the SEC, other than the changes that occurred on October 1, 2010 and November 1, 2010, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
None
PART III
| |
| Item 10 | Directors, Executive Officers and Corporate Governance |
The information required by this item concerning the directors of the Company and corporate governance is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 2011 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2010. The information concerning directors will be set forth in the definitive Proxy Statement under the headings entitled “Nominees for Election as Directors for Three-Year Terms to Expire in 2014,” “Directors Whose Terms Expire in 2013,” “Directors Whose Terms Expire in 2012,” and “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated herein by reference. The information concerning corporate governance will be set forth in the definitive Proxy Statement under the heading entitled “Meetings of the Board of Directors and Standing Committees” and is incorporated herein by reference. Information concerning the Company’s executive officers can be found in Part I, Item 1, of the Company’s Form 10-K for the fiscal year ended September 30, 2008, filed November 26, 2008.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCEthis report.
Section 16(a) of the Securities Exchange Act of 1934, as amended (the “Securities Exchange Act”), requires the Company’s directors and officers, and persons who own more than 10% of a registered class of the Company’s equity securities, to file reports of ownership and changes in ownership with the SEC and the NYSE. Directors, officers and greater-than 10% stockholders are required
5
by SEC regulation to furnish the Company with copies of all Section 16(a) forms they file. Based solely on review of information furnished to the Company, reports filed through the Company and/or written representations that no Form 5 was required, the Company believes that all Section 16(a) filing requirements applicable to its officers, directors and greater-than 10% beneficial owners were complied with during fiscal 2008, except as described below.
A single Section 16(a) report (a Form 4) was filed late on November 13, 2008 by Director Stephen E. Ewing with regard to a single transaction that occurred on September 19, 2008 in which Mr. Ewing purchased 500 shares of Company stock on the open market through his brokerage account. That Form 4 was filed late due to an inadvertent lapse in communications among Mr. Ewing, his broker and the Company personnel who file Form 4s for the Company’s directors and executive officers. That Form 4 also amended a Form 4 filed October 2, 2008, in order to correct the cumulative total of his Company stock owned so as to include his September purchase.
CODE OF ETHICS
The Company has adopted a codeCode of ethicsBusiness Conduct and Ethics that applies to the Company’s directors, principal executive officer, principal financial officer, controller, other officers and employees that is designed to deter wrongdoing and to promote honesthas posted such Code of Business Conduct and ethical conduct. The text of the code of ethics is availableEthics on the Company’s website, at www.nationalfuelgas.com. Upon request, the Company will provide to any person without charge a copywww.nationalfuelgas.com, together with certain other corporate governance documents. Copies of the codeCompany’s Code of ethics. Requests mustBusiness Conduct and Ethics, charters of important committees, and Corporate Governance Guidelines will be made available free of charge upon written request to the Secretary at the principal offices of the Company.Investor Relations, National Fuel Gas Company, 6363 Main Street, Williamsville, New York 14221.
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The Company intends to satisfy the disclosure requirement under Item 5.05 ofForm 8-K regarding an amendment to, or a waiver from, a provision of its code of ethics that applies to the Company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, and that relates to any element of the code of ethics definition enumerated in paragraph (b) of Item 406 of the SEC’sRegulation S-K, by posting such information on its website, www.nationalfuelgas.com.
| |
| Item 11 | Executive Compensation |
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 2011 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2010. The information concerning executive compensation will be set forth in the definitive Proxy Statement under the headings “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation” and, excepting the “Report of the Compensation Committee,” is incorporated herein by reference.
| |
| Item 12 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
AUDIT COMMITTEEEquity Compensation Plan Information
The Company has a separately designated standing Audit Committee establishedinformation required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 2011 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2010. The equity compensation plan information will be set forth in accordance with Section 3(a)(58)(A) of the Securities Exchange Act. The members ofdefinitive Proxy Statement under the Audit Committee are R. Don Cash, Stephen E. Ewing, Rolland E. Kidder, Craig G. Matthews (Chair)heading “Equity Compensation Plan Information” and George L. Mazanec. The Company’s Board of Directors has determined that the Company has at least two audit committee financial experts (as definedis incorporated herein by SEC regulations) serving on its Audit Committee, namely Messrs. Matthews and Mazanec, both of whom are independent directors.reference.
Item 11Security Ownership and Changes in Control
Executive Compensation(a) Security Ownership of Certain Beneficial Owners
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 2011 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2010. The information concerning security ownership of certain beneficial owners will be set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
Compensation Committee Report(b) Security Ownership of Management
The Compensationinformation required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 2011 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2010. The information concerning security ownership of management will be set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
(c) Changes in Control
None
| |
| Item 13 | Certain Relationships and Related Transactions, and Director Independence |
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 2011 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2010. The information regarding certain relationships and related transactions will be set forth in the definitive Proxy Statement under the headings “Compensation Committee Interlocks and Insider Participation” and “Related Person Transactions” and is incorporated herein by reference. The information regarding director independence is set forth in the definitive Proxy Statement under the heading “Director Independence” and is incorporated herein by reference.
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| |
| Item 14 | Principal Accountant Fees and Services |
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 2011 Annual Meeting of Stockholders will be filed with the BoardSEC not later than 120 days after September 30, 2010. The information concerning principal accountant fees and services will be set forth in the definitive Proxy Statement under the heading “Audit Fees” and is incorporated herein by reference.
PART IV
| |
| Item 15 | Exhibits and Financial Statement Schedules |
(a)1. Financial Statements
Financial statements filed as part of Directors (the “Committee”) has reviewed and discussed with managementthis report are listed in the Compensation Discussion and Analysis contained in this report. Based upon this review and discussion, the Committee recommended to the Board of Directors that the Compensation Discussion and Analysis beindex included in Item 8 of this report.Form 10-K, and reference is made thereto.
COMPENSATION COMMITTEE
G. L. Mazanec,Chairman
R. T. Brady
R. D. Cash
S. E. Ewing
R. G. Reiten
F. V. Salerno
Compensation Discussion(a)2. Financial Statement Schedules
Financial statement schedules filed as part of this report are listed in the index included in Item 8 of thisForm 10-K, and Analysisreference is made thereto.
(a)3. Exhibits
OBJECTIVES
The Company’s executive compensation program is designed to:
| | • | | Attract, motivate, reward and retain the management talent required to achieve Company objectives and contribute to its long-term success. Retention is encouraged by making a portion | |
Exhibit
| | Description of the compensation package in the form of awards that either increase in value, or only have value, if the executive officer remains with the Company for specified periods of time.
|
| Number | | Exhibits |
| |
| 3(i) | | | Articles of Incorporation: |
| | • | | Focus management efforts on both short-term and long-term drivers | Restated Certificate of stockholder value. |
| Incorporation of National Fuel Gas Company dated September 21, 1998 (Exhibit 3.1,Form 10-K for fiscal year ended September 30, 1998 in FileNo. 1-3880) |
| | • | | Tie a significant portion | Certificate of executive compensation to Company long-term stock-price performance and thus stockholder returns by making a partAmendment of each executive officer’s potential compensation depend on the market priceRestated Certificate of the Company’s Common Stock.Incorporation (Exhibit 3(ii),Form 8-K dated March 14, 2005 in FileNo. 1-3880) |
Role of the Compensation Committee
The Compensation Committee sets the base salaries and bonuses of the Company’s executive officers. It also exercises authority delegated to it by the stockholders or the Board with respect to compensation plans. Plans under which stockholders have delegated authority to the Committee include the National Fuel Gas Company 1997 Award and Option Plan, as amended (the “1997 Award and
6
Option Plan”), and the 2007 Annual At Risk Compensation Incentive Plan (the “At Risk Plan”). In addition, the Committee makes recommendations to the Board with respect to the development of incentive compensation plans and equity-based plans and administers the National Fuel Gas Company Performance Incentive Program (the “Performance Incentive Program”) and, effective for fiscal 2009, the Executive Annual Cash Incentive Program. (the “Cash Incentive Program”). The Committee is also responsible for recommending to the Board changes in compensation for non-employee directors. The Committee is comprised of the six directors named above, all of whom have been determined by the Board to be independent. No member of the Committee is permitted to receive any award under any plan administered by the Committee.
Compensation Consultant
The Committee retains The Hay Group (“Hay”), an independent compensation consulting firm, to assist it in evaluating and setting officer compensation in all subsidiaries. The Company has utilized Hay and the Hay system, since the early 1980s, with respect to compensation management in its regulated companies. The Committee believes that Hay’s base of information from multiple parent organizations and business units provides a reliable source of compensation information.
Each year, Hay compares Company compensation practices to energy industry and general industry market practices based on Hay’s proprietary databases. In addition, Hay makes an annual recommendation on incentive compensation target amounts for both a short-term incentive (cash bonuses as discussed below) and long-term incentive (stock appreciation rights, restricted stock and the Performance Incentive Program target awards also discussed below). The Committee utilizes these recommendations in exercising its business judgment as to compensation matters.
In 2007, Hay also provided a proxy analysis for the top three officers (Messrs. Ackerman, Smith and Tanski) based on 2007 proxy data for the Company and energy companies in a comparable group. Based on that proxy data, the companies in the fifteen-member peer group range in size from $7.2 billion in revenues to $136 million in revenues. The median size of the peer group is $2.8 billion in revenues. The peer group is:
AGL Resources Inc.
Atmos Energy Corporation
Energen Corporation
Energy East Corporation
EnergySouth Inc.
Equitable Resources Inc.
Keyspan Corporation
MDU Resources Group Inc.
New Jersey Resources Corporation
Northwest Natural Gas Company
Peoples Energy Corporation
Questar Corporation
Southern Union Company
Southwest Gas Corporation
UGI Corporation
These companies were selected as members of the peer group because each participates in one or more of the business segments in which the Company participates. The Committee reviews the members of the peer group from time to time, and makes adjustments, as it believes warranted. In 2007, the Committee revised the group to delete Devon Energy and to add the following companies:
EnergySouth Inc.
MDU Resources Group Inc.
Northwest Natural Gas Company
UGI Corporation
Southwest Gas Corporation
Southern Union Company
The Committee revised the peer group to more closely align the median revenue size of the group to that of the Company.
In 2008, the Committee also retained Hewitt Consulting (“Hewitt”) to assist in evaluating and setting compensation at Seneca Resources Corporation, its exploration and production subsidiary, including that of Mr. Cabell. The Committee selected Hewitt for
7
this purpose due to that entity’s expertise in the exploration and production industry. The Hewitt proxy analysis was based on proxy data from twenty one (21) exploration and production companies chosen based on certain measures, such as revenues, assets and standardized measures. The companies range in size from $2.2 billion to $157 million in E&P revenues, (with a median of $798 million), from $8.7 billion to $660 million in E&P asset size (with a median of $2.4 billion) and from $6.8 billion to $447 million in standardized measure (with a median of $2.6 billion). The peer group is:
Berry Petroleum
Cabot Oil & Gas Corporation
Carrizo Oil & Gas, Inc.
Continental Resources Inc.
El Paso Corporation
Energen Corporation
Equitable Resources, Inc.
Kinder Morgan Oil & Gas
Mariner Energy, Inc.
Penn Virginia Corporation
Petroleum Development Corporation
Petroquest Energy, Inc.
Questar Corporation
Quicksilver Resources, Inc.
Range Resources Corporation
Southwestern Energy Company
St. Mary Land & Exploration Company
Swift Energy
Ultra Petroleum Corporation
Whiting Petroleum Corporation
Williams Companies, Inc.
TOTAL COMPENSATION
Total compensation for executive officers is comprised of the following components:
| | •3(ii) | | Base salary; |
| By-Laws: |
| | • | | Annual cash incentive compensation; | National Fuel Gas Company By-Laws as amended June 11, 2008 (Exhibit 3.1,Form 8-K dated June 16, 2008 in FileNo. 1-3880) |
| | 4 | | | Instruments Defining the Rights of Security Holders, Including Indentures: |
| | • | | Long term cash incentive compensation; |
| Indenture, dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 2(b) in FileNo. 2-51796) |
| | • | | Equity compensation — Restricted stock and/or grants | Third Supplemental Indenture, dated as of stock-settled stock appreciation rights;December 1, 1982, to Indenture dated as of October 15, 1974, between the Company and |
| The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(4) in FileNo. 33-49401) |
| | • | | Employee benefits, including retirement, health | Eleventh Supplemental Indenture, dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and welfare benefits.The Bank of New York (formerly Irving Trust Company) (Exhibit 4(b),Form 8-K dated February 14, 1992 in FileNo. 1-3880) |
| • | | | Twelfth Supplemental Indenture, dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c),Form 8-K dated June 18, 1992 in FileNo. 1-3880) |
| • | | | Thirteenth Supplemental Indenture, dated as of March 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(14) in FileNo. 33-49401) |
| • | | | Fourteenth Supplemental Indenture, dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1993 in FileNo. 1-3880) |
| • | | | Indenture dated as of October 1, 1999, between the Company and The Bank of New York (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) |
The cash and equity components of total compensation are determined by the Committee, based on its business judgment, utilizing the Hay and Hewitt data and recommendations, as the Committee deems appropriate. The employee benefits for executive officers employed prior to 2004 are a reflection of the Company’s historic practice of providing benefits that are commensurate with those in the regulated energy industry. Mr. Cabell was hired in December 2006, and the Committee reviews his compensation and benefits based on the advice of Hewitt and practices of other non-regulated exploration and production companies.
Base Salary
We pay salaries to our employees to provide them with a predictable base compensation for their day-to-day job performance. The Committee reviews base salaries at calendar year-end for the Company’s executive officers and adjusts them, if it deems appropriate, upon consideration of the recommendations of its outside compensation consultants and the Chief Executive Officer. In addition, base salary may be adjusted during the calendar year when changes in responsibility occur.
In establishing the base salary amount, the Committee generally targets a range of the 50th percentile to the 75th percentile of the survey data provided by Hay for Messrs. Ackerman, Smith, Tanski, Pustulka and Mrs. Cellino. With respect to Mr. Cabell, for
8
134
calendar year 2008, information provided by Korn Ferry, as described below, was used to adjust his base salary. The Committee believes this percentile range sets an appropriate market-competitiveness standard. The Committee also considers an individual’s specific responsibilities, experience (including time in position), and effectiveness and makes adjustments based thereon.| | | | | |
Exhibit
| | Description of
|
| Number | | Exhibits |
| |
| | • | | | Officers Certificate Establishing Medium-Term Notes, dated October 14, 1999 (Exhibit 4.2,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) |
| | • | | | Officers Certificate establishing 5.25% Notes due 2013, dated February 18, 2003 (Exhibit 4,Form 10-Q for the quarterly period ended March 31, 2003 in FileNo. 1-3880) |
| | • | | | Officer’s Certificate establishing 6.50% Notes due 2018, dated April 11, 2008 (Exhibit 4.1,Form 10-Q for the quarterly period ended June 30, 2008 in FileNo. 1-3880) |
| | • | | | Officer’s Certificate establishing 8.75% Notes due 2019, dated April 6, 2009 (Exhibit 4.4,Form 8-K dated April 6, 2009 in FileNo. 1-3880) |
| | • | | | Amended and Restated Rights Agreement, dated as of December 4, 2008, between the Company and The Bank of New York, as rights agent (Exhibit 4.1,Form 8-K dated December 4, 2008 in FileNo. 1-3880) |
| | 10 | | | Material Contracts: |
| | 10 | .1 | | Credit Agreement, dated as of August 18, 2010, among the Company, the Lenders Party Thereto, JPMorgan Chase Bank, National Association, as Administrative Agent, and PNC Bank, National Association, as Syndication Agent |
| | • | | | Form of Indemnification Agreement, dated September 2006, between the Company and each Director (Exhibit 10.1,Form 8-K dated September 18, 2006 in FileNo. 1-3880) |
| | • | | | Director Services Agreement, dated as of June 1, 2008, between the Company and Philip C. Ackerman (Exhibit 99,Form 8-K dated June 16, 2008 in FileNo. 1-3880) |
| | • | | | Agreement to Extend Duration of Director Services Agreement, dated June 1, 2009, between the Company and Philip C. Ackerman (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 2009 in FileNo. 1-3880) |
| | • | | | Resolutions adopted by the National Fuel Gas Company Board of Directors on February 21, 2008 regarding director stock ownership guidelines (Exhibit 10.5,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880) |
| | | | | Management Contracts and Compensatory Plans and Arrangements: |
| | • | | | Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, a subsidiary of the Company and each of Karen M. Camiolo, Carl M. Carlotti, Anna Marie Cellino, Paula M. Ciprich, Donna L. DeCarolis, John R. Pustulka, James D. Ramsdell, David F. Smith and Ronald J. Tanski (Exhibit 10.1,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880) |
| | • | | | Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, Seneca Resources Corporation and Matthew D. Cabell (Exhibit 10.2,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880) |
| | • | | | Letter Agreement between the Company and Matthew D. Cabell, dated November 17, 2006 (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880) |
| | • | | | Description of September 17, 2009 restricted stock award (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2009 in FileNo. 1-3880) |
| | • | | | Description of post-employment medical and prescription drug benefits (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 2009 in FileNo. 1-3880) |
| | • | | | National Fuel Gas Company 1997 Award and Option Plan, as amended and restated as of July 23, 2007 (Exhibit 10.4,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880) |
| | • | | | Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1,Form 8-K dated March 28, 2005 in FileNo. 1-3880) |
| | • | | | Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1,Form 8-K dated May 16, 2006 in FileNo. 1-3880) |
| | • | | | Form of Restricted Stock Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880) |
| | • | | | Form of Stock Option Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.3,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880) |
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For calendar year 2008, the Committee maintained Mr. Ackerman’s base salary at the same level as in 2007. For Mr. Smith, for the reasons stated above and to reflect Mr. Smith’s expected rise to the CEO position, the Committee increased Mr. Smith’s base salary for calendar year 2008. The Committee also increased Mr. Tanski’s base salary for calendar year 2008 (to an amount that was slightly below the market median for general industry) to reflect his dual role of chief financial officer and president of a major subsidiary.
With regard to Mr. Cabell, the Committee reviewed information from Korn Ferry, a respected executive search firm with expertise in the energy industry, in general, and in exploration and production, in particular, who worked with the Company to recruit Mr. Cabell. Korn Ferry provided compensation data showing base salary and short-term incentive compensation for individuals with similar positions at exploration and production companies with operations in Houston. The Committee also considered Mr. Cabell’s responsibilities, experience and effectiveness in the past year, including with respect to the sale of the Canadian assets, in determining to increase Mr. Cabell’s base salary for calendar 2008 to an amount that approximates the 75th percentile.
For executive officers below the level of these top four individuals, including Mrs. Cellino and Mr. Pustulka, Mr. Ackerman and Mr. Smith made recommendations for annual base salary increases, which were accepted by the Committee. In making such recommendations, Mr. Ackerman and Mr. Smith referenced the compensation consultant’s proposal on the appropriate target amount at the 50th and 75th percentiles for the coming year and made recommendations based on their opinion, and the advice of Mr. Tanski, on an individual’s specific responsibilities, experience and effectiveness over the past year. For these reasons, Mrs. Cellino and Mr. Pustulka received base salary increases for calendar 2008 which placed them between the 50th percentile and 75th percentile target amounts provided by Hay.
The fiscal 2008 base salaries of the named executive officers are shown on the Summary Compensation Table under “Base Salary” column within this proxy statement.
Annual Cash Incentive
We pay an additional annual cash incentive to our executives to motivate their performance over a short-term (which we generally consider to be no longer than two years). For fiscal 2008, for Messrs. Ackerman, Smith, Tanski and Cabell, this incentive was paid under the At Risk Plan. Effective for fiscal 2009, the Board of Directors adopted a new program that sets forth the parameters for awarding an annual cash incentive to those executives who do not receive an award under the At Risk Plan. This program is administered by the CEO. Target incentive opportunities, which are a percentage of base salary, are established by the CEO and approved by the Committee for executive officers. Payouts are in cash. The CEO establishes performance conditions for each participant, which are subject to the Committee’s approval for designated executive officers. At least 75% of the target incentive is dependent on objective performance criteria, and no more than 25% may be discretionary.
