UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-3551
EQUITABLE RESOURCES, INC.
(Exact name of registrant as specified in its charter)
PENNSYLVANIA |
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25-0464690 |
(State or other jurisdiction of incorporation or organization) |
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(IRS Employer Identification No.) |
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225 North Shore Drive |
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Pittsburgh, Pennsylvania |
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15212 |
(Address of principal executive offices) |
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(Zip Code) |
Registrants telephone number, including area code: (412) 553-5700
Securities registered pursuant to Section 12(b) of the Act:
Title of each class |
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Name of each exchange on which registered |
Common Stock, no par value |
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New York Stock Exchange |
Preferred Stock Purchase Rights |
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes x No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o No x
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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b2 of the Exchange Act. (Check one):
Large accelerated filer x Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes o No x
The aggregate market value of voting stock held by non-affiliates of the registrant as of June 30, 2006: $3,987,703,990
The number of shares of common stock outstanding as of January 31, 2007: 121,625,746
The Companys definitive proxy statement relating to the annual meeting of shareowners, to be held April 11, 2007, which will be filed with the Commission within 120 days after the close of the Companys fiscal year ended December 31, 2006, is incorporated by reference in Part III to the extent described therein.
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Glossary of Commonly Used Terms, Abbreviations, and Measurements
Commonly Used Terms
Appalachian Basin The area of the United States comprised of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie at the foot of the Appalachian Mountains.
basis When referring to natural gas, the difference between the futures price for a commodity and the corresponding sales price at various regional sales points. The differential commonly is related to factors such as product quality, location and contract pricing.
Btu One British thermal unit a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
cash flow hedge A derivative instrument that complies with Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, and is used to reduce the exposure to variability in cash flows from the forecasted physical sale of gas production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted physical sale.
collar A financial arrangement that effectively establishes a price range for the underlying commodity. The producer bears the risk of fluctuation between the minimum (floor) price and the maximum (ceiling) price.
dekatherm(dth) A measurement unit of heat energy equal to 1,000,000 British thermal units.
development well A well drilled into a known producing formation in a previously discovered field.
exploratory well A well drilled into a previously untested geologic prospect to determine the presence of gas or oil.
farm tap Natural gas supply service in which the customer is served directly from a well or gathering pipeline.
futures contract An exchange-traded legal contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price.
gas All references to gas in this report refer to natural gas.
gross Gross natural gas and oil wells or gross acres equal the total number of wells or acres in which the Company has a working interest.
heating degree days Measure used to assess weathers impact on natural gas usage calculated by adding the difference between 65 degrees Fahrenheit and the average temperature of each day in the period (if less than 65 degrees Fahrenheit). Each degree of temperature by which the average temperature falls below 65 degrees Fahrenheit represents one heating degree day. For example, a day with an average temperature of 50 degrees Fahrenheit will have 15 heating degree days.
hedging The use of derivative commodity and interest rate instruments to reduce financial exposure to commodity price and interest rate volatility.
horizontal drilling Drilling that ultimately is horizontal or near horizontal to increase the length of the well bore penetrating the target formation.
infill drilling Drilling between producing wells in a developed field to increase production.
margin deposits Funds or good faith deposits posted during the trading life of a futures contract to guarantee fulfillment of contract obligations.
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Glossary of Commonly Used Terms, Abbreviations, and Measurements
margin call A demand for additional or variation margin deposits when futures prices move adversely to a hedging partys position.
multiple completion well A well producing oil and/or gas from different zones at different depths in the same well bore with separate tubing strings for each zone.
net Net gas and oil wells or net acres are determined by summing the fractional ownership working interests the Company has in gross wells or acres.
net revenue interest The interest retained by the Company in the revenues from a well or property after giving effect to all third party royalty interests (equal to 100% minus all royalties on a well or property).
proved reserves Reserves that, based on geologic and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reserves under existing economic and operating conditions.
proved developed reserves Proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
proved undeveloped reserves Proved reserves that are expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.
reservoir A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
royalty interest the land owners share of oil or gas production (typically 1/8, 1/6, or 1/4) free of cost.
transportation Moving gas through pipelines on a contract basis for others.
throughput Total volumes of natural gas sold or transported by an entity.
working interest An interest that gives the owner the right to drill, produce and conduct operating activities on a property and receive a share of any production.
Abbreviations
APB No. 18 Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock
APB No. 25 Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees
EITF No. 02-3 Emerging Issues Task Force Issue No. 02-3, Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10 and 00-17
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FIN 45 FASB Interpretation No. 45, Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34
FIN 48 FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes an Interpretation of FASB Statement No. 109
IRC Internal Revenue Code of 1986
IRS Internal Revenue Service
NYMEX New York Mercantile Exchange
OTC Over the Counter
PA PUC Pennsylvania Public Utility Commission
SEC Securities and Exchange Commission
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Glossary of Commonly Used Terms, Abbreviations, and Measurements
SFAS Statement of Financial Accounting Standards
SFAS No. 5 Statement of Financial Accounting Standards No. 5, Accounting for Contingencies
SFAS No. 19 Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies
SFAS No. 69 Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities an amendment of FASB Statements 19, 25, 33, and 39
SFAS No. 71 Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation
SFAS No. 87 Statement of Financial Accounting Standards No. 87, Employers Accounting for Pensions
SFAS No. 88 Statement of Financial Accounting Standards No. 88, Employers Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits
SFAS No. 106 Statement of Financial Accounting Standards No. 106, Employers Accounting for Postretirement Benefits Other Than Pensions
SFAS No . 109 Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes
SFAS No. 115 Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities
SFAS No. 123 Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation
SFAS No. 123R Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based
Payment
SFAS No. 133 Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended
SFAS No . 143 Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations
SFAS No. 144 Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets
SFAS No. 146 Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities
SFAS No. 157 Statement of Financial Accounting Standards No. 157, Fair Value Measurements
SFAS No. 158 Statement of Financial Accounting Standards No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans an amendment of FASB Statements No. 87, 88, 106 and 132(R)
SFAS No. 159 Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an amendment of FASB Statement No. 115
WV PSC Public Service Commission of West Virginia
Measurements
Bbl = barrel
Bcf = billion cubic feet
Bcfe = billion cubic feet of natural gas equivalents
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of natural gas equivalents
MMBtu = million British thermal units
MMcf = million cubic feet
MMcfe = million cubic feet of natural gas equivalents
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Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as anticipate, estimate, forecasts, approximate, expect, project, intend, plan, believe and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this report include the matters discussed in the sections captioned Outlook in Managements Discussion and Analysis of Financial Condition and Results of Operations, and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the Companys drilling and infrastructure programs, production volumes, reserves, capital expenditures, the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc., the financing of that acquisition, and the Companys move to a holding company structure. A variety of factors could cause the Companys actual results to differ materially from the anticipated results or other expectations expressed in the Companys forward-looking statements. The risks and uncertainties that may affect the operations, performance and results of the Companys business and forward-looking statements include, but are not limited to, those set forth under Item 1A, Risk Factors.
Any forward-looking statement speaks only as of the date on which such statement is made and the Company does not intend to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise.
General
In this Form 10-K, references to we, us, our, Equitable, Equitable Resources and the Company refer collectively to Equitable Resources, Inc. and its consolidated subsidiaries, unless otherwise specified.