Target Award Levels
In setting target award levels for the annual cash incentive for 2008, the Committee exercised its business judgment and, upon consideration of the recommendations of Hay, set target awards as follows:
| | | | | |
Exhibit
| | TargetDescription of
|
ExecutiveNumber | | (As a Percentage of Base Salary)Exhibits |
Mr. Ackerman |
| • | | | 100 | %Form of Stock Appreciation Right Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 2008 inFile No. 1-3880) |
Mr. Smith | • | | | 100 | %Form of Stock Appreciation Right Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 2008 inFile No. 1-3880) |
Mr. Tanski | • | | | 75 | %Administrative Rules with Respect to At Risk Awards under the 1997 Award and Option Plan amended and restated as of September 8, 2005 (Exhibit 10.4,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880) |
Mr. Cabell | • | | | 65National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.1,Form 8-K dated March 17, 2010 in FileNo. 1-3880) |
| %• | | | Form of Stock Appreciation Right Award Notice under the National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2010 inFile No. 1-3880) |
| • | | | Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program (Exhibit 10.3,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880) |
| • | | | Description of performance goals for certain executive officers under the Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program (Exhibit 10.3,Form 10-Q for the quarterly period ended December 31, 2008 in FileNo. 1-3880) |
| • | | | Description of performance goals under the Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program and the National Fuel Gas Company Executive Annual Cash Incentive Program (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 2009 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Executive Annual Cash Incentive Program (Exhibit 10.3,Form 10-Q for the quarterly period ended December 31, 2009 in FileNo. 1-3880) |
| • | | | Description of performance goals for an executive officer under the Company’s Executive Annual Cash Incentive Program (Exhibit 10.3,Form 10-Q for the quarterly period ended December 31, 2008 in FileNo. 1-3880) |
| • | | | Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated effective March 11, 2010 (Exhibit 10.2,Form 8-K dated March 17, 2010 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994 (Exhibit 10.7,Form 10-K for fiscal year ended September 30, 1994 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1995 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 19, 1996 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Deferred Compensation Plan, as amended and restated through March 20, 1997 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 1997 inFile No. 1-3880) |
| • | | | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 16, 1997 (Exhibit 10.4,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880) |
| • | | | Amendment No. 2 to the National Fuel Gas Company Deferred Compensation Plan, dated March 13, 1998 (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 1998 in FileNo. 1-3880) |
| • | | | Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated February 18, 1999 (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 1999 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 15, 2001 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 2001 in FileNo. 1-3880) |
| • | | | Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated October 21, 2005 (Exhibit 10.5,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880) |
In each case, the maximum possible award was two times the target amount. Hay’s recommendations were based on current and emerging trends in both energy and general industries.
Performance Goals
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The following are the general categories of performance goals and the purpose of such goals. The precise performance goals differ for each executive.
| | | | | |
GoalExhibit
| | Description of
|
| Number | | Purpose |
Consolidated earnings per share | | | | To focus executives’ attention on the profitability of the Company as a whole |
| | | | |
Reserves and lifting costs in the exploration and production segment | | | | To focus the attention of certain executives on this segment of our business |
| | | | |
Safety | | | | To underscore the Company’s commitment to safety, which is particularly important given the nature of the field operations in the utility and pipeline and storage segments |
| | | | |
Long-term strategy | | | | To focus the executives’ attention on areas the Committee believes are important, including succession and business planning |
| | | | |
Investor relations | | | | To further the Company’s message regarding strategic value with the investment community |
| | | | |
Customer service in the utility segment | | | | To focus the attention of certain executives on this segment of our business |
For fiscal 2008, At Risk Plan goals for Mr. Ackerman were based on the following:
| | | | | | |
| | Weight | | Target Performance Level |
Consolidated earnings per share | | | 100 | % | | $2.70 up to but not including $2.75 diluted earnings per share |
In fiscal 2008, Mr. Ackerman was awarded a bonus of 200.0% of his target amount for his performance on the goals set under the At Risk Plan. Pursuant to the terms of the At Risk Plan, Mr. Ackerman received a pro-rated portion of the bonus payment he otherwise would have received given his retirement prior to the end of the fiscal year.
For fiscal 2008, At Risk Plan goals for Mr. Smith were based on the following:
| | | | | | |
| | Weight | | Target Performance Level |
Consolidated earnings per share. In determining final performance level, the results of this goal are averaged with the prior year results on the same goal | | | 60 | % | | $2.70 up to but not including $2.75 diluted earnings per share |
| | | | | | |
Long-term strategy | | | 10 | % | | Review a succession plan for executive officers and establish a formal short-term incentive plan for the executive officers |
| | | | | | |
Reserve replacement | | | 10 | % | | Replace 90% of fiscal 2008 production |
| | | | | | |
Production volume | | | 10 | % | | 41 Billion cubic feet equivalent |
| | | | | | |
Safety, measured by the number of OSHA recordable injuries in the utility and pipeline and storage segments | | | 5 | % | | 6.49 OSHA recordable injuries in these subsidiaries |
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| | | | | | |
| | Weight | | Target Performance Level |
Investor relations, measured by one-on-one meetings | | | 5 | % | | Meetings with 35 different analysts or money managers |
In fiscal 2008, Mr. Smith was awarded a bonus of 180.1% of his target amount for his performance on the goals set under the At Risk Plan.
For fiscal 2008, At Risk Plan goals for Mr. Tanski were based on the following:
| | | | | | |
| | Weight | | Target Performance Level |
Consolidated earnings per share. In determining final performance level, the results of this goal are averaged with the prior year results on the same goal | | | 50 | % | | $2.70 up to but not including $2.75 diluted earnings per share |
| | | | | | |
Regulated companies earnings per share. In determining final performance level, the results of this goal are averaged with the prior year results on the same goal | | | 10 | % | | $1.23 up to but not including $1.28 diluted earnings per share |
| | | | | | |
Long-term strategy | | | 10 | % | | Present a plan to rationalize corporate capital structure in light of regulatory policies |
| | | | | | |
Safety, measured by the number of OSHA recordable injuries in the utility and pipeline and storage segments | | | 10 | % | | 6.49 OSHA recordable injuries these subsidiaries |
| | | | | | |
Customer service, measured by the utility segment’s service quality performance standards in New York | | | 10 | % | | 63 penalty units assessed based on customer
service satisfaction measures |
| | | | | | |
Investor relations, measured by the number of road shows | | | 5 | % | | Road shows to 16 different cities/SMSA’s |
| | | | | | |
Investor relations, measured by the number of one-on-one meetings | | | 5 | % | | Meetings with 70 different analysts or money managers |
In fiscal 2008, Mr. Tanski was awarded a bonus of 190.0% of his target amount for his performance on the goals set under the At Risk Plan.
For fiscal 2008, At Risk Plan goals for Mr. Cabell were based on the following:
| | | | | | | |
| | | Weight | | Target Performance Level |
| Production volume | | | 20 | % | | 41 Billion cubic feet equivalent |
| | | | | | | |
| Total reserve replacement for Seneca | | | 15 | % | | Replace 90% of fiscal 2008 production |
| | | | | | | |
| Appalachian reserve replacement | | | 15 | % | | Replace 300% of fiscal 2008 Appalachian production |
| | | | | | | |
| Finding and development costs | | | 20 | % | | $4.00 per million cubic feet equivalent |
| | | | | | | |
| Lease operating expense plus general and administrative expense, per Mcfe | | | 15 | % | | $1.64 per million cubic feet equivalent |
| | | | | | | |
| Seneca’s return on average capital, before other comprehensive income | | | 15 | % | | 16% |
In fiscal 2008, Mr. Cabell was awarded a bonus of 117.0% of his target amount for his performance on the goals noted above.
For executive officers below the level of these top four individuals, including Mrs. Cellino, and Mr. Pustulka. Mr. Smith made recommendations for fiscal 2008 bonuses, which were accepted by the Committee. In making such recommendations, Mr. Smith
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referenced Hay’s proposed structure on the median and 75% percentile level for the Energy Industry and General Industry, but made adjustments based on his opinion and the advice of Mr. Tanski on individual performance over the past year. Mr. Smith recommended that Mrs. Cellino receive a fiscal 2008 bonus because of her attention to customer service and oversight of budget and cost control at the Company’s utility subsidiary and her performance of her duties as Corporate Secretary, and that Mr. Pustulka receive a fiscal 2008 bonus because of his management of gas transportation and storage in the Company’s pipeline segment and his attention to pipeline integrity.
The fiscal 2008 annual cash incentives of Messrs. Ackerman, Smith, Tanski and Cabell are shown on the Summary Compensation Table in the “Non-Equity Incentive Plan Compensation” column. The fiscal 2008 annual cash incentives for Mrs. Cellino and Mr. Pustulka are shown in the “Bonus” column of this table.
Equity Compensation and Long Term Incentive Compensation
Stock options, restricted stock, stock appreciation rights and the Performance Incentive Program represent the longer-term incentive and retention component of the executive compensation package. Such awards are intended to focus attention on managing the Company from a long-term investor’s perspective. In addition, we wish to encourage officers and other managers to have a significant, personal investment in the Company through stock ownership. Awards of stock options, stock-settled stock appreciation rights (“SARs”) and/or restricted stock are used to attract and retain key management employees, when necessary or advisable. The Company typically makes equity awards on an annual basis. The Committee has not recently granted equity awards at a specific quarterly meeting because of its ongoing consideration of the appropriate option practice, including setting of performance criteria.
In exercising its business judgment regarding long-term incentive compensation, the Committee generally refers to Hay’s guidelines on the level of such compensation, but makes adjustments based on its discussion with the Chief Executive Officer as to what’s appropriate on an individual basis given the Company’s future plans and needs. The consultant, in setting those guidelines, attempts to balance general industry and energy industry practice.
Fiscal 2008 SAR grants and other long-term incentives are set forth in the Grants of Plan-Based Awards in Fiscal 2008 table within this proxy statement.
Stock Appreciation Rights, Stock Options and Restricted Stock
Awards of stock-settled SARs, stock options and restricted stock are made by the Committee under the 1997 Award and Option Plan (“Option Plan”). The exercise price for all options and stock-settled SARs is the average of the high and low market price (FMV) of the Company’s Common Stock on the date of the grant. This method of determining the FMV appears in all of the Company’s stock option Plans since 1983 and has been approved by the stockholders. In 2008, the Committee awarded performance-based stock-settled SARs rather than options, as they are less dilutive to stockholder equity. The Committee anticipates that it will continue this practice in the future. The SARs granted to the named executive officers in fiscal 2008 are set out in the “Grants of Plan-Based Awards in Fiscal 2008” table within this proxy statement. As stated above, the number granted was derived from Hay’s guidelines. No equity award was made to Mr. Ackerman due to his possible retirement.
On December 5, 2007, the Committee also awarded Mr. Cabell 25,000 shares of restricted stock in recognition of his excellent performance in the sale of the Canadian assets and to act as a retention tool. This award vests annually in increments of 5,000 shares, beginning four years after the grant date.
Performance Incentive Program
The Performance Incentive Program is the Company’s cash-based, long-term incentive program. This program was adopted to complement the equity-based programs, under which future awards have been limited due to their dilutive nature.
Under the Performance Incentive Program, the Compensation Committee may establish a performance condition for a performance period of at least one year. The default performance condition is the Company’s total return on capital as compared to the same metric for peer companies in the Natural Gas Distribution and Integrated Natural Gas Companies group as calculated and reported in the Monthly Utility Reports (each, a “Monthly Utility Report”) of AUS, Inc., a leading industry consultant (“AUS”). A cash bonus may be paid following the end of the performance period based on the level of performance. The natural gas distribution and integrated natural gas companies reported in the December, 2008 Monthly Utility Report are:
AGL Resources Inc.
Atmos Energy Corporation
Chesapeake Utilities Corporation
Delta Natural Gas Company
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El Paso Corporation
Energen Corporation
Energy West Incorporated
Equitable Resources, Inc.
Laclede Group, Inc.
National Fuel Gas Company
New Jersey Resources Corp.
NICOR Inc.
Northwest Natural Gas Co.
ONEOK, Inc.
Piedmont Natural Gas Co., Inc.
Questar Corporation
RGC Resources, Inc.
South Jersey Industries, Inc.
Southern Union Company
Southwest Gas Corporation
Southwestern Energy Company
UGI Corporation
WGL Holdings, Inc.
Williams Companies, Inc.
In fiscal 2006, the Compensation Committee chose the Company’s total return on capital as the performance metric for the three-year performance period of October 1, 2005 to September 30, 2008. The Committee selected this financial metric because it reflects how profitably management is able to allocate capital to its operations and also because it provides a performance metric of relevance to all participants, regardless of the business segment(s) for which they provide services. Based on the level of performance at the end of each of the three-year performance periods, payment can range from 0% to 200% of the target incentives. Target performance is achieved if the Company ranks in the 60th percentile of the peer group. Ranking is determined by calculating the average return on capital for the three-year period for each company and sorting the companies from highest to lowest. For this performance period, the Committee approved the following target incentives for the current named executive officers:
| | | | |
| Mr. Ackerman | | $ | 650,000 |
| Mr. Smith | | | 375,000 |
| Mr. Tanski | | | 250,000 |
| Mrs. Cellino | | | 85,000 |
| Mr. Pustulka | | | 85,000 |
Because the Monthly Utility Report with the necessary data for fiscal 2008 will not be available until January or February of 2009, the actual award amounts earned for the performance period of October 1, 2005 through September 30, 2008 are unknown. The amounts shown in the Summary Compensation Table, under column (h), footnote (6) within this proxy statement were accrued by the Company in fiscal 2008 as estimates of the amount which will be calculated and paid, in the second quarter of fiscal 2009.
In fiscal 2007 and fiscal 2008 the Committee again chose the Company’s total return on capital as the performance metric. The performance period selected in fiscal 2007 was the three-year period of October 1, 2006 through September 30, 2009, and the target incentive for the current named executive officers was selected as follows:
| | | | |
| Mr. Ackerman | | $ | 774,000 |
| Mr. Smith | | | 385,000 |
| Mr. Tanski | | | 308,750 |
| Mr. Cabell | | | 276,250 |
| Mrs. Cellino | | | 100,000 |
| Mr. Pustulka | | | 100,000 |
The performance period selected in fiscal 2008 was the three-year period of October 1, 2007 through September 30, 2010, and the target incentive for the current named executive officers was selected as follows:
| | | | |
| Mr. Ackerman | | $ | 1,548,000 |
| Mr. Smith | | | 585,000 |
| Mr. Tanski | | | 350,000 |
| Mr. Cabell | | | 225,000 |
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| | | |
Mrs. Cellino | | | 100,000 |
Mr. Pustulka | | | 100,000 |
The target thresholds for these two performance periods are the same as noted above.
The fiscal 2008 target incentives selected were derived from Hay’s guidelines, except that the Committee determined that Mr. Ackerman’s long term compensation should be awarded solely under the Performance Incentive Program, rather than a combination of equity and cash due to his possible retirement. Therefore, Mr. Ackerman’s target incentive was doubled, but he received no SAR award. The Committee believes that equity awards are more appropriate for individuals who will continue in the employ of the Company due to an equity award’s retention value and its effectiveness in the alignment of employee and stockholders long-term interests.
EMPLOYEE BENEFITS
Retirement Benefits
The Company maintains a qualified defined contribution retirement plan (401(k)), a qualified defined benefit retirement plan, a non-qualified executive retirement plan and a non-qualified tophat plan in order to attract and retain high caliber employees in high-level management positions, and, in the case of the non-qualified plans, to restore retirement benefits lost to employees under the qualified retirement plans as a result of the effect of the Internal Revenue Code limits and the qualified plans’ limits on compensation considered and benefits provided under such qualified plans.
Messrs. Ackerman, Smith, Tanski, Pustulka and Mrs. Cellino are eligible to participate in both of the non-qualified plans. Mr. Cabell is eligible to participate in the non-qualified tophat plan. These benefits are described in more detail in the section entitled “Pension Benefits Table” within this proxy statement.
Mr. Smith has a Retirement Benefit Agreement, approved by the Board and entered into in September of 2003, that provides additional retirement benefits if Mr. Smith’s employment is terminated by the Company without cause or by Mr. Smith with good reason, prior to March 1, 2011. If eligible for the enhanced benefit, Mr. Smith’s retirement benefit would be calculated as though he were 571/2 years old for purposes of determining the applicable early retirement penalty, but without giving Mr. Smith credit for additional years of service. The Committee recommended this agreement as a reflection of Mr. Smith’s achieving a high level position at a relatively early age, such that his retirement benefits could be severely reduced in the event of termination without cause. The Committee also viewed this agreement as a retention tool and a means to direct Mr. Smith’s attention to his duties of acting in the best interests of the stockholders. This benefit is described in more detail in the section entitled “Pension Benefit Table” within this proxy statement.
Executive Life Insurance
In 2004, the Committee authorized an insurance program known as the “ExecutiveLife Insurance Plan.” Under this plan, upon specific direction of the Company’s Chief Executive Officer, when an executive officer reaches age 50, the Company would pay the cost of a life insurance policy or policies, to be owned by the executive officer, in an amount up to $15,000 per year. The payment is taxable income to the executive officer and ceases when the executive officer’s employment ceases. The Committee authorized this plan as a replacement for its prior practice of providing split dollar life insurance agreements to designated executive officers. The Committee replaced the split dollar arrangement with the current plan because it wanted to continue to provide an appropriate level of death benefit, but was prohibited by the Sarbanes Oxley Act from making premium payments on certain split dollar policies due to their nature as loans.
Life insurance for Messrs. Ackerman and Smith is currently maintained under split dollar arrangements, into which the Company makes no premium payments. Mr. Tanski, Mrs. Cellino and Mr. Pustulka are covered by the ExecutiveLife Insurance Plan. Mr. Cabell is a participant in the Company’s group life insurance plan.
EXECUTIVE PERQUISITES
The Company offers a limited number of perquisites to our executive officers. The basis for offering these perquisites is to enhance the Company’s ability to attract and retain highly qualified persons and also to assist the officer in conducting business on behalf of the Company. For certain items, the perquisite is incidental to other business-related use. For example, the Company shares a
14
stadium suite with another local utility company for the local professional football team and an arena suite with a local law firm for the local professional hockey team. The Company also has season tickets for seats outside the suites. The Company made these investments as a result of specific drives by the Buffalo, New York business community to support the retention of these professional athletic teams in the Buffalo area. These suites are primarily used for Company business. On the occasions when the suites are not used for Company business, the executive officers as well as other employees are permitted personal use.
In fiscal 2008, the Compensation Committee directed the elimination of company-provided cars for most officers, effective October 1, 2008. Exceptions were allowed at the CEO’s discretion to require use of a company vehicle by officers with field operations responsibility. Officers whose vehicles were eliminated were provided a one-time adjustment to base salary as of October 1, 2008.
The Company also offers executive officers tax preparation advice, in part to assure the Company that its officers are properly reporting compensation. The Company also pays the costs of spouses accompanying named executive officers to certain of the Board of Directors meetings and functions. In addition, the Company covered Mr. Ackerman’s annual dues in a private country club and a local business club until his retirement.
CHANGE IN CONTROL ARRANGEMENTS
If an executive officer’s employment is terminated without cause within a specific time following a change in control of the Company, many of the components of total compensation described above become immediately vested or paid out in a lump sum. These items are described in more detail and calculations as of September 30, 2008, are set forth in the section entitled “Potential Payments Upon Termination or Change in Control” within this proxy statement.
In December of 1998, upon recommendation by the Committee, the Company adopted an amended and restated change in control agreement, known as the “Employment Continuation and Noncompetition Agreement” (“ECNA”). Each of the named executive officers is a party to an ECNA. In September of 2007, and again in September of 2008, the ECNA was amended and restated to be in compliance with Internal Revenue Code Section 409A and the final regulations promulgated thereunder. No enhancement to the benefit provided under the agreement was added either time.
The Company and the Committee believe that these agreements are required for the attraction and retention of the executive talent needed to achieve corporate objectives and to assure that executive officers direct their attention to their duties, acting in the best interests of the stockholders, notwithstanding the potential for loss of employment in connection with a change in control.
The agreement contains a “double-trigger” provision that provides payment only if employment terminates within three years following a change in control, as defined in the agreement, either by the Company other than for cause or by the executive officer for good reason. The Committee believes this structure strikes a balance between the incentive and the executive attraction and retention efforts described above, without providing change in control benefits to executive officers who continue to enjoy employment with the Company in the event of a change in control transaction.
The payment is generally calculated by multiplying 1.99 by the sum of the executive officer’s current base salary plus the average of the annual cash bonus for the previous two fiscal years. The 1.99 multiplier is reduced on a pro-rata basis if termination occurs between age 62 and 65. There is no gross-up for taxes. If payment is triggered, certain health benefits are continued for the earlier of 18 months following termination or until age 65.
The ECNA contains a restrictive covenant whereby the executive officer may, upon termination following a change in control, choose to refrain from being employed by or otherwise serving as an agent, consultant, partner or major stockholder of a business engaged in activity that is competitive with that of the Company or its subsidiaries. If he so chooses to be bound by this restrictive covenant, an additional payment is made in the amount of one times the sum of current base salary plus the average of the annual cash bonus for the previous two fiscal years. The Committee and the Company believe this is an appropriate payment in exchange for the non-compete covenant agreed to by the executive officer.