Equitable Resources, Inc. is an integrated energy company, with an emphasis on Appalachian area natural gas supply activities including production and gathering and natural gas distribution and transmission. The Company and its subsidiaries offer energy (natural gas, and a limited amount of natural gas liquids and crude oil) products and services to wholesale and retail customers through two business segments: Equitable Utilities and Equitable Supply. In December 2005, the Company discontinued and sold the operations of its NORESCO segment, which provided energy efficiency solutions to customers including governmental, military, institutional, commercial and industrial end-users.
The Company was formed under the laws of Pennsylvania by the consolidation and merger in 1925 of two companies, the older of which was organized in 1888. In 1984, the corporate name was changed to Equitable Resources, Inc.
The Company and its subsidiaries had approximately 1,340 employees at the end of 2006, of which 332 employees were subject to collective bargaining agreements. In January 2007, the Company and one union reached agreement on a three-year renewal contract for various clerical employees represented by the union. Although one union representing 14 employees has been operating without a contract since April 19, 2004, the Company believes that its employee relations are generally good.
The Company makes certain filings with the SEC, including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports, available free of charge through its website, http://www.eqt.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available at the SECs Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. The
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Companys annual reports to shareholders, press releases and recent analyst presentations are also available on the Companys website.
Business Segments
Equitable Utilities
Equitable Utilities operations comprise the gathering, transportation, storage, distribution and sale of natural gas. Equitable Utilities has both regulated and nonregulated operations. The regulated activities consist of the Companys state-regulated distribution operations and federally-regulated pipeline and storage operations. The nonregulated activities include the non-jurisdictional marketing of natural gas, risk management activities for the Company and the sale of energy-related products and services. Equitable Utilities generated approximately 36% of the Companys net operating revenues in 2006.
Distribution Operations
Equitable Utilities distribution operations are carried out by Equitable Gas Company (Equitable Gas), a division of the Company. The service territory for the distribution operations includes southwestern Pennsylvania, municipalities in northern West Virginia and field line sales, also referred to as farm tap service, in eastern Kentucky and West Virginia. These areas have a rather static population and economy. The distribution operations provide natural gas services to approximately 274,000 customers, comprising 255,400 residential customers and 18,600 commercial and industrial customers. Equitable Gas purchases gas through contracts with various sources including major and independent producers in the Gulf Coast, local producers in the Appalachian area and gas marketers (including an affiliate). These contracts contain various pricing mechanisms, ranging from fixed prices to several different index-related prices.
Equitable Gas distribution rates, terms of service, contracts with affiliates and issuance of securities are subject to comprehensive regulation by the PA PUC and the WV PSC. The field line sales rates in Kentucky are also subject to rate regulation by the Kentucky Public Service Commission. Equitable Gas also operates a small gathering system in Pennsylvania, which is not subject to comprehensive regulation.
The Company must usually seek approval of one or more of its regulators prior to increasing (or decreasing) its rates. Currently, Equitable Gas passes through to its regulated customers the cost of its purchased gas and transportation activities. It is allowed to recover a return in addition to the costs of its transportation activities. However, the Companys regulators do not guarantee recovery and may require that certain costs of operation be recovered over an extended term. Equitable Gas has worked with, and continues to work with, regulators to implement alternative performance-based rates. Equitable Gas tariffs for commercial and industrial customers allow for negotiated rates in limited circumstances. Equitable Gas has not filed a base rate case since 1997, and its predominant approach to maximizing value is cost control and operational excellence. Regulators periodically audit the Companys compliance with applicable regulatory requirements. The Company is not aware of any significant non-compliance as a result of any completed audits.
Because most of its customers use natural gas for heating purposes, Equitable Gas revenues are seasonal, with approximately 72% of calendar year 2006 revenues occurring during the winter heating season (the months of January, February, March, November and December). Significant quantities of purchased natural gas are placed in underground storage inventory during the off-peak season to accommodate higher demand during the winter heating season.
On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion Resources, Inc.s natural gas distribution assets in Pennsylvania and in West Virginia for approximately $970 million, subject to adjustments, in a cash transaction for the stock of The Peoples Natural Gas Company and Hope Gas, Inc. The transaction requires approvals from the PA PUC and the WV PSC and is also under review by the Pennsylvania Attorney General and by the Federal Trade Commission (FTC). On February 9, 2007 an administrative law judge for the PA PUC issued an initial decision approving the stock acquisition, subject to the terms and conditions of the Joint Petition for Settlement filed by the Company and a number of the intervening parties. The Joint Petition for
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Settlement includes, among other things, an agreement by the Company that Equitable Gas Company and The Peoples Natural Gas Company will not make base rate case filings prior to January 1, 2009. Under the Commissions rules a period for filing exceptions and reply exceptions has begun to run. Based upon the thorough manner in which the administrative law judge addressed the testimony of opposing parties, the Company believes it likely that the PA PUC will approve the stock acquisition when it reviews the application in March or April of 2007. The WV PSC procedural schedule calls for hearings in mid-May 2007. The WV PSC staff and consumer advocate, the Independent Oil and Gas Association of West Virginia and the Utility Workers Union of America Local 69 Division 1 have intervened in the West Virginia regulatory case. The Company continues to engage in settlement negotiations with these interveners. The Company is complying with the information requests of the Pennsylvania Attorney General and the FTC and is targeting an approval timeframe not long after receiving approval from the PA PUC. No assurance is given that the targeted timeframes will be achieved. The Companys acquisition agreement expires on March 31, 2007 unless a closing has not occurred due to a failure to obtain a required governmental consent or authorization and such is being diligently pursued, in which case the expiration date is automatically extended to June 30, 2007. The agreement will then terminate if no closing occurs by June 30, 2007, unless the parties agree to an extension. The assets to be acquired will increase: customers in the distribution operations by 475,000 or 173%; total storage capacity by 33 Bcf or 60%, miles of gathering pipelines by 936 miles; gathered volumes by 40%; and miles of high pressure transmission by 466 miles or 42%. Transition planning activities have commenced at Equitable Utilities to plan for the integration of the assets, resources, and business processes of The Peoples Natural Gas Company and Hope Gas, Inc.s into Equitable Resources.
Pipeline (Transportation and Storage) Operations
Equitable Utilities interstate pipeline operations are carried out by Equitrans, L.P. (Equitrans). These operations offer gas gathering, transportation, storage and related services to affiliates and third parties in the northeastern United States, including but not limited to, Dominion Resources, Inc., Keyspan Corporation, NiSource, Inc., PECO Energy Company and Amerada Hess Corporation. In 2006, approximately 77% of transportation volumes and approximately 62% of transportation revenues were from affiliates.
In the second quarter of 2006, the Company filed a certificate application with the FERC for approval to build a 70-mile, 20-inch diameter pipeline which will connect the Company-operated Kentucky hydrocarbon processing plant in Langley, Kentucky, to the Tennessee Gas Pipeline in Carter County, Kentucky, and will initially provide up to 130,000 dekatherms per day of firm transportation service. The pipeline, known as The Big Sandy Pipeline, is owned and operated by Equitrans and is targeted for completion in 2007. Equitrans has secured most of the materials, labor and rights-of-way necessary to complete the project. Equitrans received a FERC certificate on November 15, 2006, authorizing construction of the pipeline subject to certain operational, commercial and environmental conditions. Equitrans implementation plan addressed those conditions and received FERC approval on November 29, 2006. Capital expenditures incurred by the Company in 2006 related to the Big Sandy Pipeline are included in the Equitable Supply business segment.
Equitrans rates are subject to regulation by the FERC. On April 5, 2006, the FERC approved a settlement to Equitrans consolidated 2005 and 2004 rate case filings. The settlement became effective on June 1, 2006. The settlement provided for the following:
· An expected annual revenue increase of $6.0 million and an expected operating income increase of $3.2 million
· Replenishment of 7.1 Bcf of migrated base gas from prior periods
· Consolidation of transmission assets into a single transmission system with a system-wide rate
· Consolidation of gathering assets into a single gathering system with a system-wide rate
· Tracking and recovery of costs relating to compliance with the Pipeline Safety Improvement Act of 2002
· Redesigned contract storage services
· Five-year rate moratorium on gathering rates
· Three-year rate moratorium on transmission rates
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Equitrans firm transportation contracts expire between 2007 and 2009. The Company anticipates that the majority of the related volumes will be fully subscribed when they become available.
Energy Marketing
Equitable Utilities unregulated marketing operations include the non-jurisdictional marketing of natural gas at Equitable Gas, marketing and risk management activities at Equitable Energy, LLC (Equitable Energy), and the sale of energy-related products and services by Equitable Homeworks, LLC. Services and products offered by the marketing operations include commodity procurement, delivery and storage services, such as park and loan services, risk management and other services for energy consumers including large industrial, utility, commercial and institutional end-users. Equitable Energy also engages in trading and risk management activities for the Company. The objective of these activities is to limit the Companys exposure to shifts in market prices and to optimize the use of the Companys assets.
Equitable Supply
Equitable Supplys production business develops, produces and sells natural gas and, to a limited extent, crude oil and natural gas liquids, in the Appalachian region of the United States. Its gathering business consists of gathering the Companys and third party gas and the processing of natural gas liquids. Equitable Supply generated approximately 64% of the Companys net operating revenues in 2006.
Production
Equitable Supplys production business, operating through Equitable Production Company and several other affiliates (collectively referred to as Equitable Production), is the largest owner of proved natural gas reserves in the Appalachian Basin. The Companys reserves are located entirely in the Appalachian Basin, where Equitable Production currently operates approximately 12,000 producing wells.
The Appalachian Basin is characterized by wells with comparatively low rates of annual decline in production, long well lives, low production costs per well and high energy content. Many of the Companys wells have been producing for decades, and in some cases since the early 1900s. Management believes that virtually all of the Companys wells are low risk development wells because they are drilled in areas known to be productive. Many of these wells are completed in more than one producing formation, including coal formations in certain areas, and production from these formations may be commingled. The Companys 2006 drilling program was comprised dominantly of vertical wells, but also included horizontal drilling.
In 2006, Equitable Production drilled 560 gross operated wells (427 net operated wells), including 5 horizontal wells, and 95 gross non-operated wells (28 net non-operated wells) at a success rate of nearly 100%. Drilling was concentrated within Equitables core areas of southwestern Virginia, southeastern Kentucky and southern West Virginia. This activity resulted in proved developed reserve additions of approximately 120 Bcfe. Of the proved developed reserve additions, approximately 60 Bcfe relates to proved undeveloped reserves that were transferred to proved developed reserves and an equal amount relates to proved developed extensions, discoveries and other additions that were not previously classified as proved.
The natural gas produced by Equitable Supply is a commodity and therefore the Company receives market-based pricing. The market price for gas located in the Appalachian Basin is generally higher than the price for gas located in the Gulf Coast, largely due to the differential in the cost to transport gas to customers in the northeastern United States. The recent increase in production in the Appalachian Basin by the Company and other producers is putting pressure on the capacity of existing gathering and midstream transport systems. As a result, the Company has entered into certain discounted sales arrangements to ensure that its gas continues to flow.
The combination of long-lived production, low drilling costs, high drilling completion rates and proximity to natural gas markets has resulted in a highly fragmented operating environment in the Appalachian Basin. Natural gas drilling activity has increased as suppliers in the Appalachian Basin attempt to take advantage of higher than normal natural gas prices. While increased activity can place constraints on capacity of labor, equipment, pipeline
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availability and other resources in the Appalachian Basin, it also provides opportunities for expansion of natural gas gathering activities and potential for higher quality rigs and labor providers in the future.
Equitable Supply hedges a portion of its forecasted natural gas production. It also hedges third party purchases and sales. The Companys hedging strategy and information regarding its derivative instruments are outlined in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, and in Notes 1 and 3 to the Consolidated Financial Statements.
Gathering
Equitable Gathering derives its revenues from charges to customers for use of its gathering system in the Appalachian Basin. As of December 31, 2006, the system included approximately 7,100 miles of gathering line located throughout West Virginia, eastern Kentucky and southwestern Virginia. Over 85% of the gathering system volumes are transported to interconnects with three major interstate pipelines: Columbia Gas Transmission, East Tennessee Natural Gas Company and Dominion Transmission. The gathering system also maintains interconnects with Equitrans, the Companys interstate pipeline affiliate. Maintaining these interconnects provides the Company with access to geographically diverse markets.
Gathering system sales volumes for 2006 totaled 108.6 Bcfe, of which approximately 64% related to the gathering of Equitable Productions gas volumes, 26% related to third party volumes, and the remainder related to volumes in which interests were sold by the Company but which the Company continued to operate for a fee. Approximately 82% of Equitable Gatherings 2006 revenues were from affiliates. Due to increased operating costs and capital investment, Equitable Gathering is, in certain cases, charging gathering rates which are below its cost of service. Equitable Gathering continues to pursue full recovery of these costs by increasing rates charged to its customers.
Key competitors for new gathering systems include independent gas gatherers and integrated Appalachian energy companies. See Outlook under Equitable Supplys section of Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations for discussion of the Companys strategy in regards to its midstream gathering operations.
Transfer of Gathering Assets
Effective January 1, 2006, certain gathering assets, consisting of 1,400 miles of gathering line and related facilities with approximately 13.3 Bcf of annual throughput, were transferred from Equitable Supply to Equitable Utilities for segment reporting purposes. The effect of the transfer is not material to the results of operations or financial position of the Equitable Utilities or Equitable Supply segments; segment results have not been restated for this transfer.
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Discontinued Operations
In the fourth quarter of 2005, the Company sold its NORESCO domestic business for $82 million before customary purchase price adjustments. In the second quarter of 2006, the Company completed the sale of the remaining interest in its investment in IGC/ERI Pan-Am Thermal Generating Limited (Pan Am), previously included in the NORESCO business segment, for total proceeds of $2.6 million. As a result of these transactions, the Company has reclassified its financial statements for all periods presented to reflect the operating results of the NORESCO segment as discontinued operations.