OWNERSHIP GUIDELINES
In fiscal 2002, in an effort to emphasize the importance of stock ownership and after consultation with the Compensation Committee, Company Common Stock ownership guidelines were established for officers. These guidelines range from one times base salary for junior officers to four times base salary at the Chief Executive Officer level. Other employees receiving options and SARs
15
are encouraged to retain their Common Stock for long-term investment. We believe that employees who are stockholders perform their jobs in a manner that considers the long-term interests of the stockholders.
TAX CONSIDERATIONS
Section 162(m) of the Internal Revenue Code prohibits the Company from deducting compensation paid in excess of $1 million per year to any executive officer listed in the Compensation Summary Table unless such compensation qualifies as “performance-based compensation” within the meaning of Section 162(m). The Committee generally intends that compensation paid to its managers, including its executive officers, should not fail to be deductible for federal income tax purposes by reason of Section 162(m). For this reason, compensation paid under the At Risk Plan is designed to qualify as performance-based compensation under Section 162(m). The Committee may elect to award compensation, especially to a Chief Executive Officer, that is not fully deductible, if the Committee determines that such award is consistent with its philosophy and is in the best interests of the company and its stockholders.
Summary Compensation Table
The following table sets forth a summary of the compensation paid to or earned by each person who served as the Chief Executive Officer, the Principal Financial Officer and each of the three other most highly compensated executive officers (the “named executive officers”) of the Company in fiscal 2008. The compensation reflected for each officer was for the officer’s services provided in all capacities to the Company and its subsidiaries.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | (6) | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Change in | | | | |
| | | | | | | | | | | | | | | | | | | | | | | (5) | | Pension Value | | | | |
| | | | | | | | | | | | | | | (3) | | (4) | | Non-Equity | | and Nonqualified | | (7) | | |
| | | | | | | (1) | | (2) | | Stock | | Option | | Incentive Plan | | Deferred | | All Other | | |
| | | Fiscal | | Salary | | Bonus | | Awards | | Awards | | Compensation | | Compensation | | Compensation | | Total |
| Name and Principal | | Year | | ($) | | ($) | | ($) | | ($) | | ($) | | Earnings($) | | ($) | | ($) |
| Position (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Philip C. Ackerman | | | 2008 | | | | 573,333 | | | | N/A | | | | 3,513 | | | | 0 | | | | 2,229,567 | | | | 213,330 | | | | 127,055 | | | | 3,146,798 | |
| Chief Executive Officer of the Company through 2/20/08. Retired effective 6/1/08 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Philip C. Ackerman | | | 2007 | | | | 851,250 | | | | N/A | | | | 64,750 | | | | 798,644 | | | | 1,634,391 | | | | 1,340,042 | | | | 148,785 | | | | 4,837,862 | |
| Chief Executive Officer of the Company | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| David F. Smith | | | 2008 | | | | 625,000 | | | | N/A | | | | 0 | | | | 308,106 | | | | 1,750,375 | | | | 431,116 | | | | 116,467 | | | | 3,231,064 | |
| President and Chief Executive Officer of the Company | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| David F. Smith | | | 2007 | | | | 543,750 | | | | N/A | | | | 0 | | | | 580,133 | | | | 686,464 | | | | 531,864 | | | | 49,031 | | | | 2,391,242 | |
| President and Chief Operating Officer of the Company and President of National Fuel Gas Supply Corporation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ronald J. Tanski | | | 2008 | | | | 512,500 | | | | N/A | | | | 0 | | | | 206,497 | | | | 1,146,813 | | | | 656,006 | | | | 91,100 | | | | 2,612,916 | |
| Treasurer and Principal Financial Officer of the Company and President of National Fuel Gas Supply Corporation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ronald J. Tanski | | | 2007 | | | | 456,250 | | | | N/A | | | | 0 | | | | 413,798 | | | | 581,874 | | | | 486,590 | | | | 60,167 | | | | 1,998,679 | |
| Treasurer and Principal Financial Officer of the Company and President of National Fuel Gas Distribution Corporation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Matthew D. Cabell | | | 2008 | | | | 443,750 | | | | 0 | | | | 373,183 | | | | 325,346 | | | | 337,472 | | | | 0 | | | | 69,140 | | | | 1,548,891 | |
| President of Seneca Resources Corporation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Matthew D. Cabell | | | 2007 | | | | 343,269 | | | | 150,000 | | | | 159,395 | | | | 196,072 | | | | 265,338 | | | | 0 | | | | 18,543 | | | | 1,132,617 | |
| President of Seneca Resources Corporation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Anna Marie Cellino | | | 2008 | | | | 289,875 | | | | 250,000 | | | | 0 | | | | 60,636 | | | | 141,610 | | | | 160,435 | | | | 47,937 | | | | 950,493 | |
| President National Fuel Gas Distribution Corporation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| John R. Pustulka | | | 2008 | | | | 289,875 | | | | 140,500 | | | | 0 | | | | 60,636 | | | | 141,610 | | | | 212,629 | | | | 43,105 | | | | 888,355 | |
| Senior Vice President of National Fuel Gas Supply Corporation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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| | |
(1) | | The amounts in column (c) reflect base salary paid during each respective fiscal year. For fiscal 2007, Mr. Cabell’s salary reflects a partial year, as he was hired on December 11, 2006. |
|
(2) | | For Mrs. Cellino and Mr. Pustulka, the amount in column (d) represents a cash bonus earned in the fiscal year and paid in December 2008. For Mr. Cabell, for 2007 this amount represents a sign-on bonus as part of his employment package. |
|
(3) | | Column (e) represents the dollar amount recognized in fiscal 2008 and 2007 for financial statement reporting purposes with respect to Restricted Stock awarded to Mr. Cabell during fiscal years 2008 and 2007 and to Mr. Ackerman in prior years. Restricted stock is subject to restrictions on vesting and transferability. The fair market value of restricted stock on the date of the award, calculated as the average of the high and low market price of Company stock on the date of award, is recorded as compensation expense over the vesting period. SFAS 123R requires such awards to be valued at fair value. |
|
(4) | | Column (f) represents the dollar amount recognized for financial statement reporting purposes with respect to the 2008 and 2007 fiscal years for the fair value of the stock options (including SARs) granted to each of the named executive officers. The expense associated with all options granted in fiscal 2008 and fiscal 2007 (including the SARs granted in fiscal 2008), as well as those issued in prior years, has been recorded in accordance with SFAS 123R. For information on the valuation assumptions with respect to option grants (including SARs) refer to Note A under the heading “Stock-Based Compensation” in the Company’s financial statements in Form 10-K for the fiscal year ended September 30, 2008. |
|
(5) | | With respect to fiscal year 2007 the estimated amount that was in the fiscal 2007 proxy has been updated for actual payments made in February 2008 and filed in the 8-K on February 26, 2008. For Messrs. Ackerman, Smith and Tanski, column (g) reflects both a Performance Incentive Program payment made February 29, 2008 ($874,650 for Mr. Ackerman, $324,870 for Mr. Smith and $99,960 for Mr. Tanski) and the actual At Risk Program payment made in December 2007 ($759,741 for Mr. Ackerman, $361,594 for Mr. Smith and $481,914 for Mr. Tanski.) For Mr. Cabell, this amount represents his bonus paid in December 2007 for performance in fiscal 2007 based on his short-term incentive goals. Please refer to the Compensation Discussion and Analysis for additional information about these programs, including information regarding the performance conditions applicable to the awards. |
|
| | For fiscal year 2008, Messrs. Ackerman, Smith and Tanski column (g) reflects both an estimated Performance Incentive Program payment expected to be paid by March 15, 2009 ($1,082,900 for Ackerman, $624,750 for Mr. Smith and $416,500 for Mr. Tanski) and the actual At Risk Program payment made in December 2008 ($1,146,667 for Mr. Ackerman, $1,125,625 for Mr. Smith and $730,313 for Mr. Tanski). For Mr. Cabell this amount represents the actual At Risk Program payment made in December 2008. For Mrs. Cellino and Mr. Pustulka, in fiscal 2008, column (g) represents the estimated Performance Incentive payment expected to be paid by March 15, 2009. |
|
| | For the three year performance period ended September 30, 2008, the Company estimates that its performance relative to its peer group will result in a payout of approximately 166.6% of the “Target Incentive Opportunity” set for each of the participants in the Performance Incentive Program. This estimate (166.6%) is subject to change based on the final AUS report for the performance period ended September 30, 2008. |
|
(6) | | Column (h) represents the actuarial increase in the present value of the named executive officer’s benefits under all pension plans maintained by the Company determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements. These amounts may include amounts which the named executive officer may not currently be entitled to receive because such amounts are not vested as of September 30, 2008 and 2007, respectively. Also, the amounts include above market earnings under the Deferred Compensation Plan for Mr. Ackerman ($33,139 for fiscal 2007 and $32,017 for fiscal 2008), Mrs. Cellino ($1,003 for fiscal 2008), and Mr. Pustulka ($468 for fiscal 2008). See the narrative, tables and notes to the Pension Plan and the Nonqualified Deferred Compensation Plan within this proxy statement. |
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| | |
(7) | | All Other Compensation Table |
The following table describes each component of the All Other Compensation column in the Summary Compensation Table for fiscal year 2008.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | Anna | | |
| | | Philip C. | | David F. | | Ronald J. | | Matthew D. | | Marie | | John R. |
| Description | | Ackerman | | Smith | | Tanski | | Cabell | | Cellino | | Pustulka |
| Defined Contribution Company Match 401(k))(a) | | $ | 9,100 | | | $ | 13,700 | | | $ | 13,700 | | | $ | 6,954 | | | $ | 13,700 | | | $ | 13,700 | |
| 401(k) Tophat(b) | | | 94,100 | | | | 90,838 | | | | 60,619 | | | | 6,400 | | | | 18,630 | | | | 12,060 | |
| RSA Tophat(c) | | | 0 | | | | 0 | | | | 0 | | | | 3,267 | | | | 0 | | | | 0 | |
| Employee Stock Ownership Plan (ESOP) Supplemental Payment(d) | | | 5,211 | | | | 931 | | | | 1,646 | | | | 0 | | | | 529 | | | | 2,267 | |
| Executive Officer Life Insurance(e) | | | 0 | | | | 0 | | | | 15,000 | | | | 1,584 | | | | 15,000 | | | | 15,000 | |
| Travel Accident Insurance(f) | | | 51 | | | | 77 | | | | 135 | | | | 135 | | | | 78 | | | | 78 | |
| Dividends paid on Restricted Stock(g) | | | 1,687 | | | | 0 | | | | 0 | | | | 50,800 | | | | 0 | | | | 0 | |
| Perquisites(h) | | | 16,906 | | | | 10,921 | | | | N/A | | | | N/A | | | | N/A | | | | N/A | |
| |
Total | | $ | 127,055 | | | $ | 116,467 | | | $ | 91,100 | | | $ | 69,140 | | | $ | 47,937 | | | $ | 43,105 | |
| | |
a) | | Represents the Company matching contributions within the 401(k) plan. |
|
b) | | Each officer, except for Mr. Cabell, has over 20 years of service and receives a 6% match within the 401-K plan on the lesser of a) their base salary or b) the IRS annual salary limit for fiscal 2008. Each of these officers is prohibited from receiving the full 401(k) Company match on their salary due to the IRS maximum salary limit of $225,000 for 2007 and $230,000 for 2008. The 401(k) tophat gives each officer, except Mr. Cabell, a match (6%) on the following forms of compensation: i.) base salary that exceeds the IRS maximum salary allowed for the 401(k) plan; ii.) regular bonus and iii.) Annual At Risk Plan payment. Mr. Cabell became eligible for the 401(k) plan July 1, 2007 and receives a 3% Company match within the 401(k) plan. For Mr. Cabell, the 401(k) tophat match is based on his annual base salary that exceeds the IRS maximum salary limit. The 401(k) tophat dollars represent the benefit earned in fiscal 2008. |
|
c) | | Mr. Cabell is a participant in the Company’s Retirement Savings Account (RSA) Plan and receives a 2% Company contribution on the lesser of (2) his base salary or (b) the IRS annual salary limit for fiscal 2008. Mr. Cabell is prohibited from receiving the full RSA contribution on his salary due to the IRS maximum salary limit of $225,000 for 2007 and $230,000 for 2008. The RSA tophat match is based on his annual base salary that exceeds the IRS maximum salary limit. The RSA tophat dollars represents the benefit earned in fiscal 2008. |
|
d) | | All management participants who were hired prior to December 31, 1986, participate in the ESOP which pays dividends to the participants on the Common Stock held in the plan. The participant does not have the option to reinvest these dividends in order to defer the federal and state income taxes on these dividends. Therefore, the Company makes supplemental payments representing the approximate amount the Company saves in corporate income taxes. The ESOP is a qualified benefit plan that was frozen in 1987 and closed to future participants, including Mr. Cabell. |
|
e) | | Represents the Company-paid life insurance premiums on behalf of Mr. Tanski, Mrs. Cellino and Mr. Pustulka under the “ExecutiveLife Insurance Plan.” |
|
| | None of the officers, except Mr. Cabell, receive a death benefit under the Company’s Group Life Insurance Plan. Mr. Cabell is a participant in the Company’s Group Life Insurance Plan. The above dollars represent the premiums paid for this benefit. |
|
f) | | Represents the premiums paid for the blanket travel insurance policy, which provides a death benefit to each officer while traveling on business. |
|
g) | | Dividends are paid on unvested restricted stock and reported as taxable income for each officer. |
|
h) | | Perquisites for Mr. Ackerman included club membership dues and expenses, tax preparation and advice, personal use of a company owned automobile, personal use of the shared suite for local athletic events, blanket travel insurance for personal travel, attendance at company events for Mr. Ackerman’s wife and a minimal amount for use of a Company property. |
18
| | |
| | Perquisites for Mr. Smith included tax preparation and advice, personal use of a company owned automobile, tickets to a local theater, blanket travel insurance for personal travel, and attendance at company events for Mr. Smith’s wife. No single perquisite exceeded the greater of $25,000 or 10% of the total perquisites provided to Mr. Ackerman or Mr. Smith. Perquisites for each of the other named executive officers were less than $10,000. |
Grants of Plan-Based Awards in Fiscal 2008
The following table sets forth information with respect to awards granted to the named executive officers during fiscal 2008 under the Performance Incentive Program, the At Risk Plan, and the 1997 Award and Option Plan. There are no future payouts under Equity Incentive Plan Awards; therefore we have removed those columns from the table. Please refer to the Compensation Discussion and Analysis (CD&A) within this proxy statement for additional information regarding these plans.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | All Other | | All Other | | | | | | �� | | |
| | | | | | | | | | | | | | | | | | | | | | | Stock | | SAR | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | Awards: | | Awards: | | Exercise or | | | | | | Grant Date |
| | | | | | | | | | | | | | | | | | | | | | | Number of | | Number of | | Base | | | | | | Fair Value |
| | | | | | | | | | | Estimated Future Payouts Under | | Shares of | | Securities | | Price of | | | | | | of Stock and |
| | | | | | | | | | | Non-Equity Incentive Plan Awards | | Stock or | | Underlying | | Option/SAR | | Closing | | Option/SAR |
| | | | | | | Grant | | Threshold | | Target | | Maximum | | Units | | SARs | | Awards | | Market | | Awards |
| Name | | Note | | Date | | ($) | | ($) | | ($) | | (#)(1) | | (#)(1) | | ($/Sh) | | Price($) | | ($)(4) |
| Philip C. Ackerman | | | (2 | ) | | | 02/20/2008 | | | | 0 | | | | 1,548,000 | | | | 3,096,000 | | | | 0 | | | | 0 | | | | | | | | | | | | | |
| | | | (3 | ) | | | 12/22/2007 | | | | 0 | | | | 573,333 | | | | 1,146,667 | | | | 0 | | | | 0 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| David F. Smith | | | (1 | ) | | | 02/20/2008 | | | | | | | | | | | | | | | | 0 | | | | 70,000 | | | $ | 47.37 | | | $ | 47.60 | | | | 611,625 | |
| | | | (2 | ) | | | 02/20/2008 | | | | 0 | | | | 585,000 | | | | 1,170,000 | | | | | | | | | | | | | | | | | | | | | |
| | | | (3 | ) | | | 12/22/2007 | | | | 375,000 | | | | 625,000 | | | | 1,250,000 | | | | 0 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ronald J. Tanski | | | (1 | ) | | | 02/20/2008 | | | | | | | | | | | | | | | | | | | | 45,000 | | | $ | 47.37 | | | $ | 47.60 | | | | 393,188 | |
| | | | (2 | ) | | | 02/20/2008 | | | | 0 | | | | 350,000 | | | | 700,000 | | | | 0 | | | | | | | | | | | | | | | | | |
| | | | (3 | ) | | | 12/22/2007 | | | | 230,625 | | | | 384,375 | | | | 768,750 | | | | 0 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Matthew D. Cabell | | | (1 | ) | | | 12/05/2007 | | | | | | | | | | | | | | | | 25,000 | | | | | | | | | | | $ | 47.60 | | | | 1,190,000 | |
| | | | (1 | ) | | | 02/20/2008 | | | | | | | | | | | | | | | | | | | | 25,000 | | | $ | 47.37 | | | $ | 47.60 | | | | 218,438 | |
| | | | (2 | ) | | | 02/20/2008 | | | | 0 | | | | 225,000 | | | | 450,000 | | | | | | | | | | | | | | | | | | | | | |
| | | | (3 | ) | | | 12/22/2007 | | | | 0 | | | | 288,438 | | | | 576,876 | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Anna Marie Cellino | | | (1 | ) | | | 02/20/2008 | | | | | | | | | | | | | | | | | | | | 12,500 | | | $ | 47.37 | | | $ | 47.60 | | | | 109,219 | |
| | | | (2 | ) | | | 02/20/2008 | | | | 0 | | | | 100,000 | | | | 200,000 | | | | 0 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| John R. Pustulka | | | (1 | ) | | | 02/20/2008 | | | | | | | | | | | | | | | | | | | | 12,500 | | | $ | 47.37 | | | $ | 47.60 | | | | 109,219 | |
| | | | (2 | ) | | | 02/20/2008 | | | | 0 | | | | 100,000 | | | | 200,000 | | | | 0 | | | | | | | | | | | | | | | | | |
| | |
(1) | | The stock appreciation rights shown on this table were granted under the 1997 Award and Option Plan with a ten-year term, and will vest in 1/3 increments on February 20, 2009, February 20, 2010 and February 20, 2011, if certain performance conditions are met. Mr. Cabell’s restricted stock will vest in 5,000 share increments on 12/5/2011, 12/5/2012, 12/5/2013, 12/5/2014 and 12/5/2015. The exercise price of the SARs is based on the average of the high and low market price of the Common Stock on the date of grant. The SARs may be exercised any time after the “vest date” and prior to the expiration date, if the performance conditions are met, and the holder remains employed by the Company, and subject to the Company’s Insider Trading Policy. Please refer to the narrative disclosure under “Potential Payments Upon Termination or Change-in-Control” section within this proxy statement for additional information regarding termination prior to and after the vest date of the options. |
|
(2) | | This line lists the range of possible payments under the National Fuel Gas Company Performance Incentive Program for which target awards were established in fiscal 2008 with a performance period that begins October 1, 2007 and ends on September 30, 2010. |
|
(3) | | For Messrs. Ackerman, Tanski, Smith and Cabell, this represents the annual cash incentive target set in fiscal 2008 under the At Risk Plan. |
|
(4) | | This column shows the hypothetical value of the SARs awarded according to a Black-Scholes-Merton option-pricing model. The assumptions used in this model for the SARs granted on February 20, 2008 were: quarterly dividend yield of 0.65%, an annual standard deviation (volatility) of 17.69% (calculation of volatility based on average of high and low price), a risk-free rate of 3.754%, and an expected term before exercise of 7.25 years. Whether the assumptions used will prove accurate cannot be known at the date of grant. The model produces a value based on freely tradable securities, which the options are not. The holder can derive a benefit only to the extent the market value of Company Common Stock is higher than the exercise price at the date of actual exercise and performance targets are met. Please refer to Note A under the heading “Stock-Based Compensation” in the Company’s financial statements in Form 10-K for the fiscal year ended September 30, 2008 for additional detail regarding the accounting for these awards. |
The Company’s named executive officers serve at the pleasure of the Board of Directors and are not employed pursuant to employment agreements. Each of the named executive officers is a party to an Employment Continuation and Noncompetition Agreement with the Company, which would become effective upon a change in control of the Company. In addition, David F. Smith and the Company are parties to a Retirement Benefit Agreement that provides Mr. Smith with certain retirement benefits in the event the Company terminates him without cause, or Mr. Smith terminates employment with good reason, prior to the first day of the month after which Mr. Smith reaches 571/2 years of age or March 1, 2011. The Employment Continuation and Noncompetition Agreements and the Retirement Benefit Agreement for David F. Smith are described in this proxy statement under Potential Payments Upon Termination or Change-in-Control.