Composition of Segment Operating Revenues
Presented below are operating revenues as a percentage of total operating revenues for each class of products and services representing greater than 10% of total operating revenues during the years 2006, 2005 and 2004.
|
|
2006 |
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2005 |
|
2004 |
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Equitable Utilities: |
|
|
|
|
|
|
|
Residential natural gas sales |
|
24 |
% |
26 |
% |
29 |
% |
Marketed natural gas sales |
|
30 |
% |
27 |
% |
23 |
% |
Equitable Supply: |
|
|
|
|
|
|
|
Natural gas equivalents sales |
|
29 |
% |
30 |
% |
29 |
% |
Financial Information About Segments
See Note 2 to the Consolidated Financial Statements for financial information by business segment including, but not limited to, revenues from external customers, operating income, and total assets.
Financial Information About Geographic Areas
Substantially all of the Companys assets and operations are located in the continental United States.
Environmental
See Note 19 to the Consolidated Financial Statements for information regarding environmental matters.
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Risks Relating to Our Business
In addition to the other information contained in this Form 10-K, the following risk factors should be considered in evaluating our business. Please note that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations.
Natural gas price volatility may have an adverse effect on our revenue, profitability and liquidity.
Our revenue, profitability and liquidity depend on the price for natural gas. The markets for natural gas are volatile and fluctuations in prices will affect our financial results. Natural gas prices are affected by a number of factors beyond our control, which include: weather conditions; the supply of and demand for natural gas; national and worldwide economic and political conditions; the price and availability of alternative fuels; the proximity to, and availability of capacity on, transportation facilities; and government regulations, such as regulation of natural gas transportation, royalties and price controls.
Increases in natural gas prices may be accompanied by or result in increased well drilling costs, increased deferral of purchased gas costs for our distribution operations, increased production taxes, increased lease operating expenses, increased exposure to credit losses resulting from potential increases in uncollectible accounts receivable from our distribution customers, increased volatility in seasonal gas price spreads for our storage assets, and increased customer conservation or conversion to alternative fuels. Significant price increases, such as occurred in the fall and winter of 2005, subject us to margin calls on our commodity price derivative contracts (hedging arrangements, including futures contracts, swap agreements and exchange traded instruments) which require us to post significant amounts of cash collateral with our hedge counterparties. The cash collateral, which is interest-bearing, provided to our hedge counterparties is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related hedged transaction. In such cases we are, however, exposed to the risk of non-performance by our hedge counterparties of their obligations under the derivative contracts. In addition, to the extent we have hedged our current production at prices below the current market price, we are unable to benefit fully from the increase in the price of natural gas.
Lower natural gas prices, increases in our estimates of development costs or changes to our production assumptions may result in our having to make downward adjustments to our estimated proved reserves, change our production plans, and incur non-cash charges to earnings.
Our failure to assess production opportunities based on market conditions could negatively impact our long-term growth prospects for our production business.
Our goal of sustaining long-term growth for our production business is contingent upon our ability to identify production opportunities based on market conditions. Successfully identifying production opportunities involves a high degree of business experience, knowledge and careful evaluation of potential opportunities, along with subjective judgments and assumptions which may prove to be incorrect.
Our failure to develop and maintain the necessary infrastructure to successfully deliver gas to market may adversely affect our earnings, cash flows and results of operations.
Our gas delivery depends on the availability of adequate transportation infrastructure. We have announced a significant investment in transportation infrastructure (the Big Sandy Pipeline) which is intended to address a lack of capacity on and access to existing transportation pipelines as well as curtailments on such pipelines. We are also planning an upgrade to the Company-operated hydrocarbon processing plant in Langley, Kentucky for completion in early 2008. Our infrastructure development program can involve significant risks, including those related to timing and cost overruns and these risks can be affected by the availability of capital, materials, and a qualified work force, as well as weather conditions, gas price volatility, government approvals, title problems, geology and other factors. In addition, we may not be able to obtain sufficient third party transportation contracts to recover the costs of our infrastructure development program. We also deliver to and are served by third party gas gathering, transportation,
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processing and storage facilities which are limited in number and geographically concentrated. An extended interruption of access to or service from these facilities could result in material adverse consequences to us.
The amount and timing of actual future gas production is difficult to predict and may vary significantly from our estimates which may reduce our earnings.
Our future success depends on our ability to develop additional gas reserves that are economically recoverable and to maximize existing well production, and our failure to do so may reduce our earnings. We have expanded our drilling program in recent years, and we have subsequently announced further expansion. Our drilling of development wells can involve significant risks, including those related to timing and cost overruns and these risks can be affected by the availability of capital, leases, rigs and a qualified work force, as well as weather conditions, gas price volatility, government approvals, title problems, geology and other factors. Drilling for natural gas can be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient revenues to return a profit due to inadequate well operation and compressor availability. Without continued successful development or acquisition activities, our reserves and revenues will decline as a result of our current reserves being depleted by production.
We may engage in acquisition and disposition strategies that involve a number of inherent risks, any of which may cause us not to realize anticipated benefits and may adversely affect our earnings, cash flows and results of operations.
On March 1, 2006, we signed a purchase agreement to acquire the capital stock of The Peoples Natural Gas Company and Hope Gas, Inc. from Consolidated Natural Gas Company, a wholly-owned subsidiary of Dominion Resources, Inc. In addition, we intend to continue to strategically position our business in order to improve our ability to compete. Acquisitions, joint ventures and other business combinations involve various inherent risks, such as assessing the value, strengths, weaknesses, contingent and other liabilities and potential profitability of acquisition or other transaction candidates; the potential loss of key personnel of an acquired business; the constraints imposed by regulators in approving such transactions; the potential for unions of an acquired business to strike; our ability to achieve identified financial and operating synergies anticipated to result from an acquisition or other transaction; demands on management related to the increase in size after an acquisition or other transaction; and unanticipated changes in business and economic conditions affecting an acquisition or other transaction. We may be unable to realize, or do so within any particular time frame, the cost reductions, cash flow increases or other synergies expected to result from such transactions. In addition, various factors including prevailing market conditions and the incursion of related contingent liabilities could negatively impact the benefits we receive from transactions.
If we fail to achieve our strategic or financial goals in any acquisition or disposition transaction, it could have a significant adverse affect on our earnings, cash flows and results of operations. Furthermore, if we borrow money to finance an acquisition, which we plan to do in connection with the acquisition of The Peoples Natural Gas Company and Hope Gas, Inc., our failure to achieve our stated goals could impact our ability to repay such borrowings or other borrowings and could weaken our financial condition. Moreover, additional debt could increase our vulnerability to the effects of interest rate movements.
We are subject to risks associated with the operation of our pipelines and facilities.
Our business operations are subject to all of the inherent hazards and risks normally incidental to the production, transportation, storage and distribution of natural gas. These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. As a result, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. There can be no assurance that insurance policies we maintain to limit our liability of such losses will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that such levels of insurance will be available in the future at economical prices.
13
Our need to comply with comprehensive, complex and sometimes unpredictable government regulations may increase our costs and limit our revenue growth, which may result in reduced earnings.
Significant portions of our gathering, transportation, storage and distribution businesses are subject to state and federal regulation including regulation of the rates which we may assess our customers. The agencies that regulate our rates may prohibit us from realizing a level of return which we believe is appropriate. These restrictions may take the form of imputed revenue credits, cost disallowances (including purchased gas cost recoveries) and/or expense deferrals. Additionally, we may be required to provide additional assistance to low income residential customers to help pay their bills.