19
Outstanding Equity Awards at Fiscal Year-End 2008
The following table sets forth, on an award-by-award basis, the number of securities underlying unexercised stock options or SARs and the total number and aggregate market value of shares of unvested restricted stock held by the named executives as of September 30, 2008. The table also provides the exercise price (average of the high and low on grant date) and date of expiration of each unexercised stock option or SAR.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Option/SAR Awards | | | | | | | | | | Stock Awards |
| | | | | | | | | | | Number of | | | | | | | | | | |
| | | | | | | Number of | | Securities | | | | | | | | | | |
| | | | | | | Securities | | Underlying | | | | | | | | | | Number of | | |
| | | | | | | Underlying | | Unexercised | | | | | | | | | | Shares or | | Market Value of |
| | | | | | | Unexercised | | Options/SARs | | | | | | | | | | Units of Stock | | Shares or Units of |
| | | | | | | Options/SARs | | (#) | | Option/SAR | | Option/SAR | | That Have Not | | Stock That Have |
| | | Grant Date | | (#) | | Unexercisable | | Exercise Price | | Expiration Date | | Vested (#) | | NotVested ($) |
| Name | | (2) | | Exercisable | | (2) | | ($)(3) | | (4) | | (5) | | (5) |
| Philip C. Ackerman | | | 12/10/98 | | | | 315,660 | | | | 0 | | | $ | 23.03 | | | | 12/11/2008 | | | | | | | | | |
| | | | 12/9/99 | | | | | | | | | | | | | | | | | | | | 1,328 | | | $ | 54,335 | |
| | | | 2/17/00 | | | | 435,312 | | | | 0 | | | | 21.33 | | | | 2/18/2010 | | | | 0 | | | | 0 | |
| | | | 12/7/00 | | | | 500,000 | | | | 0 | | | | 27.80 | | | | 12/8/2010 | | | | 0 | | | | 0 | |
| | | | 3/14/02 | | | | 195,918 | | | | 0 | | | | 24.50 | | | | 3/15/2012 | | | | 0 | | | | 0 | |
| | | | 3/29/05 | | | | 160,000 | | | | 0 | | | | 28.16 | | | | 6/1/2013 | | | | 0 | | | | 0 | |
| | | | 5/10/06 | | | | 100,000 | | | | 0 | | | | 35.11 | | | | 6/1/2013 | | | | 0 | | | | 0 | |
| | | | 12/6/06 | | | | 110,000 | | | | 0 | | | | 39.48 | | | | 6/1/2013 | | | | 0 | | | | 0 | |
| David F. Smith | | | 3/14/02 | | | | 4,082 | | | | 0 | | | | 24.50 | | | | 3/14/2012 | | | | 0 | | | | 0 | |
| | | | 3/14/02 | | | | 125,918 | | | | 0 | | | | 24.50 | | | | 3/15/2012 | | | | 0 | | | | 0 | |
| | | | 3/29/05 | | | | 60,000 | | | | 0 | | | | 28.16 | | | | 3/30/2015 | | | | 0 | | | | 0 | |
| | | | 5/10/06 | | | | 55,000 | | | | 0 | | | | 35.11 | | | | 5/10/2016 | | | | 0 | | | | 0 | |
| | | | 12/6/06 | | | | 60,000 | | | | 0 | | | | 39.48 | | | | 12/6/2016 | | | | 0 | | | | 0 | |
| | | | 2/20/08 | | | | | | | | 70,000 | | | | 47.37 | | | | 2/20/2018 | | | | 0 | | | | 0 | |
| Ronald J. Tanski | | | 12/10/98 | | | | 5,000 | | | | 0 | | | | 23.03 | | | | 12/10/2008 | | | | 0 | | | | 0 | |
| | | | 2/17/00 | | | | 4,688 | | | | 0 | | | | 21.33 | | | | 2/17/2010 | | | | 0 | | | | 0 | |
| | | | 2/17/00 | | | | 20,312 | | | | 0 | | | | 21.33 | | | | 2/18/2010 | | | | 0 | | | | 0 | |
| | | | 12/7/00 | | | | 25,000 | | | | 0 | | | | 27.80 | | | | 12/8/2010 | | | | 0 | | | | 0 | |
| | | | 3/14/02 | | | | 4,082 | | | | 0 | | | | 24.50 | | | | 3/14/2012 | | | | 0 | | | | 0 | |
| | | | 3/14/02 | | | | 70,918 | | | | 0 | | | | 24.50 | | | | 3/15/2012 | | | | 0 | | | | 0 | |
| | | | 3/29/05 | | | | 40,000 | | | | 0 | | | | 28.16 | | | | 3/30/2015 | | | | 0 | | | | 0 | |
| | | | 5/10/06 | | | | 36,000 | | | | 0 | | | | 35.11 | | | | 5/10/2016 | | | | 0 | | | | 0 | |
| | | | 12/6/06 | | | | 45,000 | | | | 0 | | | | 39.48 | | | | 12/6/2016 | | | | 0 | | | | 0 | |
| | | | 2/20/08 | | | | | | | | 45,000 | | | | 47.37 | | | | 2/20/2018 | | | | 0 | | | | 0 | |
| Matthew D. Cabell | | | 12/11/06 | (1) | | | | | | | 100,000 | | | | 39.50 | | | | 12/11/2016 | | | | 15,000 | | | | 613,725 | |
| | | | 12/5/07 | | | | | | | | 0 | | | | | | | | | | | | 25,000 | | | | 1,022,875 | |
| | | | 2/20/08 | | | | | | | | 25,000 | | | | 47.37 | | | | 2/20/2018 | | | | 0 | | | | 0 | |
| Anna Marie Cellino | | | 12/7/00 | | | | 25,000 | | | | 0 | | | | 27.80 | | | | 12/8/2010 | | | | 0 | | | | 0 | |
| | | | 3/14/02 | | | | 70,918 | | | | 0 | | | | 24.50 | | | | 3/15/2012 | | | | 0 | | | | 0 | |
| | | | 3/29/05 | | | | 30,000 | | | | 0 | | | | 28.16 | | | | 3/30/2015 | | | | 0 | | | | 0 | |
| | | | 5/10/06 | | | | 12,000 | | | | 0 | | | | 35.11 | | | | 5/10/2016 | | | | 0 | | | | 0 | |
| | | | 12/6/06 | | | | 15,000 | | | | 0 | | | | 39.48 | | | | 12/6/2016 | | | | 0 | | | | 0 | |
| | | | 2/20/08 | | | | | | | | 12,500 | | | | 47.37 | | | | 2/20/2018 | | | | 0 | | | | 0 | |
| John R. Pustulka | | | 3/14/02 | | | | 4,082 | | | | 0 | | | | 24.50 | | | | 3/14/2012 | | | | 0 | | | | 0 | |
| | | | 3/29/05 | | | | 35,000 | | | | 0 | | | | 28.16 | | | | 3/30/2015 | | | | 0 | | | | 0 | |
| | | | 5/10/06 | | | | 12,000 | | | | 0 | | | | 35.11 | | | | 5/10/2016 | | | | 0 | | | | 0 | |
| | | | 12/6/06 | | | | 15,000 | | | | 0 | | | | 39.48 | | | | 12/6/2016 | | | | 0 | | | | 0 | |
| | | | 2/20/08 | | | | | | | | 12,500 | | | | 47.37 | | | | 2/20/2018 | | | | 0 | | | | 0 | |
20
| | |
(1) | | On November 16, 2006, the Compensation Committee approved the award of the stock options and restricted stock subject to Mr. Cabell commencing employment as President of Seneca Resources Corporation. The actual award date was Mr. Cabell’s first day of employment, December 11, 2006. |
|
(2) | | Options vest one year after grant date except for the following awards: |
|
| | Options granted on March 14, 2002 vested over a period of 3 years — 1/3 on March 14, 2003, 1/3 on March 14, 2004 and the balance on March 13, 2005. |
|
| | Options granted on March 29, 2005 vested on June 29, 2005. |
|
| | Options and restricted stock granted on December 11, 2006 will vest on December 11, 2009. |
|
| | Stock-settled SARs granted on February 20, 2008 vest over a period of 3 years — 1/3 on February 20, 2009, 1/3 on February 20, 2010 and 1/3 on February 20, 2011, subject to fulfillment of performance conditions. |
|
(3) | | Awards were issued at Fair Market Value (FMV), as defined by the stockholder approved 1997 Award and Option Plan as the average of the high and low trade prices on the day of exercise. |
|
(4) | | Option expiration date unless there is a premature termination of employment or a “change in control” or “change in ownership” of the Company as defined in the Plan. |
|
(5) | | For Mr. Ackerman, represents a 1999 award of 1,328 shares of restricted stock which will vest in January 2009. For Mr. Cabell, represents an award of 15,000 shares of restricted stock that will vest on December 11, 2009 and an award of 25,000 shares of restricted stock that will vest in one fifth increments on December 5, 2011, 2012, 2013, 2014 and 2015, subject to Mr. Cabell’s continued employment. The market value represents the total number of unvested restricted stock shares multiplied by the FMV as of September 28, 2008. |
Please refer to the “Potential Payments Upon Termination or Change-in-Control” section within this proxy statement for additional information regarding termination prior to and after the vest date of the awards.
21
Option Exercises and Stock Vested — Fiscal 2008
The following table sets forth, as to each named executive officer, information with respect to stock option exercises and vesting of restricted stock during fiscal 2008.
| | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| | | Number of | | Value | | Number of | | Value |
| | | Shares | | Realized | | Shares | | Realized |
| | | Acquired on | | on | | Acquired on | | on |
| | | Exercise | | Exercise | | Vesting | | Vesting |
| Name | | (#) | | ($)(1) | | (#) | | ($) |
| Philip C. Ackerman | | | 4,082 | | | $ | 148,197 | | | | 0 | | | $ | 0 | |
| David F. Smith | | | 20,000 | | | | 621,250 | | | | 0 | | | | 0 | |
| Ronald J. Tanski | | | 20,000 | | | | 473,221 | | | | 0 | | | | 0 | |
| Matthew D. Cabell | | | 0 | | | | 0 | | | | 0 | | | | 0 | |
| Anna Marie Cellino | | | 0 | | | | 0 | | | | 0 | | | | 0 | |
| John R. Pustulka | | | 120,918 | | | | 2,850,593 | | | | 0 | | | | 0 | |
| | |
(1) | | Represents the aggregate difference between the exercise price and the fair market value of the common stock on the date of exercise. |
Pension Benefits
The following table sets forth information with respect to the pension benefits as of September 30, 2008 of each of the named executive officers. The Company offers a qualified pension plan and a supplemental benefit plan in which certain of the named executive officers participate.
| | | | | | | | | | | | | | | |
| | | | | Number of | | Present Value | | Payments |
| | | | | Years | | of | | During |
| | | | | Credited | | Accumulated | | Last |
| | | | | Service | | Benefit | | Fiscal Year |
| Name | | Plan Name | | (#)(1) | | ($)(1) | | ($) |
| Philip C. Ackerman | | Executive Retirement Plan | | | 40 | | | | 12,701,345 | | | | 0 | |
| | | National Fuel Gas Company Retirement Plan | | | 39 | | | | 1,284,352 | | | | 35,889 | |
| David F. Smith | | Executive Retirement Plan | | | 30 | | | | 2,708,381 | | | | 0 | |
| | | National Fuel Gas Company Retirement Plan | | | 29 | | | | 857,219 | | | | 0 | |
| Ronald J. Tanski | | Executive Retirement Plan | | | 29 | | | | 1,667,362 | | | | 0 | |
| | | National Fuel Gas Company Retirement Plan | | | 28 | | | | 842,799 | | | | 0 | |
| Matthew Cabell | | Executive Retirement Plan | | | N/A | | | | N/A | | | | N/A | |
| (not a participant) | | National Fuel Gas Company Retirement Plan | | | N/A | | | | N/A | | | | N/A | |
| Anna Marie Cellino | | Executive Retirement Plan | | | 27 | | | | 639,456 | | | | 0 | |
| | | National Fuel Gas Company Retirement Plan | | | 26 | | | | 719,740 | | | | 0 | |
| John R. Pustulka | | Executive Retirement Plan | | | 34 | | | | 928,454 | | | | 0 | |
| | | National Fuel Gas Company Retirement Plan | | | 33 | | | | 1,229,151 | | | | 0 | |
| | |
(1) | | The years of credited service and present value of accumulated benefits were determined by Mercer the plan actuary using the same assumptions used for accounting and disclosure purposes. Please refer to Note G, Retirement Plan and Other Post-retirement Benefits, to the Company’s financial statements for a discussion of these assumptions. |
Retirement Plan
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The National Fuel Gas Company Retirement Plan (the “Retirement Plan”) is a tax-qualified defined benefit plan. The Retirement Plan provides unreduced retirement benefits at termination of employment at or after age 65, or, with ten years of service, at or after age 60. For the Retirement Plan, credited service is the period that an employee is a participant in the plan and receives pay from the Company or one of its participating subsidiaries. Credited service does not include the first year of employment and is measured in years, with a maximum of 40 years of credited service. The Retirement Plan does not permit the granting of extra years of credited service to the participants.
A reduced retirement benefit is available upon attainment of age 55 and completion of ten years of service. For retirement between ages 55 and 60, the benefit is reduced by 5% for each year retirement precedes age 60 (for example, a participant who retires at age 59 would receive a retirement benefit equal to 95% of the unreduced benefit). However, participants may retire with no reduction in their accrued benefit on or after the date on which the sum of their age plus years of service equals ninety. Mr. Ackerman retired as of June 1, 2008. The present value of his accumulated Benefit is as of his retirement date. As of September 30, 2008, Mr. Smith is eligible for an early retirement benefit of 75% of the unreduced benefit. Mr. Smith is eligible for certain retirement benefits under his Retirement Benefit Agreement if, prior to March 1, 2011, he is terminated for cause or resigns for good reason. See the “Potential Payments Upon Termination or Change-in-Control” section within this proxy statement. As of September 30, 2008, Mr. Tanski is eligible for an early retirement benefit equal to 80% of the unreduced benefit. Mrs. Cellino is eligible for an early retirement benefit equal to 75% of the unreduced benefit and Mr. Pustulka is eligible for an early retirement benefit equal to 80% of the unreduced benefit.
The base benefit under the Retirement Plan is a life annuity that is calculated as the product of (a), (b) and (c), where (a) is final average pay, (b) is years of credited service, and (c) is 1.5%. Final average pay is the average of the participant’s total pay during the five consecutive years of highest pay from the last ten years of participation. Total pay includes base salary, bonus payments, and annual At Risk Plan payments. Total pay does not include reimbursements or other expense allowances, imputed income, deferrals under the National Fuel Gas Company Deferred Compensation Plan (the “DCP”), fringe benefits, or Performance Incentive Program awards or equity awards. The benefit under the Retirement Plan is limited by maximum benefits and compensation limits under the Internal Revenue Code.
Other forms available at retirement include joint and survivor, term-certain, and Social Security adjusted annuities. All are calculated on an actuarially equivalent basis using a 6% interest rate and unisex mortality factors developed from 1971 Group Annuity Mortality Table rates.
Executive Retirement Plan
The National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan (the “ERP”) is a non-tax-qualified deferred compensation plan. The Chief Executive Officer of the Company designates all participants of the ERP.
The ERP provides a two-part benefit: a Tophat Benefit and a Supplemental Benefit. The Tophat Benefit makes an ERP participant whole for any reduction in the regular pension he or she receives under the Retirement Plan resulting from Internal Revenue Code limitations and/or participation in the Company’s deferred compensation plan. The Supplemental Benefit provides an additional retirement benefit to the Retirement Plan.
The Tophat Benefit vests in the same manner and subject to the same service requirements that apply to the Retirement Plan. The Supplemental Benefit vests at age 55 and completion of five years of credited service. An ERP participant who vests in the Tophat Benefit, but does not vest in the Supplemental Benefit, receives only a Tophat Benefit. A participant who is vested in both the Tophat Benefit and the Supplemental Benefit and who terminates service with the Company before age 65 receives the Tophat Benefit and a portion of the Supplemental Benefit that is based upon the participant’s age and years of credited service. For the Executive Retirement Plan, credited service is the number of years the participant has been employed by the Company or one of its participating subsidiaries, not to exceed forty years.
The Tophat Benefit is stated as a life annuity that is calculated as the difference between (a) and (b), where (a) is the benefit the ERP participant would have received under the Retirement Plan but for the limitations imposed by the Internal Revenue Code and adjusted as if deferrals under the deferred compensation plan were not excluded from the definition of final average pay; and (b) is the base benefit the participant receives under the Retirement Plan.
Assuming retirement at age 65, the Supplemental Benefit is stated as a life annuity that is calculated using the following formula:
(a) 1.97% of final average pay for each year of service not in excess of 30 years; plus
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(b) 1.32% of final average pay for each of the next 10 years of service that are in excess of 30 (but not to exceed 10); minus
(c) 1.25% of an assumed Social Security benefit (calculated as if the participant had no future wages) for each year of service not in excess of 40 years; minus
(d) the participant’s base benefit under the Retirement Plan; minus
(e) the participant’s Tophat Benefit.
Final average pay under the ERP is the same as under the Retirement Plan, except that deferrals to DCP are not excluded and the Internal Revenue Code limitations are not considered.
If a participant retires before age 65, the amounts determined in (a) and (b) above are multiplied by an early retirement percentage from the table that follows:
| | | | | |
| | | Early |
| Retirement | | Retirement |
| Age | | Percentage |
| 65 | | | 100 | |
| 64 | | | 94 | |
| 63 | | | 88 | |
| 62 | | | 82 | |
| 61 | | | 70 | |
| 60 | | | 58 | |
| 59 | | | 46 | |
| 58 | | | 34 | |
| 57 | | | 22 | |
| 56 | | | 10 | |
| 55 and 2 months | | | 0 | |
The early retirement percentages set forth above are increased by 1.5% for each year of service in excess of 30 years (provided the total early retirement percentage does not exceed 100%).
The normal form of benefit under the ERP is a four-year period certain annuity that is actuarially equivalent to the lump-sum present value (calculated using the most recently published mortality table that is generally accepted by American actuaries and reasonably applicable to the ERP, and a 6 percent discount rate) of the sum of the participant’s Tophat Benefit and Supplemental Benefit (if the participant is vested therein). Other available forms of payment include single life, ten-year period certain and life, and joint and survivor annuities.
Nonqualified Defined Contribution and Other Nonqualified Deferred Compensation Plans
The Deferred Compensation Plan (DCP) is a non-qualified deferred compensation plan, which was instituted for certain high-level management employees of the Company and certain subsidiaries. The DCP is not an active plan and has been closed with no deferrals since July 31, 2002. The purpose of the DCP was to provide retirement/savings financial planning opportunities, which were not available to the officers in the qualified retirement plans due to Internal Revenue Code limitations. All account balances are subject to the general creditors of the Company.
DCP participants were able to defer receipt of portions of their salaries and bonuses, to be paid to them following retirement, termination of employment, death or earlier in certain circumstances. The participants were eligible to elect a “Savings” and/or a “Retirement” account. For DCP deferrals prior to May 1, 1994, the Company credited deferred amounts and all earnings with interest equal to the Moody’s Composite Average of Yields on Corporate Bonds (“Moody’s Index”) in effect for the month of May prior to the plan year beginning August 1 plus 135% of the Moody’s Composite Average of Yields on Corporate Bonds (“Accumulation Account”). The participant signed a contract selecting the amount to be deferred for the upcoming deferral period, the type of account (Savings and/or Retirement), annuity term (5, 10 or 15 years) if a Retirement account and up to three dates with percentages and/or dollar amounts if a Savings account. The annuity for the Retirement account is determined by setting the interest rate on all outstanding balances at 135% of the average of the Moody’s Index in effect for the 60-month period that ends with the month preceding the month of retirement.
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Beginning with deferrals after May 1, 1994, the participants could select a Savings and/or a Retirement account similar to DCP deferrals prior to May 1, 1994 but without the Accumulation Account and including one additional investment opportunity. The two investment choices were the Moody’s Composite Average of Yields on Corporate Bonds in effect for the month of May prior to the plan year beginning August 1 and a return equal to the total return of the Standard and Poor’s 500 stock index minus 1.2% per annum (“S&P 500 Minus 1.2% Election”). The participant could select either the Moody’s Index or the S&P 500 Minus 1.2% Election, but not both within the same account. For deferrals after May 1, 1994, the rate of 135% of Moody’s was no longer available. In addition, participants with deferrals after May 1, 1994 could elect to defer their Savings and Retirement account balance past their retirement date, but not past age 70.
The DCP deferral contract indicates the participant’s investment selection and future payouts or retirement choices regarding the term of the annuity (5, 10 or 15 years). A participant who selected the S&P 500 Minus 1.2% Election for his Retirement account may, after he reaches age 55, switch once to the Moody’s Index. For a participant who retires and elected to invest in the S&P 500 Minus 1.2% Election, the investment’s return will assume the Moody’s Index six months prior to his retirement date in order to determine the final benefit.
The Company also maintains a non-qualified tophat plan. See note (1) below. The Company pays the 401(k) tophat benefit no later than March 15 of the calendar year following the year in which the tophat benefit was earned.
See “Potential Payments Upon Termination or Change-in-Control” section within this proxy statement for additional information regarding the effect of termination of employment on the DCP.
The following table reflects the earnings, distributions and total balance of the National Fuel Gas Company Deferred Compensation Plan (DCP) and 401(k) Tophat Plan:
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Aggregate | | | | |
| | | Executive | | Registrant | | Earnings | | Aggregate | | Aggregate |
| | | Contributions | | Contributions | | (Loss) in | | Withdrawals/ | | Balance at |
| | | in Last FY | | in Last FY | | Last FY | | Distributions | | Last FYE |
| Name | | ($) | | ($)(1) | | ($)(2) | | ($)(3) | | ($)(4) |
| Philip C. Ackerman | | | 0 | | | | 94,100 | | | | (140,441 | ) | | | 130,458 | | | | 1,544,990 | |
| David F. Smith | | | 0 | | | | 90,838 | | | | (50,133 | ) | | | 41,096 | | | | 255,482 | |
| Ronald J. Tanski | | | 0 | | | | 60,619 | | | | 0 | | | | 43,564 | | | | 56,869 | |
| Matthew D. Cabell | | | 0 | | | | 6,400 | | | | 0 | | | | 3,000 | | | | 4,900 | |
| Anna Marie Cellino | | | 0 | | | | 18,630 | | | | (23,083 | ) | | | 10,795 | | | | 274,280 | |
| John R. Pustulka | | | 0 | | | | 12,060 | | | | (4,144 | ) | | | 10,795 | | | | 108,484 | |
| | |
(1) | | This represents the 401(k) tophat which gives each officer, except Mr. Cabell, an additional match (6%) on the following forms of compensation: i.) base salary that exceeds the IRS maximum salary allowed for the 401(k) plan; ii.) regular bonus and iii.) Annual At Risk Plan. Mr. Cabell receives a 3% company match within the 401(k) plan. His 401(k) tophat match is based on his annual base salary that exceeds the IRS maximum salary limit. The above amounts represent the benefit earned in fiscal 2008 and also appears in the Summary Compensation Table under Other Income. There are no earnings on this benefit and it cannot be deferred. |
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(2) | | This represents the net losses during the fiscal year for the Deferred Compensation Plan. The earnings associated with the Moody’s Index were more than offset by the losses associated with the S&P 500 minus 1.2% elections during the year. Mr. Ackerman’s, Mrs. Cellino’s and Mr. Pustulka’s earnings (loss) include $32,017, $1,003 and $468, respectively, of Above Market Rate of Interest in respect to DCP plan balances that were credited with the Moody’s Index. The total Above Market Rate of Interest is included in the Compensation Table under Column (i). Mr. Smith, and Mr. Tanski were not credited with Above Market Rate of Interest on their DCP balances. The DCP interest credited for the S&P 500 Minus 1.2% Election is not considered Above Market because a similar type of investment choice is offered within the 401(k) plan which is generally available to full-time employees with six months of service. The net effect of the two investment choices resulted in an overall decrease in account balances. |
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(3) | | This represents the annual tophat payment for the calendar year ended December 31, 2008 for all officers except Mr. Ackerman. The amount in this column for Mr. Ackerman represents the tophat payment of $99,309 made in January 2008 plus DCP annuity payments of $31,149 paid to him after his retirement for the period June 1 through September 30, 2008. |
|
(4) | | This represents the ending DCP balance, if any, plus the 401(k) tophat accruals for the period January 1, 2008 through |
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| | |
| | September 30, 2008. Mr. Ackerman’s DCP account balance and 401(k) tophat accrual on June 1, 2008, his retirement date, was $1,707,218. |
Potential Payments Upon Termination or Change-in-Control
The information below describes and quantifies certain compensation that would become payable under existing plans and arrangements if the named executive officer’s employment had terminated on September 30, 2008 (the last business day of the Company’s fiscal year), assuming the named executive officer’s compensation and service levels as of that date and, if applicable, based on the fair market value (FMV) of the Common Stock on that date. The FMV is the average of the high and low stock price on September 30, 2008. These benefits are in addition to benefits available generally to most salaried employees.
National Fuel Gas Company Performance Incentive Program
Termination for Cause
Regardless of whether the performance period has been completed and the named executive officer would have been entitled to a cash payment, if a named executive officer’s employment is terminated for Cause at any time prior to payment under this program, the named executive officer is no longer entitled to the payment.
“Cause” under the Performance Incentive Program generally means:
| • | | the executive’s failure to comply with a reasonable and lawful written directive of the Board of Directors or the Chief Executive Officer;Exhibits |
| |
| | • | | the executive’s failure to perform the substantial responsibilities | Form of his position; |
| Letter Regarding Deferred Compensation Plan and Internal Revenue Code Section 409A, dated July 12, 2005 (Exhibit 10.6,Form 10-K for fiscal year ended September 30, 2005 inFile No. 1-3880) |
| | • | | any act of dishonesty, gross negligence, or misconduct by | National Fuel Gas Company Tophat Plan, effective March 20, 1997 (Exhibit 10,Form 10-Q for the executive; |
| quarterly period ended June 30, 1997 in FileNo. 1-3880) |
| | • | | the executive’s conviction of or entering a plea of guilty or nolo contendere (will not contest) | Amendment No. 1 to a crime constituting a felony or the executive’s willful violation of any law, rule or regulation; or |
| National Fuel Gas Company Tophat Plan, dated April 6, 1998 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 1998 in FileNo. 1-3880) |
| | • | | | Amendment No. 2 to National Fuel Gas Company Tophat Plan, dated December 10, 1998 (Exhibit 10.1,Form 10-Q for the executive engagesquarterly period ended December 31, 1998 in any business which is competitive with that of the Company. |
Termination for Any Other Reason
If a named executive officer’s employment terminates during a performance period for any reason other than Cause, the named executive officer will be entitled to the amount that would have been payable to the named executive officer if the named executive officer remained employed for the entire performance period, pro-rated based on the number of days completed within said performance period prior to termination. Any payment to the named executive officer will also be subject to any conditions as determined by the Chief Executive Officer.
Change of Control
In the event of a Change of Control, the performance period will be truncated, and the Compensation Committee will determine each named executive officer’s payment based on achievement of the performance conditions. The payment will be pro-rated based on the truncated time period.
“Change of Control” under the Performance Incentive Program generally means:
| • | | notice of a Schedule 13D filing with the SEC disclosing that any person (as such term is used in Section 13(d) of the 1934 Act) is the beneficial owner, directly or indirectly, of twenty (20) percent or more of the outstanding stock of the Company; |
| FileNo. 1-3880) |
| | • | | a tender or exchange offer to acquire, directly or indirectly, twenty (20) percent or more | Form of the outstanding stock of the Company; |
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| • | | consolidation or merger of the CompanyLetter Regarding Tophat Plan and Internal Revenue Code Section 409A, dated July 12, 2005 (Exhibit 10.7,Form 10-K for fiscal year ended September 30, 2005 in which the Company is not the surviving corporation, other than a consolidation or merger of the Company in which holders of its stock immediately prior to the consolidation or merger have substantially the same proportionate ownership of common stock of the surviving corporation immediately after the consolidation or merger as immediately before; |
| FileNo. 1-3880) |
| | • | | consolidation | National Fuel Gas Company Tophat Plan, Amended and Restated December 7, 2005 (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2005 in which the Company is the surviving corporation but in which the common stockholders of the Company immediately prior to the consolidation or merger do not hold at least a majority of the outstanding common stock of the continuing or surviving corporation; |
| FileNo. 1-3880) |
| | • | | sale or other transfer of all or substantially all | National Fuel Gas Company Tophat Plan, as amended September 20, 2007 (Exhibit 10.3,Form 10-K for the assets of the Company; or |
| fiscal year ended September 30, 2007 in FileNo. 1-3880) |
| | • | | a change in the majority of the members of the Board of Directors of the Company within a 24-month period unless the election or nomination for election by the Company’s stockholders of each new director was approved by the vote of at least two-thirds of the directors then still in office who were in office at the beginning of the 24-month period. |
National Fuel Gas Company 1997 Award and Option Plan
Noncompetition
Under this plan, if a named executive officer engages in any business or activity competitive with that of the Company, without the Company’s written consent, or the named executive officer performs any act that is against the best interests of the Company, all unexercised, unearned or unpaid awards are forfeited.
Termination of Employment
As a general rule, if the named executive officer’s employment with the Company terminates for a reason other than death, disability, retirement, or any approved reason, all unexercised, unearned or unpaid awards are forfeited, unless otherwise stated below or in an award notice to the named executive officer. The Compensation Committee has the authority to determine what events constitute disability, retirement, or termination for an approved reason.
Incentive Stock Options
Except as otherwise disclosed in an award letter, if the named executive officer’s employment with the Company terminates, any incentive stock option that has not expired will terminate, and the named executive officer will no longer be entitled to purchase shares of the Company’s Common Stock pursuant to such incentive stock option except that:
i.) Upon termination of employment (other than by death), the named executive officer may, within three months after the date of termination of employment, purchase all or part of the shares of the Common Stock which the named executive officer was entitled to purchase under the incentive stock option on the date of termination of employment. However, if termination of employment occurs by reason of death, disability or retirement at age 65 or later, then the Company must offer to extend the term of those incentive stock options to the lesser of five years or the original term, unless the named executive officer is president or chief executive officer of the Company or president of a “principal subsidiary” (an entity owned at least 80% by the Company with at least $5 million net income in the most recently completed fiscal year), in which case the Company must offer to extend the term of that person’s incentive stock options to the original term.
ii.) Upon the death of the named executive officer while employed with the Company or within three months after the date of termination of employment, the executive officer’s estate or beneficiary may, within one year after the date of the named executive officer’s death, purchase all or part of any shares of Common Stock which the named executive officer was entitled to purchase under such incentive stock option on the date of death.
Non-Qualified Stock Options and Stock Appreciation Rights
Except as otherwise disclosed in an award letter, any non-qualified stock option (including any stock-settled stock appreciation right) that has not expired will terminate upon the termination of the named executive officer’s employment with the Company, and no shares of Common Stock may be purchased pursuant to the non-qualified stock option, except that:
i.) Upon termination of employment for any reason other than death, discharge by the Company for cause, or voluntary resignation of the named executive officer prior to age 60, a named executive officer may, within five years after the date of termination of employment, or any such greater period of time that the Compensation Committee deems appropriate, exercise all or
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part of the non-qualified stock option, which the named executive officer was entitled to exercise on the date of termination of employment or subsequently becomes eligible to exercise as follows: (a) six months after the date of grant, if the named executive officer has voluntarily resigned on or after his 60th birthday, after the date of grant, and before such six months; or (b) on the date of the named executive officer’s voluntary resignation on or after his 60th birthday and at least six months after the date of grant. However, if termination of employment occurs by reason of death, disability or retirement at age 65 or later and if the named executive officer is the president or chief executive officer of the Company, or president of a principal subsidiary, then each non-qualified stock option would remain exercisable for the balance of its unexpired term.
ii.) Upon the death of a named executive officer while employed with the Company or within the period stated in the preceding paragraph i.), the named executive officer’s estate or beneficiary may, within five years after the date of the named executive officer’s death while employed, or within the period stated in paragraph i.) above, exercise all or part of the non-qualified stock option, which the named executive officer was entitled to exercise on the date of death.
As specified in Mr. Cabell’s award letter, upon a voluntary termination of employment or an involuntary termination for Just Cause, all non-qualified stock options are forfeited. Upon an involuntary termination due to death or for other than Just Cause, all non-qualified stock options will become exercisable and will remain exercisable for three years.
Restricted Stock
As specified in Mr. Cabell’s award letter dated December 12, 2006, the following will occur with respect to his restricted stock upon a termination:
i.) unless his termination is due to death or termination by the Company without Just Cause, he will forfeit his right to the restricted stock if his employment with the Company terminates for any reason prior to the expiration of the vesting restrictions;
ii.) in the event of either his termination by the Company without Just Cause or his death before December 11, 2009, all restrictions will lapse on the date of his death or termination without Just Cause.
In this context, “Just Cause” means the failure to comply with Company policies on hedging, financial reporting, accurate accounting, disclosure of information about the Company, or regulatory compliance; fraud, misconduct, or dishonesty related to employment; illegal conduct amounting to a misdemeanor or felony; or the willful and continued failure to substantially perform duties with the Company after written warnings specifically identifying the lack of substantial performance.
Change in Control and Change in Ownership
If there is a Change in Ownership or a named executive officer’s employment terminates within three years following a Change in Control, unless the termination is due to death, disability, Cause, resignation by the named executive officer other than for Good Reason, or retirement, all terms and conditions lapse, and all unvested awards become vested. In addition, any outstanding awards are cashed out based on the Fair Market Value of the Common Stock as of either the date the Change in Ownership occurs or the date of termination following a Change in Control. For this purpose, “Fair Market Value” is the average of the high and low market price. In addition, the noncompetition provision mentioned above will become null and void.
For purposes of this section, “Change in Control” has a meaning similar to the definition of Change of Control, which was defined earlier under the Performance Incentive Program section. The only major difference between the 1997 Award and Option Plan definition of Change in Control and the Performance Incentive Program Change of Control definition is that the 1997 Award and Option Plan provides that a Change in Control shall be deemed to have occurred at such time as individuals who constitute the Board of Directors of the Company on January 1, 1997 (the “Incumbent Board”) have ceased for any reason to constitute at least a majority, provided that any person becoming a director subsequent to January 1, 1997 whose election, or nomination for election by the Company’s stockholders, was approved by a vote of at least three-quarters of the directors comprising the Incumbent Board (either by specific vote or by approval of the proxy statement of the Company in which such person is named as nominee for director without objection to such nomination) shall be considered as though such person was a member of the Incumbent Board. The Performance Incentive Program instead states that a Change of Control shall be deemed to have occurred when there is change in the majority of the members of the Board of Directors of the Company within a 24-month period unless the election or nomination for election by the Company’s stockholders of each new director was approved by the vote of at least two-thirds of the directors then still in office who were in office at the beginning of the 24-month period.
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“Change in Ownership” means a change which results directly or indirectly in the Common Stock ceasing to be actively traded on a national securities exchange or the National Association of Securities Dealers Automated Quotation System.
“Good Reason” means a good faith determination made by a named executive officer that the Company has materially reduced the responsibilities, prestige or scope of the named executive officer’s position. Examples include the assignment to the named executive officer of duties inconsistent with the named executive officer’s position, assignment of the executive to another place of employment more than 30 miles from the named executive officer’s current place of employment, or reduction in the named executive officer’s total compensation or benefits. The named executive officer must specify the event relied upon for his or her determination by written notice to the Board of Directors within six months after the occurrence of the event.
National Fuel Gas Company Tophat Plan
Under the Company’s Tophat Plan, the Company restores to the named executive officers benefits lost under the 401(k) Plan due to the Internal Revenue Code or qualified plan limits.
Retirement or Termination of Employment
If a named executive officer retires or his employment is terminated, the named executive officer (or his beneficiary in the event of his death) will receive a lump sum payment equal to the value of his benefit, as of the date of retirement or termination of employment.
National Fuel Gas Company 2007 Annual at Risk Compensation Incentive Plan (“AARCIP”)
Noncompetition
If, in the opinion of the Compensation Committee, the named executive officer, without the written consent of the Company, engages in any business or activity that is competitive with that of the Company, or the named executive officer performs any act which in the opinion of the Committee is against the best interests of the Company, the named executive officer must forfeit all unearned and/or unpaid At Risk Awards.
Termination of Employment Other Than Due to Death, Disability, Retirement, Or an Approved Reason
If a named executive officer’s employment with the Company or a subsidiary terminates for a reason other than death, disability, retirement, or an approved reason, all unearned or unpaid At Risk Awards will be canceled or forfeited, unless stated below or in an award notice to the named executive officer. The Compensation Committee has the authority to determine what events constitute disability, retirement, or termination for an approved reason.
Termination Due to Disability, Retirement, Or an Approved Reason
In the event of the disability, retirement or termination for an approved reason of a named executive officer during a performance period, the named executive officer’s participation will be deemed to continue to the end of the performance period, and the named executive officer will be paid a percentage of the amount earned, based upon the extent, if any to which the respective performance criteria are attained, proportionate to the named executive officer’s period of active service during the performance period.
Death
If a named executive officer dies during a performance period, the named executive officer’s beneficiary will be paid an amount proportionate to the period of active service during the performance period, based upon the maximum amount, which the named executive officer could have earned under the At Risk Award.
Change in Control and Change in Ownership
In the event of a Change in Ownership (which has the same definition as provided in the 1997 Award and Option Plan, discussed above) or a named executive officer’s employment terminates within three years following a Change in Control, unless the termination is due to death, disability entitling the named executive officer to benefits under the Company’s long-term disability plan, Cause, resignation by the named executive officer other than for Good Reason (which has the same definition as provided in the 1997 Award and Option Plan, discussed above), or retirement entitling the named executive officer to benefits under the Company’s retirement plan, the named executive officer will be entitled to a single lump sum cash payment equal to a prorated portion of the At Risk Award previously established for the performance period which has commenced but has not yet ended, and 100% of the At Risk Award previously earned by, but not yet paid, to the named executive officer during each performance period that has ended.
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“Change in Control” under the AARCIP has the same meaning as provided in the 1997 Award and Option Plan, discussed above, except with respect to an incumbent board. The AARCIP provides that a Change in Control occurs if individuals who constitute the Board on January 1, 2007 (the “Incumbent Board) cease to constitute at least a majority, provided that any person becoming a director subsequent to January 1, 2007 whose election, or nomination for election by the Company’s stockholders, was approved by a vote of at least three-quarters of the directors comprising the Incumbent Board will be considered as though he or she was a member of the Incumbent Board.
“Cause” means the executive’s willful and continued failure to substantially perform his duties after written warnings specifically identifying his lack of substantial performance or his willful engaging in illegal conduct which is materially and demonstrably injurious to the Company or its subsidiaries.
Deferred Compensation Plan (“DCP”)
The term Change in Control under the DCP has a similar definition as provided in the Performance Incentive Program, discussed above.
Termination For Any Reason Other Than Death or Retirement Prior to a Change in Control
In the event of a termination for any reason, other than death or retirement, prior to a Change in Control, the named executive officer is entitled to receive any undistributed savings account balance and his retirement account balance in the form of a lump sum payment. However, the named executive officer will not be entitled to the accumulation account balance.
Termination After A Change in Control or Death
If the named executive officer’s employment terminates for any reason, other than retirement, after a Change in Control or the named executive officer dies at any time during his employment with the Company, the named executive officer (or his beneficiary) will receive in the form of a lump sum payment any undistributed savings account balance, retirement account balance, and accumulation account balance.
Retirement
In the case of retirement at any time, the named executive officer is entitled to a monthly payment (a 15-year annuity, unless the named executive officer elected to receive a 5- or 10-year annuity) based on his retirement account balance and accumulation account balance; provided that the named executive officer provides the Company at least 90 days notice of his retirement. However, if the named executive officer does not have a retirement account balance and his accumulation account balance is less than $5,000 at the date of retirement, that account will be paid in the form of a lump sum equal to the value of the account. If the named executive officer dies before the commencement of the retirement annuity, the entire DCP balance will be paid in full as a lump sum payment to the named executive officer’s beneficiary. If the named executive officer dies after commencement of the annuity, the annuity will continue to be paid to the named executive officer’s beneficiary for the remainder of its original term.
Under the plan, for certain deferrals after May 1, 1994, Mr. Ackerman was eligible and elected to defer a portion of his salary to a retirement account that would entitle him to commence monthly payments beginning the first of the month coinciding with or following his 70th birthday.
Employment Continuation and Noncompetition Agreement
If there is a change in control, and the executive remains employed thereafter, the executive’s annual salary and employee benefits are preserved for at least three years at the levels then in effect for the named executive officers. The Agreement also provides the benefits described below.