We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, restoration of drilling properties after drilling is completed, pipeline safety and work practices related to employee health and safety. Complying with these requirements could have a significant effect on our costs of operations and competitive position. If we fail to comply with these requirements, even if caused by factors beyond our control, such failure could result in the assessment of civil or criminal penalties and damages against us.
The rates of federal, state and local taxes applicable to the industries in which we operate, including production taxes paid by Equitable Supply, which often fluctuate, could be increased by the respective taxing authorities. In addition, the tax laws, rules and regulations that affect our business could change. Any such increase or change could adversely impact our cash flows and profitability .
See Item 7A, Quantitative and Qualitative Disclosures About Market Risk, for further discussion regarding the Companys exposure to market risks, including the risks associated with our use of derivative contracts to hedge commodity prices.
None
Principal facilities are owned by the Companys business segments, with the exception of various office locations and warehouse buildings, which are leased. A limited amount of equipment is also leased. The majority of the Companys properties are located on or under (1) public highways under franchises or permits from various governmental authorities, or (2) private properties owned in fee, or occupied under perpetual easements or other rights acquired for the most part without examination of underlying land titles. The Companys facilities are generally well maintained and, where necessary, are replaced or expanded to meet operating requirements.
Headquarters. In May 2005, the Company completed the relocation of its corporate headquarters and other operations to a newly constructed office building, which the Company leases, located at the North Shore in Pittsburgh, Pennsylvania. The Company still maintains leases for properties previously used for its administrative operations that were not being utilized for a period of time following the relocation and were deemed to have no economic benefit to the Company. However, during the second quarter of 2006, the Company began to utilize certain of the leased space previously deemed to have no economic benefit to the Company for the transition planning activities relating to the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc.
Equitable Utilities. This segment owns and operates natural gas distribution properties as well as other general property and equipment in western Pennsylvania, West Virginia and Kentucky. The segment also owns and operates underground storage, transmission and gathering facilities in Pennsylvania and West Virginia.
14
The distribution operations consist of approximately 4,100 miles of pipe in Pennsylvania, West Virginia and Kentucky. The interstate pipeline operations consist of approximately 2,900 miles of transmission, storage, and gathering lines and interconnections with five major interstate pipelines. The interstate pipeline system stretches throughout north central West Virginia and southwestern Pennsylvania. Equitrans has 15 natural gas storage reservoirs with approximately 496 MMcf per day of peak delivery capability and 57 Bcf of storage capacity of which 27 Bcf is working gas. These storage reservoirs are clustered, with 8 in northern West Virginia and 7 in southwestern Pennsylvania.
Equitable Supply. This segments production and gathering properties are located in the Appalachian Basin, specifically Kentucky, Pennsylvania, Virginia and West Virginia. This segment currently has an inventory of approximately 3.3 million gross acres (approximately 71% of which is considered undeveloped), which encompasses nearly all of the Companys acreage of proved developed and undeveloped natural gas and oil production properties. Although most of its wells are drilled to relatively shallow depths (2,000 to 6,500 feet below the surface), the Company retains what are normally considered deep rights on the majority of its acreage. As of December 31, 2006, the Company estimated its total proved reserves to be 2,497 Bcfe, including proved undeveloped reserves of 772 Bcfe. No report has been filed with any federal authority or agency reflecting a 5% or more difference from the Companys estimated total reserves. Additional information relating to the Companys estimates of natural gas and crude oil reserves and future net cash flows is provided in Note 24 (unaudited) to the Consolidated Financial Statements.
Natural Gas and Crude Oil Production:
|
|
2006 |
|
2005 |
|
2004 |
|
|||
Natural Gas: |
|
|
|
|
|
|
|
|||
MMcf produced |
|
80,698 |
|
78,105 |
|
72,226 |
|
|||
Average well-head sales price per Mcfe sold (net of hedges) |
|
$ |
4.79 |
|
$ |
5.13 |
|
$ |
4.45 |
|
Crude Oil: |
|
|
|
|
|
|
|
|||
Thousands of Bbls produced |
|
112 |
|
108 |
|
83 |
|
|||
Average sales price per Bbl |
|
$ |
58.35 |
|
$ |
53.07 |
|
$ |
37.38 |
|
Average production cost, including severance taxes (lifting cost), of natural gas and crude oil during 2006, 2005, and 2004 was $0.768, $0.771, and $0.583 per Mcfe, respectively.
|
|
Natural Gas |
|
Oil |
|
Total productive wells at December 31, 2006: |
|
|
|
|
|
Total gross productive wells |
|
12,402 |
|
22 |
|
Total net productive wells |
|
9,270 |
|
19 |
|
At December 31, 2006, the Company had approximately 117 multiple completion wells.
Total acreage at December 31, 2006: |
|
|
|
Total gross productive acres |
|
964,840 |
|
Total net productive acres |
|
906,950 |
|
Total gross undeveloped acres |
|
2,330,550 |
|
Total net undeveloped acres |
|
2,191,833 |
|
Number of net productive and dry exploratory and development wells drilled:
|
|
2006 |
|
2005 |
|
2004 |
|
Exploratory wells: |
|
|
|
|
|
|
|
Productive |
|
|
|
|
|
|
|
Dry |
|
|
|
|
|
|
|
Development wells: |
|
|
|
|
|
|
|
Productive |
|
455.0 |
|
344.2 |
|
246.5 |
|
Dry |
|
1.0 |
|
1.0 |
|
|
|
15
Selected data by state (at December 31, 2006 unless otherwise noted):
|
|
Kentucky |
|
Virginia |
|
West
|
|
Pennsylvania |
|
Ohio(a) |
|
Total |
|
Natural gas and oil production (MMcfe) 2006 |
|
35,699 |
|
23,723 |
|
20,534 |
|
1,415 |
|
|
|
81,371 |
|
Natural gas and oil production (MMcfe) 2005 |
|
33,849 |
|
21,913 |
|
19,924 |
|
2,247 |
|
822 |
|
78,755 |
|
Natural gas and oil production (MMcfe) 2004 |
|
30,183 |
|
20,497 |
|
18,019 |
|
2,415 |
|
1,646 |
|
72,760 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net revenue interest (%) |
|
84.3 |
% |
67.5 |
% |
61.5 |
% |
88.4 |
% |
|
|
72.3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross productive wells |
|
4,876 |
|
2,223 |
|
4,621 |
|
704 |
|
|
|
12,424 |
|
Total net productive wells |
|
4,047 |
|
1,754 |
|
2,784 |
|
704 |
|
|
|
9,289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross acreage |
|
1,442,481 |
|
527,284 |
|
1,201,304 |
|
124,321 |
|
|
|
3,295,390 |
|
Total net acreage |
|
1,379,615 |
|
507,992 |
|
1,086,923 |
|
124,253 |
|
|
|
3,098,783 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves (Bcfe) |
|
886 |
|
337 |
|
472 |
|
30 |
|
|
|
1,725 |
|
Proved undeveloped reserves (Bcfe) |
|
339 |
|
98 |
|
335 |
|
|
|
|
|
772 |
|
Proved developed and undeveloped reserves (Bcfe) |
|
1,225 |
|
435 |
|
807 |
|
30 |
|
|
|
2,497 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross proved undeveloped drilling locations |
|
1,069 |
|
656 |
|
1,189 |
|
|
|
|
|
2,914 |
|
Net proved undeveloped drilling locations |
|
1,050 |
|
375 |
|
1,174 |
|
|
|
|
|
2,599 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate miles of gathering line |
|
3,300 |
|
1,200 |
|
2,600 |
|
|
|
|
|
7,100 |
|
(a) Relates to certain non-core gas properties sold in May 2005. See Note 4 to the Companys Consolidated Financial Statements.