Termination by the Company Without Cause Or Termination By the Executive For Good Reason
Severance Benefit
In the event of termination of a named executive officer within three years of a Change in Control without Cause or by the named executive officer for Good Reason, the named executive officer is entitled to a single lump sum cash payment equal to 1.99 times the sum of the named executive officer’s annual base salary and the average of the annual cash bonus for the previous two fiscal years.
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The named executive officers are also entitled to any vested benefits under the employee benefit plans, including any compensation previously deferred and not yet paid and any amounts payable pursuant to any agreement with the named executive officer.
If the named executive officer’s employment terminates at any time during the three year period ending on the first day of the month following the named executive officer’s sixty-fifth birthday, the multiplier will not be 1.99, but will be a number equal to 1.99 times (x/1095), where x equals the number of days remaining until the named executive officer’s sixty-fifth birthday. In addition, the extension of any welfare benefits will cease at age 65.
“Cause” means the named executive’s gross misconduct, fraud or dishonesty, which has resulted or is likely to result in material economic damage to the Company or its subsidiaries as determined in good faith by a vote of at least two-thirds of the non-employee directors of Company at a meeting of the Board.
“Change in Control” has a similar definition as provided in the Performance Incentive Program, discussed above. However, Mr. Cabell’s agreement also provides that a Change in Control will occur if the Company sells more than 50% ownership of Seneca Resources.
“Good Reason” means there is a material diminution in the named executive’s responsibilities, base compensation or budget, or in the responsibilities of the person to whom the named executive is required to report. “Good Reason” also includes a requirement that the named executive relocate to an office outside the United States or more than 30 miles from the location at which the executive performed his services immediately prior to the Change in Control, or any other action or inaction that constitutes a material breach by the Company of the agreement. The Company has a period of 30 days to cure any acts which would otherwise give the executive the right to terminate his employment for Good Reason.
Continuation of Health and Welfare Benefits
In addition to the severance payment, the named executive officer will be entitled to participate in the Company’s employee and executive health and welfare benefit plans, excluding any vacation benefits, for eighteen months following termination (or, in the case of Mr. Cabell, until the end of the second calendar year following termination for purposes of any non-health-related benefit) or until the named executive officer becomes eligible for comparable benefits at a subsequent employer.
Retirement
Except for Mr. Cabell, if the named executive officer is at least fifty-two years old at the date of termination, the named executive officer will be deemed to have earned and be vested in the retirement benefits that are payable to the named executive officer under the Company retirement plans.
Mr. Cabell will be entitled to a single lump sum payment equal to the present value of his unvested accrued benefits under the Company’s retirement plans, which he participated in immediately before the Change in Control.
Termination for Cause or the Executive Voluntarily Terminates
If the named executive officer’s employment is terminated for Cause, death, disability, or the named executive officer voluntarily terminates his employment other than for Good Reason, the named executive officer will not be entitled to the severance benefit discussed above. The named executive officer (or his beneficiary) will be entitled to any vested benefits under the employee benefit plans, including any compensation previously deferred and not yet paid and any amounts payable pursuant to any agreement between the named executive officer and the Company. The named executive officer will also be entitled to any other benefits provided in the Company’s plans for death or disability.
Noncompetition
Unless the named executive officer has elected not to be bound by the noncompete provisions of the Agreement, the Company will make a lump sum payment of one times the sum of the named executive officer’s annual base salary and the average of the annual cash bonus for the previous two fiscal years. The noncompete payment will not be paid to the named executive officer if his employment is terminated by reason of death or disability.
In order for the named executive officer to be entitled to the noncompete payment, the named executive officer may not directly or indirectly engage in, become employed by, serve as an agent or consultant to, or become a partner, principal or stockholder (other than a holder of less than 1% of the outstanding voting shares of any publicly held company) of any business or entity that is engaged in any activity which is competitive with the business of the Company or its subsidiaries or affiliates in any geographic area in which the Company or its subsidiaries are engaged in competitive business.
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Split Dollar ArrangementAmended and Restated Split Dollar Insurance and Death Benefit Agreement for Philip C. Ackerman The Company has maintained a split dollar life insurance arrangement with Mr. Ackerman since 1991, as amended from time to time. The split dollar arrangement formerly required that i.) the Company would pay, until his retirement date, the premiums on two life insurance policies owned by Mr. Ackerman (ownership later transferred to a life insurance trust established by Mr. Ackerman), ii.) the Company would be repaid its premiums upon the earlier of his 70th birthday or death, and iii.) if he died before age 70 his beneficiaries would receive a death benefit from the policies of no more than twice the sum of his most recent annual salary and lump sum compensation, with any additional death benefit payable to the Company. In light of Sarbanes-Oxley’s prohibition on loans to executive officers, the Company stopped paying premiums on those policies in 2002. All subsequent premiums on those policies have instead been paid from the policies owned by Mr. Ackerman’s trust. In fiscal 2006, the trust transferred to the Company one of its insurance policies as a partial early repayment to the Company of the insurance premiums previously paid by the Company, which left one existing insurance policy covered by the split dollar arrangement. To place Mr. Ackerman in approximately the position he would have been in had the Company not been prohibited under Sarbanes-Oxley from performing its obligations under the split dollar arrangement, in fiscal 2006 the Company and Mr. Ackerman agreed that i.) if Mr. Ackerman dies before his 70th birthday, the Company will pay his beneficiaries a death benefit equal to the sum of 24 times his base monthly salary in the month prior to his death or retirement plus two times the most recent award, if any, paid to him under the Company’s lump sum payment programs other than the Performance Incentive Program, reduced by the amount received by his trust from the remaining insurance policy pursuant to the split dollar arrangement, or ii.) if Mr. Ackerman is living on his 70th birthday, the Company’s agreement to pay a death benefit will terminate, and the Company will make a cash payment to Mr. Ackerman in the amount of $968,905. This cash amount represents the amount that, at that time, was projected as the difference between the cash surrender value that would have been available to Mr. Ackerman at age 70 under the original arrangement (net of the premiums that would have been repayable to the Company) over the projected net cash surrender value available to Mr. Ackerman’s trust on his 70th birthday under the remaining insurance policy.
Retirement Benefit Agreement for David F. Smith
The Retirement Benefit Agreement for David F. Smith provides Mr. Smith with certain retirement benefits in the event the Company terminates Mr. Smith without Cause, or Mr. Smith terminates employment with Good Reason, prior to March 1, 2011 (the first day of the month after which Mr. Smith reaches 571/2 years of age). “Cause” means the failure by Mr. Smith to substantially perform duties or the engaging in illegal conduct, gross misconduct, fraud or dishonesty, which injures the Company in a material way. “Good Reason” means a significant reduction in the nature and scope of duties and direct reporting responsibilities, a significant reduction in total potential compensation, or a requirement to relocate more than 100 miles away from the Company’s headquarters.
The payment that Mr. Smith would receive under the Retirement Benefit Agreement would be calculated to ensure that Mr. Smith receives benefits equivalent to what he would have received under the terms of the Executive Retirement Plan and the qualified Retirement Plan if he had attained age 571/2 at the time of his termination of employment. The Retirement Benefit Agreement will terminate on March 1, 2011 if benefits have not become payable under the agreement. In addition, the agreement will terminate before March 1, 2011 if Mr. Smith is terminated for any reason other than a termination by the Company without cause or by Mr. Smith with Good Reason.
Potential Payments Upon Termination or Change-in-Control Table
Due to the number of factors that affect the nature and amount of any benefit provided upon the events discussed above, any actual amounts paid or distributed may be different from the amounts contained in the table. Factors that could affect these amounts include the timing during the year of any such event, the market value of the Common Stock and the named executive officer’s age. For Column (2), “Retirement,” will be “N/A” if the named executive officer was not eligible to retire on September 30, 2008. In that case, the Company would have accrued benefits payable to the named executive officer, which are accrued amounts in the other columns for the different types of terminations. Mr. Ackerman retired from the Company effective June 1, 2008. Therefore, the table for Mr. Ackerman below sets forth information with respect to retirement only.
The payments that would have been due upon a “termination for cause” on September 30, 2008 other than in connection with a change-in-control are not shown in a separate column in the following table. The payments that would have been due in that case are the Deferred Compensation Plan balances of $169,519 for Mr. Smith, $0 for Mr. Tanski, $0 for Mr. Cabell, $256,482 for Mrs. Cellino and $97,256 for Mr. Pustulka and the accrued 401(k) Tophat Plan benefit for the period January 1, 2008 to September 30, 2008 of $84,575 for Mr. Ackerman, $85,963 for Mr. Smith, $56,869 for Mr. Tanski, $4,900 for Mr. Cabell, $17,798 for Mrs. Cellino and $11,228 for Mr. Pustulka. All of the unvested and vested stock options and restricted stock awards would have been forfeited on the date of termination for cause other than in connection with a change-in-control.
The payments that would have been due upon an “involuntary termination” other than for cause and other than in connection with a change in control are the same as the payments under Column (1) for “Voluntary Termination,” with the following exceptions: i.) the “Bonus-At-Risk Award” could have been paid if termination was for an approved reason, such as a reduction in force, ii.) the unvested
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stock options would have vested if not already reflected as vested under Column (1), iii.) Mr. Smith would have received a benefit of $1,231,072 under the Retirement Benefit Agreement, and iv.) for Mr. Cabell, the unvested Restricted Stock would have vested upon termination.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Potential Payments Upon Termination | | | | | | | | | | | | | | | | | | | | | Following a Change in Control or Change in | | | | | | | | | | | | | | | | | | | | | Board | | | | | | | | | | | | | | | | | | | | | Company | | | | | | | | | | | | | | | | | | | | | | | | | | | | Terminates | | | | | | | | | | | | | | | | | | | | | | | | | | | | without Cause | | | | | | | | | | | | | | | | | | | | | | | | | | | | and/or | | | | | | | Executive | | | | | Potential Payments Upon Termination Other | | | Executive | | | | | | | Terminates | | | Executive Benefits | | than in Connection with a Change in Control | | | Terminates | | | Company | | | Voluntarily Other | | | and Payments | | Voluntary | | | | | | | | | | | | | | | for Good | | | Terminates | | | than for Good | | | Upon Termination | | Termination | | | Retirement | | | Death | | | Disability | | | Reason | | | for Cause | | | Reason | | | for: | | $(1) | | | $(2) | | | $(3) | | | $(4) | | | $(5) | | | $(6) | | | $(7) | | Mr. Philip Ackerman | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Bonus — At Risk Award(b) | | | N/A | | | | 1,146,667 | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | Performance Incentive Program(c) | | | N/A | | | | 2,802,212 | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | Deferred Compensation Plan(h) | | | N/A | | | | 1,622,643 | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | Executive Retirement Plan(i) | | | N/A | | | | 3,560,248 | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | 401k Tophat(k) | | | N/A | | | | 84,575 | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | Death Benefit(n) | | | N/A | | | | (n | ) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | Welfare Plan Benefits and Fringe Benefits(o) | | | N/A | | | | 11,053 | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | | | | | | | | | | | | | | | | | | | | | | Total for Mr. Ackerman | | | N/A | | | | 9,227,398 | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Mr. David Smith | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Severance(a) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 2,773,283 | | | | 0 | | | | 0 | | | Bonus — At Risk Award(b) | | | 0 | | | | 1,125,625 | | | | 1,125,625 | | | | 1,125,625 | | | | 1,125,625 | | | | 0 | | | | 0 | | | Performance Incentive Program(c) | | | 1,377,227 | | | | 1,377,227 | | | | 1,377,227 | | | | 1,377,227 | | | | 1,377,227 | | | | 0 | | | | 1,377,227 | | | Non-Compete(d) | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 1,393,610 | | | | 1,393,610 | | | | 1,393,610 | | | Vested and Outstanding exercisable Options(g) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 3,306,150 | | | | 0 | | | | N/A | | | Deferred Compensation Plan(h) | | | 169,519 | | | | 196,979 | | | | 169,519 | | | | 196,979 | | | | 169,519 | | | | 169,519 | | | | 169,519 | | | Executive Retirement Plan(i) | | | 761,401 | | | | 761,401 | | | | 202,391 | | | | 761,401 | | | | 761,401 | | | | 0 | | | | 761,401 | | | Retirement Agreement(j) | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 84,563 | | | | 0 | | | | 0 | | | 401k Tophat(k) | | | 85,963 | | | | 85,963 | | | | 85,963 | | | | 85,963 | | | | 85,963 | | | | 85,963 | | | | 85,963 | | | Post-retirement/Post- termination Health Care(m) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 26,302 | | | | N/A | | | | N/A | | | Welfare Plan Benefits and Fringe Benefits(o) | | | 0 | | | | 7,731 | | | | 0 | | | | 7,731 | | | | 11,597 | | | | 0 | | | | 0 | | | | | | | | | | | | | | | | | | | | | | | | | Total for Mr. Smith | | | 2,394,110 | | | | 3,354,626 | | | | 2,960,725 | | | | 3,554,926 | | | | 11,115,240 | | | | 1,649,092 | | | | 3,787,720 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Mr. Ronald Tanski | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Severance(a) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 2,250,917 | | | | 0 | | | | 0 | | | Bonus — At Risk Award(b) | | | 0 | | | | 730,313 | | | | 730,313 | | | | 730,313 | | | | 730,313 | | | | 0 | | | | 0 | | | Performance Incentive Program(c) | | | 953,785 | | | | 953,785 | | | | 953,785 | | | | 953,785 | | | | 953,785 | | | | 0 | | | | 953,785 | | | Non-Compete(d) | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 1,131,114 | | | | 1,131,114 | | | | 1,131,114 | | | Vested and Outstanding exercisable Options(g) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 2,922,888 | | | | N/A | | | | N/A | | | Executive Retirement Plan(i) | | | 512,138 | | | | 512,138 | | | | 126,093 | | | | 512,138 | | | | 512,138 | | | | 0 | | | | 512,138 | | | 401k Tophat(k) | | | 56,869 | | | | 56,869 | | | | 56,869 | | | | 56,869 | | | | 56,869 | | | | 56,869 | | | | 56,869 | | | Post-retirement/Post- termination Health Care(m) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 26,302 | | | | N/A | | | | N/A | | | Welfare Plan Benefits and Fringe Benefits(o) | | | 0 | | | | 1,720 | | | | 0 | | | | 1,720 | | | | 17,580 | | | | 0 | | | | 0 | | | | | | | | | | | | | | | | | | | | | | | | | Total for Mr. Tanski | | | 1,522,792 | | | | 2,254,825 | | | | 1,867,060 | | | | 2,254,825 | | | | 8,601,906 | | | | 1,187,983 | | | | 2,653,906 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Mr. Matthew Cabell | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Severance(a) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 1,495,296 | | | | 0 | | | | 0 | | | Bonus — At Risk Award (b) | | | N/A | | | | N/A | | | | 337,472 | | | | 337,472 | | | | 337,472 | | | | 0 | | | | 0 | | | Performance Incentive Program(c) | | | 431,772 | | | | N/A | | | | 431,772 | | | | 431,772 | | | | 431,772 | | | | 0 | | | | 431,772 | | | Non-Compete(d) | | | 0 | | | | N/A | | | | 0 | | | | 0 | | | | 751,045 | | | | 751,045 | | | | 751,045 | | | Unvested Restricted Stock(e) | | | 0 | | | | N/A | | | | 1,636,600 | | | | 1,636,600 | | | | 1,636,600 | | | | 0 | | | | 0 | | | Unvested Stock Options(f) | | | 0 | | | | N/A | | | | 141,500 | | | | 141,500 | | | | 141,500 | | | | 0 | | | | 0 | | | 401k Tophat(k) | | | 4,900 | | | | N/A | | | | 4,900 | | | | 4,900 | | | | 4,900 | | | | 4,900 | | | | 4,900 | | | RSA Tophat(l) | | | 3,267 | | | | N/A | | | | 3,267 | | | | 3,267 | | | | 3,267 | | | | 3,267 | | | | 3,267 | | | Post-retirement/Post- termination Health Care(m) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 21,774 | | | | N/A | | | | N/A | | | | | | | | | | | | | | | | | | | | | | | | | Total for Mr. Cabell | | | 439,939 | | | | N/A | | | | 2,555,511 | | | | 2,555,511 | | | | 4,801,852 | | | | 759,212 | | | | 1,190,984 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Ms. Anna Marie Cellino | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Severance(a) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 956,195 | | | | 0 | | | | 0 | | | Short Term Incentive bonus(b) | | | 0 | | | | 250,000 | | | | 250,000 | | | | 250,000 | | | | 250,000 | | | | 0 | | | | 0 | | | Performance Incentive Program(c) | | | 308,210 | | | | 308,210 | | | | 308,210 | | | | 308,210 | | | | 308,210 | | | | 0 | | | | 308,210 | | | Non-Compete(d) | | | 0 | | | | N/A | | | | 0 | | | | 0 | | | | 480,500 | | | | 480,500 | | | | 480,500 | | | Vested and Outstanding exercisable Options(g) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 1,966,531 | | | | N/A | | | | N/A | | | Deferred Compensation Plan(h) | | | 256,482 | | | | 273,799 | | | | 256,482 | | | | 273,799 | | | | 256,482 | | | | 256,482 | | | | 256,482 | | | Executive Retirement Plan(i) | | | 162,090 | | | | 162,090 | | | | 51,628 | | | | 162,090 | | | | 162,090 | | | | 0 | | | | 162,090 | | | 401k Tophat(k) | | | 17,798 | | | | 17,798 | | | | 17,798 | | | | 17,798 | | | | 17,798 | | | | 17,798 | | | | 17,798 | | | Post-retirement/Post- termination Health Care(m) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 26,302 | | | | N/A | | | | N/A | | | Welfare Plan Benefits and Fringe Benefits(o) | | | 0 | | | | N/A | | | | 0 | | | | N/A | | | | 15,000 | | | | 0 | | | | 0 | | | | | | | | | | | | | | | | | | | | | | | | | Total for Mrs. Cellino | | | 744,580 | | | | 1,011,897 | | | | 884,118 | | | | 994,099 | | | | 4,939,108 | | | | 754,780 | | | | 1,225,080 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Mr. John Pustulka | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash Severance(a) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 847,243 | | | | 0 | | | | 0 | | | Short Term Incentive bonus(b) | | | 0 | | | | 140,500 | | | | 140,500 | | | | 140,500 | | | | 140,500 | | | | 0 | | | | 0 | | | Performance Incentive Program(c) | | | 308,210 | | | | 308,210 | | | | 308,210 | | | | 308,210 | | | | 308,210 | | | | 0 | | | | 308,210 | | | Non-Compete(d) | | | 0 | | | | N/A | | | | 0 | | | | 0 | | | | 425,750 | | | | 425,750 | | | | 425,750 | | | Vested and Outstanding exercisable Options(g) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 604,696 | | | | N/A | | | | N/A | | | Deferred Compensation Plan(h) | | | 97,256 | | | | 101,706 | | | | 97,256 | | | | 101,706 | | | | 97,256 | | | | 97,256 | | | | 97,256 | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Potential Payments Upon Termination | | | | | | | | | | | | | | | | | | | | | Following a Change in Control or Change in | | | | | | | | | | | | | | | | | | | | | Board | | | | | | | | | | | | | | | | | | | | | Company | | | | | | | | | | | | | | | | | | | | | | | | | | | | Terminates | | | | | | | | | | | | | | | | | | | | | | | | | | | | without Cause | | | | | | | | | | | | | | | | | | | | | | | | | | | | and/or | | | | | | | Executive | | | | | Potential Payments Upon Termination Other | | | Executive | | | | | | | Terminates | | | Executive Benefits | | than in Connection with a Change in Control | | | Terminates | | | Company | | | Voluntarily Other | | | and Payments | | Voluntary | | | | | | | | | | | | | | | for Good | | | Terminates | | | than for Good | | | Upon Termination | | Termination | | | Retirement | | | Death | | | Disability | | | Reason | | | for Cause | | | Reason | | | for: | | $(1) | | | $(2) | | | $(3) | | | $(4) | | | $(5) | | | $(6) | | | $(7) | | | Executive Retirement Plan(i) | | | 263,724 | | | | 263,724 | | | | 64,190 | | | | 263,724 | | | | 263,724 | | | | 0 | | | | 263,724 | | | 401k Tophat(k) | | | 11,228 | | | | 11,228 | | | | 11,228 | | | | 11,228 | | | | 11,228 | | | | 11,228 | | | | 11,228 | | | Post-retirement/Post- termination Health Care(m) | | | N/A | | | | N/A | | | | N/A | | | | N/A | | | | 26,302 | | | | N/A | | | | N/A | | | Welfare Plan Benefits and Fringe Benefits(o) | | | 0 | | | | 3,350 | | | | 0 | | | | 3,350 | | | | 20,025 | | | | 0 | | | | 0 | | | | | | | | | | | | | | | | | | | | | | | | | Total for Mr. Pustulka | | | 680,418 | | | | 828,718 | | | | 621,384 | | | | 828,718 | | | | 2,744,934 | | | | 534,234 | | | | 1,106,168 | | | | | | | | | | | | | | | | | | | | | | | | |