Wells located in Kentucky are primarily in shale formations with depths ranging from 2,500 feet to 6,000 feet and average spacing of 72 acres. Wells located in Virginia are primarily in coal bed methane formations with depths ranging from 2,000 feet to 3,000 feet and average spacing of 60 acres. Wells located in West Virginia are primarily in tight sand formations with depths ranging from 2,500 feet to 6,500 feet and average spacing of 40 acres in the northern part of the state and 60 acres in the southern part of the state. Wells located in Pennsylvania are primarily in tight sand formations with depths ranging from 3,000 feet to 5,000 feet and average spacing of 40 acres.
The gathering operations own or operate approximately 7,100 miles of gathering line and 180 compressor units comprising 107 compressor stations with approximately 123,000 horse power of installed capacity, as well as other general property and equipment.
Substantially all of Equitable Supplys sales are delivered to several large interstate pipelines on which the Company leases capacity. These pipelines are subject to periodic curtailments for maintenance and repairs.
Equitable Supply leases office space in Pennsylvania, West Virginia, Virginia and Kentucky.
16
In the ordinary course of business, various legal claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves for pending litigation, which it believes are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of the Companys security holders during the last quarter of its fiscal year ended December 31, 2006.
17
Executive Officers of the Registrant (as of February 21, 2007)
Name and Age |
|
Current Title (Year Initially Elected an
|
|
Business Experience |
|
|
|
|
|
John A. Bergonzi (54) |
|
Vice President and Corporate Controller (2003) |
|
Elected to present position January 2003; Corporate Controller and Assistant Treasurer from December 1995 to December 2002. |
|
|
|
|
|
Philip P. Conti (47) |
|
Senior Vice President and Chief Financial Officer (2000) |
|
Elected to present position February 2007; Vice President and Chief Financial Officer from January 2005 to February 2007, also Treasurer until January 2006; Vice President, Finance and Treasurer from August 2000 to January 2005. |
|
|
|
|
|
Randall L. Crawford (44) |
|
Senior Vice President, and President, Equitable Utilities (2003) |
|
Elected to present position February 2007; Vice President, and President, Equitable Utilities from February 2004 to February 2007; President, Equitable Gas Company from January 2003 to January 2004; Executive Vice President, Equitable Gas Company from November 2000 to December 2002. |
|
|
|
|
|
Martin A. Fritz (42) |
|
Vice President and Chief Administrative Officer (2006) |
|
Elected to present position February 2007; Vice President and Chief Information Officer from April 2006 to February 2007; Chief Information Officer from May 2003 to March 2006; Deputy General Counsel from April 1999 to April 2003. |
|
|
|
|
|
Murry S. Gerber (53) |
|
Chairman and Chief Executive Officer (1998) |
|
Elected to present position February 2007; Chairman, President and Chief Executive Officer from May 2000 to February 2007; President and Chief Executive Officer from June 1, 1998 to February 2007. |
|
|
|
|
|
Joseph E. OBrien (54) |
|
Senior Vice President, and President, Equitable Supply (2001) |
|
Elected to present position February 2007; Vice President, and President Equitable Supply from February 2006 to February 2007; Vice President, Facility Construction from July 2005 to January 2006. President, NORESCO, LLC from January 2000 to June 2005. |
|
|
|
|
|
Johanna G. OLoughlin (60) |
|
Senior Vice President, General Counsel and Corporate Secretary (1996) |
|
Elected to present position January 2002; Vice President, General Counsel and Secretary from May 1999 to January 2002. |
|
|
|
|
|
Charlene Petrelli (46) |
|
Vice President and Chief Human Resources Officer (2003) |
|
Elected to present position February 2007; Vice President, Human Resources from January 2003 to February 2007; Director of Corporate Human Resources from October 2000 to December 2002. |
|
|
|
|
|
David L. Porges (49) |
|
Vice Chairman, President and Chief Operating Officer (1998) |
|
Elected to present position February 2007; Vice Chairman and Executive Vice President, Finance and Administration from January 2005 to February 2007; Executive Vice President and Chief Financial Officer from February 2000 to January 2005. |
All executive officers have executed agreements with the Company and serve at the pleasure of the Companys Board of Directors. Officers are elected annually to serve during the ensuing year or until their successors are chosen and qualified.
18
Item 5. Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The Companys common stock is listed on the New York Stock Exchange. The high and low sales prices reflected in the New York Stock Exchange Composite Transactions, and the dividends declared and paid per share, are summarized as follows (in U.S. dollars per share):
|
|
2006 |
|
2005 (a) |
|
||||||||||||||
|
|
High |
|
Low |
|
Dividend |
|
High |
|
Low |
|
Dividend |
|
||||||
1 st Quarter |
|
$ |
39.02 |
|
$ |
34.05 |
|
$ |
0.21 |
|
$ |
30.62 |
|
$ |
27.89 |
|
$ |
0.19 |
|
2 nd Quarter |
|
37.00 |
|
31.59 |
|
0.22 |
|
34.42 |
|
28.16 |
|
0.21 |
|
||||||
3 rd Quarter |
|
37.48 |
|
32.55 |
|
0.22 |
|
39.90 |
|
34.01 |
|
0.21 |
|
||||||
4 th Quarter |
|
44.48 |
|
34.83 |
|
0.22 |
|
41.18 |
|
34.51 |
|
0.21 |
|
||||||
(a) Adjusted to reflect the two-for-one stock split effective September 1, 2005.
As of February 12, 2007, there were 3,992 shareholders of record of the Companys common stock.
The amount and timing of dividends is subject to the discretion of the Board of Directors and depends on business conditions, the Companys results of operations and financial condition and other factors. Based on currently foreseeable market conditions, the Company anticipates that comparable dividends will be paid on a regular quarterly basis.
The following table sets forth the Companys repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred in the three months ended December 31, 2006.
Period |
|
Total
|
|
Average
|
|
Total number of
|
|
Maximum number
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October 2006 (October 1 October 31) |
|
12,941 |
|
$ |
37.82 |
|
|
|
8,385,400 |
|
|
|
|
|
|
|
|
|
|
|
|
November 2006 (November 1 November 30) |
|
9,721 |
|
$ |
42.86 |
|
|
|
8,385,400 |
|
|
|
|
|
|
|
|
|
|
|
|
December 2006 (December 1 December 31) |
|
8,235 |
|
$ |
43.31 |
|
|
|
8,385,400 |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
30,897 |
|
|
|
|
|
|
|
(a) Includes 16,724 shares delivered in exchange for the exercise of stock options to cover award cost and 14,173 shares for Company-directed purchases made by the Companys 401(k) plans.
(b) Equitables Board of Directors previously authorized a share repurchase program with a maximum of 50.0 million shares and no expiration date. The program was initially publicly announced on October 7, 1998, with subsequent amendments announced on November 12, 1999, July 20, 2000, April 15, 2004 and July 13, 2005.
19
Stock Performance Graph
The following graph compares the most recent five-year cumulative total return attained by shareholders of Equitable Resources common stock with the cumulative total returns of the S & P 500 index, and a customized peer group of eleven companies listed in footnote 1 below whose principal businesses are natural gas distribution, exploration and production, and transmission. An investment of $100 (with reinvestment of all dividends) is assumed to have been made on December 31, 2001 in the Companys common stock, in the S&P 500 index, and in the peer group. Relative performance is tracked through December 31, 2006.
|
|
2001 |
|
2002 |
|
2003 |
|
2004 |
|
2005 |
|
2006 |
|
EQUITABLE RESOURCES, INC. |
|
100.00 |
|
104.90 |
|
131.69 |
|
191.65 |
|
237.77 |
|
277.02 |
|
SELF-CONSTRUCTED PEER GROUP (1) |
|
100.00 |
|
88.54 |
|
110.19 |
|
137.39 |
|
167.99 |
|
203.86 |
|
S & P 500 |
|
100.00 |
|
77.90 |
|
100.24 |
|
111.15 |
|
116.61 |
|
135.03 |
|
(1) The following eleven companies are included in the customized peer group: CMS Energy Corporation, Energen Corporation, Keyspan Corporation, Kinder Morgan, Inc, National Fuel Gas Company, NiSource Inc, OGE Energy Corp., ONEOK, Inc, Peoples Energy Corp., Questar Corporation and Southwestern Energy Company. This is the same peer group used for the companys short-term incentive plans. The company uses other peer groups for other purposes, including its executive performance incentive program under the 1999 Long-Term Incentive Plan.
20
Item 6. Selected Financial Data
|
|
As of and for the year ended December 31, (a) |
|
|||||||||||||
|
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
2002 |
|
|||||
|
|
(Thousands, except per share amounts) |
|
|||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Operating revenues |
|
$ |
1,267,910 |
|
$ |
1,253,724 |
|
$ |
1,045,183 |
|
$ |
876,574 |
|
$ |
878,961 |
|
Income from continuing operations before cumulative effect of accounting change (b) |
|
$ |
216,025 |
|
$ |
258,574 |
|
$ |
298,790 |
|
$ |
165,750 |
|
$ |
145,731 |
|
Income from continuing operations before cumulative effect of accounting change per share of common stock (c) |
|
|
|
|
|
|
|
|
|
|
|
|||||
Basic |
|
$ |
1.79 |
|
$ |
2.14 |
|
$ |
2.42 |
|
$ |
1.34 |
|
$ |
1.16 |
|
Diluted |
|
$ |
1.77 |
|
$ |
2.09 |
|
$ |
2.37 |
|
$ |
1.31 |
|
$ |
1.14 |
|
Total assets |
|
$ |
3,256,911 |
|
$ |
3,342,285 |
|
$ |
3,205,346 |
|
$ |
2,948,073 |
|
$ |
2,440,396 |
|
Long-term debt |
|
$ |
753,500 |
|
$ |
766,500 |
|
$ |
626,500 |
|
$ |
647,000 |
|
$ |
471,250 |
|
Preferred trust securities |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
125,000 |
|
Cash dividends declared per share of common stock (c) |
|
$ |
0.870 |
|
$ |
0.820 |
|
$ |
0.720 |
|
$ |
0.485 |
|
$ |
0.335 |
|
(a) Amounts have been reclassified to reflect the operating results of the NORESCO segment as discontinued operations for all periods presented.
(b) The year ended December 31, 2003, excludes the negative cumulative effect of an accounting change of $3.6 million related to the adoption of SFAS No. 143. The year ended December 31, 2002, excludes the negative cumulative effect of accounting change of $5.5 million related to the adoption of SFAS No. 142 and income from discontinued operations of $9.0 million related to the sale of the Companys natural gas midstream operations.
(c) All per share amounts have been adjusted for the two-for-one stock split effected on September 1, 2005.
See Item 1A, Risk Factors, Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations and Notes 4 and 5 to the Consolidated Financial Statements for other matters that affect the comparability of the selected financial data as well as uncertainties that might affect the Companys future financial condition.
21
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
Consolidated Results of Operations
Equitables consolidated income from continuing operations for 2006 was $216.0 million, or $1.77 per diluted share, compared with $258.6 million, or $2.09 per diluted share, for 2005, and $298.8 million, or $2.37 per diluted share, for 2004.
The $42.6 million decrease in income from continuing operations from 2005 to 2006 included the impact of several factors. In 2005, the Company recognized a pre-tax gain of $110.3 million on the sale of Kerr-McGee Corporation (Kerr-McGee) shares. In 2006, the Company incurred $12.3 million of transition planning expenses relating to the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. The Company also established a reserve for West Virginia royalty disputes. The impact of lower realized selling prices ($25.8 million) and warmer weather ($9.3 million) also contributed to the decrease between years.
Decreases in income from continuing operations between years were partially offset by 2005 charges of $16.0 million for the termination and settlement of certain defined benefit pension plans and of $7.8 million for the Companys office consolidation, as well as the 2006 favorable impact of the Equitrans rate case settlement. Additionally, income from continuing operations for 2006 was positively impacted by reduced expenses related to the executive performance incentive programs ($22.7 million), favorable storage asset optimization ($16.4 million), and higher production sales volumes ($11.6 million).
The $40.2 million decrease in income from continuing operations from 2004 to 2005 was primarily the result of several factors. The Company recorded a gain in 2004 as a result of the Westport Resources Corporation (Westport)/Kerr-McGee merger in the second quarter of 2004 as well as a gain on the sale of 0.8 million Kerr-McGee shares subsequent to the merger. These gains were partially offset by an expense related to the Companys charitable contribution of 0.4 million Kerr-McGee shares to the Equitable Resources Foundation, Inc. in 2004. The 2005 gain from the sale of the Companys remaining Kerr-McGee shares partially offset the impact of the 2004 items.
Income from continuing operations was favorably impacted in 2005 compared to 2004 as a result of higher realized selling prices, an increase in sales volumes from production and increased revenues from storage asset optimization. These increases were offset in some part by increased operating costs resulting primarily from higher natural gas prices and sales volumes, increased incentive expenses and impairment charges related to the Companys office consolidation.
The Companys effective tax rate for its continuing operations for the year ended December 31, 2006, was 33.7% compared to 37.2% for the year ended December 31, 2005, and 34.2% for the year ended December 31, 2004. The higher effective tax rate in 2005 was primarily the result of tax benefit disallowances under Section 162(m) of the IRC. See Note 6 to the Consolidated Financial Statements.
Business Segment Results
Business segment operating results are presented in the segment discussions and financial tables on the following pages. Operating segments are evaluated on their contribution to the Companys consolidated results based on operating income, equity in earnings of nonconsolidated investments, and other income, net. Interest expense and income taxes are managed on a consolidated basis. Headquarters costs are billed to the operating segments based upon a fixed allocation of the headquarters annual operating budget. Differences between budget and actual headquarters expenses are not allocated to the operating segments. Certain performance-related incentive costs, pension costs and administrative costs totaling $21.9 million, $48.0 million and $45.8 million in 2006, 2005 and 2004, respectively, were not allocated to business segments. The decrease in unallocated expenses from 2005 to 2006 was primarily related to decreased long-term incentive expenses.