| | | (a) | | For all officers, other than Mr. Ackerman who retired at June 1, 2008, severance is equal to 1.99 multiplied by the sum of i.) annual base salary and ii.) the average of the named executive officer’s annual cash bonus for the two fiscal years of the Company ending immediately prior to the effective date of the change in control. The earned salary and severance amount shall be paid in cash in a lump sum. | | (b) | | Represents the Annual At Risk Award or Short Term Incentive bonus paid in December 2008 that was earned in fiscal 2008. This amount also appears in the Summary Compensation table. | | (c) | | The target incentive payable to Mr. Ackerman of $2,802,212 at September 30, 2008, represents the estimated target incentive if he were to die. The total estimated payment of $2,802,212 is composed of $1,082,900 for the three-year performance period ended September 30, 2008, $859,656 for the three-year performance period ended September 30, 2009, and $859,656 for the three-year performance period ended September 30, 2010. | | | | The target incentive payable to Mr. Smith of $1,377,227 at September 30, 2008, represents the estimated target incentive if he were to terminate, except for cause, as a participant of the three separate performance periods. The total estimated payment of $1,377,227 is composed of $624,750 for the three-year performance period ended September 30, 2008, $427,607 for the three-year performance period ended September 30, 2009, and $324,870 for the three-year performance period ended September 30, 2010. | | | | The target incentive payable to Mr. Tanski of $953,785 at September 30, 2008, represents the estimated target incentive if he were to terminate, except for cause, as a participant of the three separate performance periods. The total estimated payment of $953,785 is composed of $416,500 for the three-year performance period ended September 30, 2008, $342,918 for the three-year performance period ended September 30, 2009, and $194,367 for the three-year performance period ended September 30, 2010. | | | | The target incentive payable to Mrs. Cellino and Mr. Pustulka of $308,210 at September 30, 2008, represents the estimated target incentive if she/he were to terminate, except for cause, as a participant of the three separate performance periods. The total estimated payment of $308,210 is composed of $141,610 for the three-year performance period ended September 30, 2008, $111,067 for the three-year performance period ended September 30, 2009, and $55,533 for the three-year performance period ended September 30, 2010. | | | | The target incentive payable to Mr. Cabell of $431,772 at September 30, 2008, represents the estimated target incentive if he were to terminate, except for cause, as a participant in two of the three performance periods in which he participates. The total estimated payment of $431,772 is composed of $306,822 for the three-year performance period ended September 30, 2009 and $124,950 for the three-year performance period ended September 30, 2010. | | | | The above payments in respect of any three-year performance period will be paid in a lump sum cash amount not later than 21/2 months after the end of the calendar year in which the relevant performance period ends. | | (d) | | If the named executive officer elected to be bound by the non-compete provision contained in the Employment Continuation and Noncompetition Agreement, he shall receive a lump sum payment within 30 days following the named executive officer’s date of termination equal to one times the sum of i.) the named executive officer’s annual base salary and ii.) the named executive officer’s average cash bonus payable to the named executive officer for the two fiscal years of the company ending immediately prior to the effective date of the change in control, as compensation for the covenant not to compete. | | (e) | | The value, at September 30, 2008, of any restricted stock that would have vested upon the termination of employment for the stated reason on September 30, 2008. |
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| | | (f) | | All named executive officers except for Mr. Ackerman have unvested options. However, only Mr. Cabell has certain options with a positive value as of September 30, 2008. Specifically, options granted in February 2008 vest in 1/3 increments on February 20, 2009, February 20, 2010, and February 20, 2011, subject to satisfaction of performance conditions. Because the exercise price of $47.37 is higher than the FMV of the stock on September 30, 2008 of $40.915, these February 2008 options have no value. Mr. Cabell also has unvested options issued on December 11, 2006 that would have vested at certain termination events and are scheduled to vest on December 11, 2009. The exercise price of Mr. Cabell’s December 2006 options is $39.50. | | (g) | | This represents the total number of vested options outstanding at September 30, 2008 multiplied by the difference between the FMV of stock on September 30, 2008 and the exercise price of each option. Under the terms of the 1997 Award and Option Plan this amount will be paid in a lump sum, which is why this is separately disclosed. | | (h) | | Represents the Deferred Compensation Plan (“DCP”) balances as of September 30, 2008, except for Mr. Ackerman whose balance is as of June 1, 2008. Under the plan, DCP retirement and disability benefits are the same for participants listed on this table (Columns 2 and 4) and are calculated with the Plan-mandated switch to the Moody’s index rate six months prior to retirement or disability for those participants who elected a return based on the S&P 500 Minus 1.2% Election. For those participants, DCP retirement and disability benefits will be different than DCP benefits provided upon death or voluntary termination other than retirement. DCP benefits provided upon death are the full lump sum value of all account balances, with no switch to the Moody’s index rate as noted above (Column 3). DCP benefits provided upon termination other than death, retirement or disability are the lump sum value of all accounts. Benefits are paid as a lump sum in all situations except retirement or disability, in which case benefits are paid as an annuity. | | | | Upon retirement, Mr. Ackerman would receive three separate monthly annuities, the present value of which equals $1,622,643. The first of those three payments began on June 1, 2008, Mr. Ackerman’s retirement date, in the amount of $7,787 per month for 15 years with a present value of $821,051. The other two projected payments consist of i.) a fifteen-year annuity of $3,180 per month with a present value of $400,953 and ii.) a ten-year annuity commencing at age 70 of $5,603 per month with a present value of $400,639. Upon death, Mr. Ackerman’s beneficiary would receive a lump sum payment of the value of all accounts. | | | | Upon retirement and/or disability, Mr. Smith would receive a projected ten-year annuity of $2,169 per month with a present value of $196,979. The amounts for all other terminations are the account balances as of September 30, 2008. | | | | Upon retirement and/or disability, Mrs. Cellino would receive a projected ten-year annuity of $3,165 per month with a present value of $273,799. The amounts for all other terminations are the account balances as of September 30, 2008. | | | | Upon retirement and/or disability, Mr. Pustulka would receive two separate monthly annuities, the present value of which equals $101,706. The first is a projected five year annuity of $613 per month with a present value of $31,925. The second is a projected ten-year annuity of $839 per month with a present value of $69,781. The amounts for all other terminations are the account balances as of September 30, 2008. | | | | Mr. Tanski does not have any outstanding account balances under the DCP. Mr. Cabell is not eligible to participate in the DCP. | | (i) | | For Mr. Ackerman this is the first amount payable following retirement (subject to at least a six month delay, in accordance with IRC Section 409A). Three subsequent payments of the same amount would be made in each of the next three years pursuant to Mr. Ackerman’s election. For each of the other named executive officers, this is the value of the first payment payable under the Executive Retirement Plan (the “ERP”) that would have been due following the termination of employment for the stated reason on September 30, 2008, as elected by the named executive officer. If a payment is shown in any column on this line (except for amounts shown in the Column 3, “Death”), three additional payments of the same amount would be made under the ERP, one in each of the next three years as elected by the named executive officer. Column 3, “Death”, represents a straight life annuity payment to the named executive officer’s surviving spouse/beneficiary until his/her death. For further description of the ERP, the calculation of the benefit payable under the ERP and the applicable early retirement percentages, please refer to the caption “Executive Retirement Plan” following the Pension Benefits Table. |
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| | | | | The amounts in this row represent the following, with respect to benefits provided under the ERP: | | | | Mr. Ackerman retired on June 1, 2008 with an unreduced retirement benefit. His first Executive Retirement Plan payment will occur in January 2009, and subsequent payments will occur in January 2010, 2011 and 2012, as determined by his four year sum certain election. In the event of his death prior to commencement of the ERP benefit, Mr. Ackerman’s spouse shall receive the ERP benefit payment in the same form as elected. | | | | For Mr. Smith, in the event of termination resulting from retirement, Mr. Smith is eligible to retire with a reduced retirement benefit that includes the tophat portion of the ERP benefit, but not the supplemental portion of the ERP. In the event of a voluntary termination, involuntary termination other than for cause or disability, Mr. Smith is eligible to receive a reduced early retirement benefit. With respect to an involuntary termination for cause (willful misconduct), no retirement benefits will be paid under the ERP. In the event of death prior to commencement of the ERP benefit, Mr. Smith’s spouse shall receive the ERP benefit for her lifetime commencing on the first day of the month following the date of death. | | | | For Mr. Tanski, in the event of termination resulting from retirement, Mr. Tanski is eligible to retire with a reduced retirement benefit that includes the tophat and supplemental portions of the ERP benefit. In the event of a voluntary termination, involuntary termination other than for cause or disability, Mr. Tanski is eligible to receive a reduced early retirement benefit. With respect to an involuntary termination for cause (willful misconduct), no retirement benefits will be paid under the ERP. In the event of death prior to commencement of the ERP benefit, Mr. Tanski’s spouse shall receive the ERP benefit for her lifetime commencing on the first day of the month following the date of death. | | | | For Mrs. Cellino, in the event of termination resulting from retirement, Mrs. Cellino is eligible to retire with a reduced retirement benefit that includes the tophat portion of the ERP benefit, but not the supplemental portion of the ERP. In the event of a voluntary termination, involuntary termination other than for cause or disability, Mrs. Cellino is eligible to receive a reduced early retirement benefit. With respect to an involuntary termination for cause (willful misconduct), no retirement benefits will be paid under the ERP. In the event of death prior to commencement of the ERP benefit, Mrs. Cellino’s spouse shall receive the ERP benefit for his lifetime commencing on the first day of the month following the date of death. | | | | For Mr. Pustulka, in the event of termination resulting from retirement, Mr. Pustulka is eligible to retire with a reduced retirement benefit that includes the tophat and supplemental portions of the ERP. In the event of a voluntary termination, involuntary termination other than for cause or disability, Mr. Pustulka is eligible to receive a reduced early retirement benefit. With respect to an involuntary termination for cause (willful misconduct), no retirement benefits will be paid under the ERP. In the event of death prior to commencement of the ERP benefit, Mr. Pustulka’s spouse shall receive the ERP benefit for her lifetime commencing on the first day of the month following the date of death. | | (j) | | Represents the annual benefit payable under the Retirement Benefit Agreement, expressed as a 50% joint and survivor annuity. | | (k) | | Represents the 401(k) Tophat Plan benefit for the period January 1, 2008 throughdated September 30, 2008. | | (l) | | Represents the RSA Tophat Plan benefit for Mr. Cabell for the period January 1, 2008 through September 30, 2008. | | (m) | | For all terminations other than for a Change-in-Control: the officer receives the same health benefits as other supervisory employees hired prior to January 1, 2003. The amount shown under column (5) represents 18 months of COBRA rates for medical, drug and dental. The actual COBRA rates were used for 2008 and 2009 and the 2010 rates were projected using a 9% trend for medical, 10% for drug and 5% for dental. | | (n) | | Mr. Ackerman by contract, would receive a death benefit payment based on two times the sum of his base salary at the time of retirement and his most recent annual cash bonus, less proceeds paid under his split dollar policy. The amount that would have been paid by the Company if he had died is $1,297,469. If Mr. Ackerman survives to age 70, he would instead receive a lump sum payment of $968,905. | | (o) | | For Columns (2) and (4), this represents an allowance for tax preparation and financial planning in the year following the year of retirement and/or disability. For Column (5), this includes an allowance for tax preparation and financial planning and the annual payment for life insurance under the ExecutiveLife Insurance Plan for 18 months. Mr. Tanski, Mrs. Cellino and Mr. |
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| | | | | Pustulka are participants in the ExecutiveLife Insurance Plan. |
Directors’ Compensation
The Retainer Policy for Non-Employee Directors (the “Retainer Policy”), which replaced both the Board’s preexisting retainer policy and the Retirement Plan for Non-Employee Directors (the “Directors’ Retirement Plan”), was approved at the17, 1997 Annual Meeting of Stockholders. Directors who are not Company employees or retired employees do not participate in any of the Company’s employee benefit or compensation plans. Directors who are current employees receive no compensation for serving as directors. Only non-employee directors are covered by the Retainer Policy, under which directors are paid in money plus an amount of common stock adjusted from time to time.
In fiscal 2008, pursuant to the Retainer Policy, non-employee directors, with the exception of Mr. Ackerman, were each paid an annual retainer of $32,000 and 1,200 shares of Common Stock, payable in quarterly increments. Common Stock issued to non-employee directors under the Retainer Policy is nontransferable until the later of two years from issuance or six months after the recipient’s cessation of service as a director of the Company.
Non-employee directors were each paid a fee of $2,000 for each Board meeting and $2,000 for each Committee meeting attended in person or by telephone. Non-employee directors were each paid an additional annual retainer fee of $7,500 if appointed as Chairman of any committee; accordingly, Messrs. Brady, Matthews and Mazanec each received an additional annual retainer fee of $7,500 during fiscal 2008.
Benefit accruals under the Directors’ Retirement Plan ceased for each current non-employee director on December 31, 1996. Mr. Brady is the only current director eligible for benefits under the Directors’ Retirement Plan benefits, and will receive his accrued Directors’ Retirement Plan benefits of $1,800 per year for up to ten years. People who first become directors after February 1997 are not eligible to receive benefits under the Directors’ Retirement Plan. The Directors’ Retirement Plan pays an annual retirement benefit equal to 10% of the annual retainer in effect on December 31, 1996 ($18,000 per year), multiplied by the number of full years of service prior to January 1, 1997, but not to exceed 100% of that annual retainer. The retirement benefit would begin upon the later of the date of the director’s retirement from the board or the date the director turns age 70, and would continue until the earlier of the expiration of ten years or the death of the director.
In addition, in place of the above-described director compensation, Philip C. Ackerman, the Chairman of the Board of Directors, received director compensation under a Director Services Agreement (“Agreement”). Generally, the Agreement provides that, effective as of June 1, 2008, after Mr. Ackerman’s retirement from the Company, he will perform the duties and responsibilities of Chairman of the Board of Directors as established under the Company’s By-Laws and Corporate Governance Guidelines, and consult with the Chief Executive Officer on matters pertaining to the administration and operation of the Company that Mr. Ackerman or the Chief Executive Officer deems appropriate. In no event will Mr. Ackerman provide, or be required to provide, services during the term of the Agreement for more than the equivalent of fifty full time days in any calendar year (pro-rated for the partial calendar years during such period at the beginning and the end of the Chairman Services Period). Under the Agreement, Mr. Ackerman will receive an annual fee equal to $400,000. The Agreement is for a term of one year and as otherwise agreed by the Board, the Chief Executive Officer and by Mr. Ackerman. Under the Agreement, Mr. Ackerman is not eligible for any other compensation for his services, or to accrue any additional benefits under any employee benefit plans of the Company. The Company reimburses Mr. Ackerman for reasonable travel, lodging, meals and other appropriate expenses incurred by him and provides him with suitable office space on its premises and appropriate secretarial services on an as needed basis under the Agreement.
Under the settlement agreement between the Company and New Mountain Vantage GP, L.L.C. and its affiliates, including the California Public Employees Retirement System (collectively “Vantage”), at Vantage’s request Mr. Salerno receives no compensation for his Board service for as long as Vantage continues to hold common stock of the Company.
The Company requires that each director, in order to receive compensation for service as a director, must beneficially own at least 500 shares of Common Stock during the first year of service as a director, at least 1,000 shares during the second year of service and at least 2,500 shares thereafter. The transfer of shares issued by the Company to a director as compensation for service as a director is prohibited until the later of (i) two years after the date those shares were issued to the director, or (ii) six months after the director ceases to be as a director of the Company; however, upon death those transferability restrictions disappear.
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The following table sets forth the compensation paid to each non-employee director for service during fiscal 2008:
DIRECTOR COMPENSATION TABLE — FISCAL 2008
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Change in | | | | | | | | | | | | | | | | | | | | | | | | Pension Value | | | | | | | | Fees | | | | | | | | | | | | | | and Nonqualified | | | | | | | | Earned or | | | | | | | | | | Non-Equity | | Deferred | | | | | | | | Paid in | | Stock | | Option | | Incentive Plan | | Compensation | | All Other | | | | | | Cash ($) | | Awards | | Awards | | Compensation | | Earnings | | Compensation | | Total | | Name | | (1) | | ($)(2) | | ($) | | ($) | | (3) ($) | | (4) ($) | | ($) | | Philip C. Ackerman | | | 133,333 | | | | None | | | | None | | | | None | | | | N/A | | | | 3 | | | | 133,336 | | | Robert T. Brady | | | 75,500 | | | | 60,019 | | | | None | | | | None | | | | N/A | | | | 9 | | | | 135,528 | | | R. Don Cash | | | 88,000 | | | | 60,019 | | | | None | | | | None | | | | N/A | | | | 9 | | | | 148,028 | | | Stephen E. Ewing | | | 78,000 | | | | 60,019 | | | | None | | | | None | | | | N/A | | | | 9 | | | | 138,028 | | | Rolland E. Kidder | | | 70,000 | | | | 60,019 | | | | None | | | | None | | | | N/A | | | | 9 | | | | 130,028 | | | Craig G. Matthews | | | 75,500 | | | | 60,019 | | | | None | | | | None | | | | N/A | | | | 9 | | | | 135,528 | | | George L. Mazanec | | | 89,500 | | | | 60,019 | | | | None | | | | None | | | | N/A | | | | 9 | | | | 149,528 | | | Richard G. Reiten | | | 70,000 | | | | 60,019 | | | | None | | | | None | | | | N/A | | | | 9 | | | | 130,028 | | | John F. Riordan | | | 52,000 | | | | 60,019 | | | | None | | | | None | | | | N/A | | | | 9 | | | | 112,028 | | | Frederick V. Salerno (5) | | | None | | | | None | | | | None | | | | None | | | | N/A | | | | None | | | | None | |
| | | (1) | | Represents the portion of the annual retainer paid in cash, plus meeting fees, except for Mr. Ackerman. For Mr. Ackerman it represents the prorated portion of his annual fee due for the period of June 1 — September 30, 2008. | | (2) | | Represents the fair value as required by Statement of Financial Accounting Standards 123R, on the date of issuance, of the Common Stock issued pursuant to the current Retainer Policy. The average of the high and low stock price on each date of issuance was used to compute the fair value. The average prices were as follows: $47.07 for October 1, 2007, $46.52 for January 2, 2008, $47.35 April 1 2008 and $59.125 for July 1, 2008. As of September 30, 2008, the aggregate number of shares paid under the Retainer Policy to Messrs. Brady, Cash, Ewing, Kidder, Matthews, Mazanec, and Reiten are 10,100, 6,733, 1,946, 7,190, 4,341, 10,100, and 4,576 respectively. | | (3) | | Benefit accruals under the Directors Retirement Plan ceased for each current non-employee director on December 31, 1996. Mr. Brady is the only active director who has an accrued pension benefit under this plan. His retirement benefit will begin upon the later of the date of his retirement as a director or the date he turns age 70. His benefit is fixed at a set amount of $1,800 per year with no increase in future benefits. The Company expensed the present value of this future benefit in a prior fiscal year and continues to expense only the interest associated with this benefit. The fiscal 2008 interest expense to the Company was $ 331.65. The directors do not have a non-qualified deferred compensation plan or any other pension plan. | | (4) | | Represents premiums paid on a Blanket-Travel Insurance Policy, which covers each director up to a maximum benefit of $500,000. This insurance provides coverage in case of death or injury while on a trip for Company business. | | (5) | | Under the settlement agreement between the Company and Vantage at Vantage’s request Mr. Salerno receives no compensationPhilip C. Ackerman (Exhibit 10.5,Form 10-K for his Board servicefiscal year ended September 30, 1997 in FileNo. 1-3880) | | • | | | Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Philip C. Ackerman, dated March 23, 1999 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) | | • | | | Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and David F. Smith (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) | | • | | | Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and David F. Smith, dated March 29, 1999 (Exhibit 10.14,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) | | • | | | Life Insurance Premium Agreement, dated September 17, 2009, between the Company and David F. Smith (Exhibit 10.1,Form 8-K dated September 23, 2009 in FileNo. 1-3880) | | • | | | National Fuel Gas Company Parameters for Executive Life Insurance Plan (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2004 in FileNo. 1-3880) | | • | | | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as longamended and restated through November 1, 1995 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1995 in FileNo. 1-3880) | | • | | | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated September 18, 1997 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880) | | • | | | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated December 10, 1998 (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 1998 in FileNo. 1-3880) | | • | | | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 16, 1999 (Exhibit 10.15,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) | | • | | | Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 5, 2001 (Exhibit 10.4,Form 10-K/A for fiscal year ended September 30, 2001, in FileNo. 1-3880) | | • | | | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as Vantage continues to hold common stock of January 1, 2007 (Exhibit 10.5,Form 10-Q for the Company.quarterly period ended December 31, 2006 in FileNo. 1-3880) |
Compensation Committee Interlocks and Insider Participation
There are no “Compensation Committee interlocks” or “insider participation” which SEC regulations or NYSE listing standards require to be disclosed in this report.
Item 12Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth for each current director, each nominee for director, each of the executive officers named in the Summary Compensation Table, and for all directors and officers as a group, information concerning beneficial ownership of Common Stock. The Common Stock is the only class of Company equity securities outstanding. Unless otherwise stated, to the best of the Company’s knowledge, each person has sole voting and investment power with respect to the shares listed, including shares which the individual has the right to acquire through exercise of stock options but has not done so. All information is as of November 30, 2008, except as otherwise indicated.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Shares Held in | | | | | | | | Name of Beneficial | | Exercisable Stock | | Shares held | | 401(k) | | Restricted | | Shares Otherwise | | Percent of | | Owner | | Options(1) | | in ESOP(2) | | Plan(3) | | Stock(4) | | Beneficially Owned(5) | | Class(6) | | Philip C. Ackerman | | | 1,816,890 | | | | 22,052 | | | | 17,772 | | | | 1,328 | | | | 580,685 | (7) | | | 2.98 | % | | Robert T. Brady | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 12,600 | | | | * | | | Matthew D. Cabell | | | 0 | | | | 0 | | | | 345 | | | | 40,000 | | | | 2,000 | | | | * | | | R. Don Cash | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 11,033 | (8) | | | * | | | Anna Marie Cellino | | | 152,918 | | | | 1,054 | | | | 10,650 | | | | 0 | | | | 83,319 | | | | * | | | Stephen E. Ewing | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 3,746 | | | | * | | | Rolland E. Kidder | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 24,490 | (9) | | | * | | | Craig G. Matthews | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 6,937 | | | | * | | | George L. Mazanec | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 13,400 | (10) | | | * | | | John R. Pustulka | | | 66,082 | | | | 3,683 | | | | 13,534 | | | | 0 | | | | 30,392 | | | | * | | | Richard G. Reiten | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 5,876 | | | | * | | | Frederic F. Salerno | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 100 | | | | * | | | David F. Smith | | | 305,000 | | | | 1,774 | | | | 12,996 | | | | 0 | | | | 122,906 | (11) | | | * | | | Ronald J. Tanski | | | 251,000 | | | | 2,848 | | | | 16,181 | | | | 0 | | | | 86,158 | (12) | | | * | | | Directors and Executive Officers as a Group (19 individuals) | | | 3,230,790 | | | | 35,505 | | | | 115,675 | | | | 41,328 | | | | 1,060,898 | | | | 5.34 | % |
| | | * | | Represents beneficial ownership of less than 1% of issued and outstanding Common Stock on November 30, 2008. | | (1) | | This column lists shares with respect to which each of the named individuals, and all current directors and executive officers as a group (19 individuals), have the right to acquire beneficial ownership within 60 days of November 30, 2008, through the exercise of stock options granted under the 1997 Award and Option Plan. Stock options, until exercised, have no voting power. | | (2) | | This column lists shares held in the Company and Subsidiaries Employee Stock Ownership Plan (“ESOP”). The beneficial owners of these shares have sole voting power with respect to shares held in the ESOP, but do not have investment power respecting most of those shares until they are distributed. | | (3) | | This column lists shares held in the Company Tax-Deferred Savings Plan for Non-Union Employees (“TDSP”), a 401(k) plan. The beneficial owners of these shares have sole voting and investment power with respect to shares held in the TDSP. | | (4) | | This column lists shares of restricted stock, certain restrictions on which had not lapsed as of November 30, 2008. Owners of restricted stock have power to vote the shares, but have no investment power with respect to the shares until the restrictions lapse. | | (5) | | This column includes shares held of record and any shares beneficially owned through a bank, broker or other nominee. | | (6) | | This column lists the sum of the individual’s (or individuals’) stock options and shares shown on this table, expressed as a percent of the Company’s outstanding shares and that individual’s (or individuals’) exercisable stock options at November 30, 2008. | | (7) | | Includes 1,000 shares held by Mr. Ackerman’s wife in trust for her mother, and 76,250 shares also held in trust, as to which shares Mr. Ackerman disclaims beneficial ownership, and 220 shares with respect to which Mr. Ackerman shares voting and investment power with his wife. | | (8) | | Includes 3,000 shares held by the Don Kay Clay Cash Foundation, a Utah not-for-profit corporation, of which Mr. Cash, his wife, son and daughter-in-law are directors. Mr. Cash disclaims beneficial ownership of these shares. | | (9) | | Includes 10,000 shares owned by Mr. Kidder’s wife, as to which Mr. Kidder shares voting and investment power. | | (10) | | Includes 600 shares owned by Mr. Mazanec’s wife, as to which Mr. Mazanec shares voting and investment power. |
| | | | | | Exhibit
| | Description of
| | Number | | Exhibits | | | | | • | | | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 20, 2007 (Exhibit 10.4,Form 10-K for the fiscal year ended September 30, 2007 in FileNo. 1-3880) | | | • | | | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 24, 2008 (Exhibit 10.5,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880) | | | • | | | Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated June 1, 2010 (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 2010 in FileNo. 1-3880) | | | • | | | National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10, 1996 (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880) | | | • | | | National Fuel Gas Company Participating Subsidiaries Executive Retirement Plan 2003 Trust Agreement(I), dated September 1, 2003 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 2004 in FileNo. 1-3880) | | | • | | | National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 8-K dated June 3, 2005 in FileNo. 1-3880) | | | • | | | Description of long-term performance incentives for the period October 1, 2007 to September 30, 2010 under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880) | | | • | | | Description of long-term performance incentives for the period October 1, 2008 to September 30, 2011 under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2008 in FileNo. 1-3880) | | | • | | | Description of long-term performance incentives for the period October 1, 2009 to September 30, 2012 under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2009 in FileNo. 1-3880) | | | • | | | Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880) | | | • | | | National Fuel Gas Company 2009 Non-Employee Director Equity Compensation Plan (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2009 in FileNo. 1-3880) | | | • | | | Amended and Restated Retirement Benefit Agreement for David F. Smith, dated September 20, 2007, among the Company, National Fuel Gas Supply Corporation and David F. Smith (Exhibit 10.5,Form 10-K for the fiscal year ended September 30, 2007 in FileNo. 1-3880) | | | • | | | Description of assignment of interests in certain life insurance policies (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 2006 in FileNo. 1-3880) | | | • | | | Description of agreement between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.3,Form 10-Q for the quarterly period ended June 30, 2006 in FileNo. 1-3880) | | | • | | | Agreement, dated September 24, 2006, between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.1,Form 10-K for the fiscal year ended September 30, 2006 in FileNo. 1-3880) | | | 12 | | | Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 2006 through 2010 | | | 21 | | | Subsidiaries of the Registrant | | | 23 | | | Consents of Experts: | | | 23 | .1 | | Consent of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation | | | 23 | .2 | | Consent of Independent Registered Public Accounting Firm | | | 31 | | | Rule 13a-14(a)/15d-14(a) Certifications: | | | 31 | .1 | | Written statements of Chief Executive Officer pursuant toRule 13a-14(a)/15d-14(a) of the Exchange Act |
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| | | (11) | | Includes 51,902 shares owned by Mr. Smith’s wife, as to which Mr. Smith shares voting and investment power. | | (12) | | Includes 614 shares owned jointly with Mr. Tanski’s wife, as to which Mr. Tanski shares voting and investment power. |
| | | | | | Exhibit
| | Description of
| | Number | | Exhibits | | | | | 31 | .2 | | Written statements of Principal Financial Officer pursuant toRule 13a-14(a)/15d-14(a) of the Exchange Act | | | 32•• | | | Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | | | 99 | | | Additional Exhibits: | | | 99 | .1 | | Report of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation | | | 99 | .2 | | Company Maps | | | 101 | | | Interactive data files pursuant toRegulation S-T: (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the years ended September 30, 2010, 2009 and 2008, (ii) the Consolidated Balance Sheets at September 30, 2010 and September 30, 2009, (iii) the Consolidated Statements of Cash Flows for the years ended September 30, 2010, 2009 and 2008, (iv) the Consolidated Statements of Comprehensive Income for the years ended September 30, 2010, 2009 and 2008 and (v) the Notes to Consolidated Financial Statements. | | | • | | | Incorporated herein by reference as indicated. | | | | | | All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report onForm 10-K. | | | •• | | | In accordance with Item 601(b)(32)(ii) ofRegulation S-K and SEC Release Nos.33-8238 and34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference. |
As of November 30, 2008, the Company knows of no one who beneficially owns in excess of 5% of the Company’s Common Stock, which is the only class of Company stock outstanding, except as set forth in the table below.
| | | | | | | | | | | | | | | | | Shares Held as | | | | | | | | Trustee for Company | | Shares | | Percent | | | | Employee Benefit | | Otherwise | | of | | Name and Address of Beneficial Owner | | Plans(1) | | Beneficially held | | Class(2) | | Vanguard Fiduciary Trust Company | | | 4,665,677 | | | | 2,091,580 | (3) | | | 8.51 | % | 100 Vanguard Boulevard
Malvern, PA 19355 | | | | | | | | | | | | | | New Mountain Vantage, GP L.L.C | | | N/A | | | | 7,397,400 | (4)(5) | | | 9.31 | % | 787 7th Avenue,
49th floor
New York, NY 10091 | | | | | | | | | | | | |
| | | (1) | | This column lists the shares held by Vanguard Fiduciary Trust Company in its capacity as trustee for certain employee benefit plans. Vanguard Fiduciary Trust Company held 4,665,677 shares on behalf of the plans as of November 30, 2008, all of which have been allocated to plan participants. The plan trustee votes the shares allocated to participant accounts as directed by those participants. Shares held by the trustee on behalf of the plans as to which participants have made no timely voting directions are voted by the Trustee in the same proportion as the shares of Common Stock for which the Trustee received timely directions, except in the case where to do so would be inconsistent with provisions of Title I of ERISA. Vanguard Fiduciary Trust Company disclaims beneficial ownership of all shares held in trust by the trustee that have been allocated to the individual accounts of participants in the plans for which directions have been received, pursuant to Rule 13d-4 under the Securities Exchange Act. | | (2) | | This column lists the sum of the shares shown on this table, expressed as a percent of the Company’s outstanding shares at November 30, 2008. | | (3) | | The Vanguard Group, which is affiliated with Vanguard Fiduciary Trust Company, has sole investment and voting discretion with respect to these shares of Company common stock, according to its Form 13F for the period ended September 30, 2008. | | (4) | | These shares are derived from a Form 13F filing made by New Mountain Vantage Advisers, L.L.C. for the period ended September 30, 2008 on behalf of New Mountain Advisers, L.L.C., New Mountain Vantage GP, L.L.C. and Steven B. Klinsky. The 13F filing shows that the shares over which these entities have sole voting power are 4,720,400 shares and that there is shared voting power for 2,677,000 shares. | | (5) | | According to a Settlement Agreement dated January 24, 2008 (and filed with the SEC on that same date) among the Company and New Mountain Vantage, GP L.L.C., New Mountain Vantage, L.P., New Mountain Vantage (California), L.P., New Mountain Vantage (Texas), L.P., New Mountain Vantage Advisers, L.L.C., New Mountain Vantage (Cayman), Ltd., New Mountain Vantage HoldCo Ltd., Mr. Steven B. Klinsky, NMV Special Holdings, L.L.C., California Public Employees’ Retirement System (“CalPERS”), F. Fox Benton, III, David M. DiDomenico, Frederic V. Salerno (collectively, the “New Mountain Group”), this year the New Mountain Group (except CalPERS) must vote all of the shares which any of the New Mountain Group is entitled to vote in favor of the Board’s nominees for director, and in accordance with the Board’s recommendation on any other proposal submitted to the Company’s stockholders by a person other than the Company. The Settlement Agreement applies solely to votes cast at the 2009 Annual Meeting. CalPERS is not bound by these requirements for the 2009 Annual Meeting. In the Settlement Agreement, the New Mountain Group represents that CalPERS retained sole voting power of the 2,677,000 shares identified in note 4) above, which may also be deemed to be beneficially owned by NMV Special Holdings, L.L.C.. |
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EQUITY COMPENSATION PLAN INFORMATION
As of September 30, 2008
| | | | | | | | | | | | | | | | | | | | | | | | | Number of securities | | | | | | | | | | | | | remaining available for | | | | | Number of securities to be | | | Weighted-average exercise | | | future issuance under | | | | | issued upon exercise of | | | price of outstanding | | | equity compensation plans | | | | | outstanding options, | | | options, warrants and | | | (excluding securities | | | | | warrants and rights | | | rights | | | reflected in column (a)) | | | Plan category | | (a) | | | (b) | | | (c) | | | Equity compensation plans approved by security holders | | | 6,829,697 | | | $ | 27.30 | | | | 771,452 | (1) | | Equity compensation plans not approved by security holders | | | 0 | | | | 0 | | | | 0 | | | | | | | | | | | | | | Total | | | 6,829,697 | | | $ | 27.30 | | | | 771,452 | | | | | | | | | | | | |
| | | (1) | | Of the securities listed in column (c), 25,655 were reserved at September 30, 2008 for issuance pursuant to the Company’s Retainer Policy for Non-Employee Directors. The remaining 745,797 are available for future issuance under the 1997 Award and Option Plan. |
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Item 13Certain Relationships and Related Transactions, and Director Independence
Related Person TransactionsSignatures
The Company had no related person transactions in fiscal 2008. The Company’s Code of Business Conduct and Ethics (which is in writing and available to stockholders as described above) identifies the avoidance of any actual or perceived conflicts between personal interests and Company interests as an essential part of the responsibility of the Company’s directors, officers and employees. The Code provides that a conflict of interest may arise when a director, officer or employee receives improper personal benefits as a result of his or her position in the Company, or when personal situations tend to influence or compromise a director’s, officer’s or employee’s ability to render impartial business decisions in the best interest of the Company. Potential conflicts of interest under the Code would include but not be limited to related person transactions. The Audit Committee administers the Code as it relates to the Company’s directors and executive officers. Director Independence
The Board of Directors has determined that directors Brady, Cash, Ewing, Kidder, Matthews, Mazanec, Reiten, Salerno and Riordan, during the time he served as director, are (or were in the case of Mr. Riordan who passed away during the year after a short illness) independent, and that Mr. Ackerman, Chairman of the Board of the Company, and Mr. Smith, Chief Executive Officer and President of the Company, are not due to their employment relationship, which for Mr. Ackerman ceased June 1, 2008. The Board’s determinations of director independence were made in accordance with the listing standards of the New York Stock Exchange (NYSE) and the Director Independence Guidelines adopted by the Board and available on the Company’s website at www.nationalfuelgas.com. Generally, the Director Independence Guidelines provide that, in order for a director to be considered independent, the Board must affirmatively determine that the director has no direct or indirect material relationship with the Company or any subsidiary, after consideration of all relevant facts and circumstances not merely from the standpoint of the director, but also from that of persons or entities with which the director has an affiliation. Specifically, the Director Independence Guidelines set out seven specific circumstances in which a director will not be considered independent, and three categorical types of commercial or charitable relationships that will not be considered material relationships for purposes of determining whether a director is independent. The Director Independence Guidelines also set out four types of independence-related disclosures that the Company will continue to make.
Item 14Principal Accountant Fees and Services
AUDIT FEES
In addition to retaining PricewaterhouseCoopers LLP to report on the annual consolidated financial statements of the Company for fiscal 2008, the Company retained PricewaterhouseCoopers LLP to provide various non-audit services in fiscal 2008. The aggregate fees billed for professional services by PricewaterhouseCoopers LLP for each of the last two fiscal years were as follows:
| | | | | | | | | | | | | 2007 | | | 2008 | | | Audit Fees(1) | | $ | 1,391,150 | | | $ | 1,379,079 | | | Audit-Related Fees(2) | | $ | 20,000 | | | $ | 0 | | | Tax Fees | | | | | | | | | | Tax advice and planning(3) | | $ | 356,150 | | | $ | 44,900 | | | Tax compliance(4) | | $ | 122,595 | | | $ | 139,000 | | | All Other Fees(5) | | $ | 39,585 | | | $ | 2,610 | | | | | | | | | | | TOTAL | | $ | 1,929,480 | | | $ | 1,565,589 | | | | | | | | | |
| | | (1) | | Audit Fees include audits of consolidated financial statements and internal control over financial reporting, reviews of financial statements included in quarterly Forms 10-Q, comfort letters and consents, and audits of certain of the Company’s wholly owned subsidiaries to meet statutory or regulatory requirements. | | (2) | | Audit-Related Fees include audits of certain of the Company’s wholly-owned subsidiaries not required by statute or regulation, and consultations concerning technical financial accounting and reporting standards and implementation of the Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”). | | (3) | | Tax advice and planning includes consultations on various federal, state and foreign tax matters. |
43
| | | (4) | | Tax compliance includes tax return preparation and tax audit assistance. | | (5) | | All Other Fees relate to permissible fees other than those described above and include the software-licensing fee for an accounting and financial reporting research tool. |
The Audit Committee’s charter (available on the Company’s website at www.nationalfuelgas.com and in print to stockholders who request a copy from the Company’s Secretary at its principal office) references its pre-approval policies and procedures. The committee has pre-approved the use of PricewaterhouseCoopers LLP for specific types of services, including various audit and audit-related services and certain tax services, among others. The chair of the committee and, in his absence, another specified member of the committee are authorized to pre-approve any audit or non-audit service on behalf of the committee. Each pre-approval is to be reported to the full committee at the first regularly scheduled committee meeting following such pre-approval. The Company’s Reporting Procedures for Accounting and Auditing Matters are included in this proxy statement as Appendix C.
For fiscal 2008, none of the services provided by PricewaterhouseCoopers LLP were approved by the Audit Committee in reliance upon the “de minimus exception” contained in Section 202 of Sarbanes-Oxley and codified in Section 10A(i)(1)(B) of the Securities Exchange Act and in 17 CFR 210.2-01(c)(7)(i)(C).
PART IV
Item 15Exhibits and Financial Statement Schedules
(a)3. Exhibits
| | | Exhibit | | Description of | Number | | Exhibits | | | | 31 | | Rule 13a-14(a)/15d-14(a) Certifications: | | | | 31.1 | | Written statements of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act | | | | 31.2 | | Written statements of Principal Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act | | | | 32 | | Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
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Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. National Fuel Gas Company
(Registrant) D. F. Smith Chairman of the Board and Chief Executive Officer Date: November 24, 2010 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. | | | | | | | | | Signature | | National Fuel Gas CompanyTitle | | | | | | | (Registrant) | | | | /s/ D. F. Smith
D. F. Smith | | Chairman of the Board, Chief Executive Officer and Director | | Date: November 24, 2010 | | | | | | /s/ P. C. Ackerman
P. C. Ackerman | | Director | | Date: November 24, 2010 | | | | | | /s/ R. T. Brady
R. T. Brady | | Director | | Date: November 24, 2010 | | | | | | /s/ R. D. Cash
R. D. Cash | | Director | | Date: November 24, 2010 | | | | | | /s/ S. E. Ewing
S. E. Ewing | | Director | | Date: November 24, 2010 | | | | | | /s/ R. E. Kidder
R. E. Kidder | | Director | | Date: November 24, 2010 | | | | | | /s/ C. G. Matthews
C. G. Matthews | | Director | | Date: November 24, 2010 | | | | | | /s/ G. L. Mazanec
G. L. Mazanec | | Director | | Date: November 24, 2010 | | | | | | /s/ R. G. Reiten
R. G. Reiten | | Director | | Date: November 24, 2010 |
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| | | | | | | | | Signature | | ByTitle | | /s/ D. F. Smith | | | | | | | | | | /s/ F. V. Salerno
F. V. Salerno | | Director | | Date: November 24, 2010 | | | | | | | /s/ D. F. SmithP. Bauer
D. P. Bauer | | Treasurer and Principal
Financial Officer | | Date: November 24, 2010 | | | | | | President | /s/ K. M. Camiolo
K. M. Camiolo | | Controller and Chief ExecutivePrincipal
Accounting Officer | | Date: November 24, 2010 |
Date: January 6, 2009
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141
|