The Company has reconciled each segments operating income, equity in earnings of nonconsolidated investments and other income, net to the Companys consolidated operating income, equity in earnings of nonconsolidated investments and other income, net totals in Note 2 to the Consolidated Financial Statements.
22
Additionally, these subtotals are reconciled to the Companys consolidated net income in Note 2. The Company has also reported the components of each segments operating income and various operational measures in the sections below, and where appropriate, has provided information describing how a measure was derived. Equitables management believes that presentation of this information is useful to management and investors in assessing the financial condition, operations and trends of each of Equitables segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations. In addition, management uses these measures for budget planning purposes.
Equitable Utilities
Overview
Equitable Utilities net operating revenues increased 8.5% from 2005 to 2006. This increase was primarily due to increased pipeline revenues from the settlement of the Equitrans rate case effective June 1, 2006, as well as favorable marketing revenues resulting from volatile natural gas prices, as the marketing operations were able to take advantage of their asset position and achieve record margins from that business in 2006. The marketing business is primarily driven by Equitable Utilities physical and contractual gas storage assets which allow the segment to purchase gas and store it in lower price markets and simultaneously enter into contracts to sell it later at higher prices, taking advantage of near term seasonal gas price spreads. Those spreads are unpredictable and at times were considerably wider in 2006 than they were in 2005.
The positive results from the pipeline and marketing operations were partially offset by reduced revenues in Equitable Utilities distribution operations, as the weather in Equitable Gas service territory in 2006 was 15% warmer than the 30 year average and 10% warmer than 2005. The National Oceanic and Atmospheric Administration (NOAA) reported that the 2006 average annual temperature for the contiguous U.S. was the warmest on record. NOAA also reported that, based on the unusually warm temperatures during much of the first half of the winter season (October to December 2006), the nations residential energy demand was approximately 13.5 percent lower than what would have occurred under average climate conditions for the season.
Operating expenses at Equitable Utilities decreased 3%, driven primarily by the absence of charges related to pension plans and the Companys office consolidation that occurred in 2005, offset somewhat by transition planning expenses incurred in 2006 related to the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. and the recognition of costs previously deferred as a result of the Equitrans rate case settlement.
Expenses were also positively impacted by a reduction in bad debt expense. In 2006, Equitable continued its consistent and aggressive collections strategy as permitted by The Responsible Utility Customer Protection Act, which became effective on December 14, 2004. In December 2005, the PA PUC approved Equitable Gass petition requesting approval to use up to $7 million of pipeline supplier refunds to benefit low-income customers in its service territory, primarily during the winter heating season. Approximately $4.9 million and $0.3 million of this amount was credited to eligible customers accounts during 2006 and 2005, respectively. The execution of the collections strategy and provision of additional customer energy assistance enabled Equitable Utilities to reduce its delinquent customer base by 20% as of December 2006 compared to December 2005. These efforts were significant in enabling Equitable Utilities to reduce its bad debt expense in 2006, despite unusually high gas cost rates in effect during 2006 and 2005.
On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion Resources, Inc.s natural gas distribution assets in Pennsylvania and in West Virginia for approximately $970 million, subject to adjustments, in a cash transaction for the stock of The Peoples Natural Gas Company and Hope Gas, Inc. The transaction requires approvals from the PA PUC and the WV PSC and is also under review by the Pennsylvania Attorney General and by the Federal Trade Commission (FTC). On February 9, 2007 an administrative law judge for the PA PUC issued an initial decision approving the stock acquisition, subject to the terms and conditions of the Joint Petition for Settlement filed by the Company and a number of the intervening parties. The Joint Petition for Settlement includes, among other things, an agreement by the Company that Equitable Gas Company and The Peoples Natural Gas Company will not make base rate case filings prior to January 1, 2009. Under the Commissions rules a period for filing exceptions and reply exceptions has begun to run. Based upon the thorough
23
manner in which the administrative law judge addressed the testimony of opposing parties, the Company believes it likely that the PA PUC will approve the stock acquisition when it reviews the application in March or April of 2007. The WV PSC procedural schedule calls for hearings in mid-May 2007. The WV PSC staff and consumer advocate, the Independent Oil and Gas Association of West Virginia and the Utility Workers Union of America Local 69 Division 1 have intervened in the West Virginia regulatory case. The Company continues to engage in settlement negotiations with these interveners. The Company is complying with the information requests of the Pennsylvania Attorney General and the FTC and is targeting an approval timeframe not long after receiving approval from the PA PUC. No assurance is given that the targeted timeframes will be achieved. The Companys acquisition agreement expires on March 31, 2007 unless a closing has not occurred due to a failure to obtain a required governmental consent or authorization and such is being diligently pursued, in which case the expiration date is automatically extended to June 30, 2007. The agreement will then terminate if no closing occurs by June 30, 2007, unless the parties agree to an extension.
With the relatively recent repeal of the Public Utility Holding Company Act of 1935, the Company has filed applications with the PA PUC and WV PSC to reorganize as a holding company. Currently, Equitable Gas is a division of Equitable Resources, Inc., which requires the Company to obtain regulatory approval for many actions that are not directly related to the distribution operations, such as acquisitions and financings. This requirement restricts the Companys ability to take advantage of opportunities and market conditions. The Company successfully completed a request for direction to holders of notes under the indentures governing its long-term debt. Upon receipt of the other required approvals, the Company expects to complete the reorganization. In 2006, the Company expensed $1.6 million of costs related to the holding company implementation.
24
Results of Operations
|
|
Years Ended December 31, |
|
|||||||||||
|
|
2006 |
|
2005 |
|
%
|
|
2004 |
|
%
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
OPERATIONAL DATA |
|
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Heating degree days (30 year average = 5,829) |
|
4,976 |
|
5,543 |
|
(10.2 |
) |
5,360 |
|
3.4 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Residential sales and transportation volume (MMcf) |
|
21,014 |
|
24,680 |
|
(14.9 |
) |
25,520 |
|
(3.3 |
) |
|||
Commercial and industrial volume (MMcf) |
|
23,841 |
|
25,368 |
|
(6.0 |
) |
29,597 |
|
(14.3 |
) |
|||
Total throughput (MMcf) Distribution Operations |
|
44,855 |
|
50,048 |
|
(10.4 |
) |
55,117 |
|
(9.2 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Net operating revenues (thousands): |
|
|
|
|
|
|
|
|
|
|
|
|||
Distribution Operations (regulated): |
|
|
|
|
|
|
|
|
|
|
|
|||
Residential |
|
$ |
92,497 |
|
$ |
102,457 |
|
(9.7 |
) |
$ |
104,612 |
|
(2.1 |
) |
Commercial & industrial |
|
42,519 |
|
46,857 |
|
(9.3 |
) |
48,563 |
|
(3.5 |
) |
|||
Other |
|
8,319 |
|
7,544 |
|
10.3 |
|
5,950 |
|
26.8 |
|
|||
Total Distribution Operations |
|
143,335 |
|
156,858 |
|
(8.6 |
) |
159,125 |
|
(1.4 |
) |
|||
Pipeline Operations (regulated) |
|
72,586 |
|
53,767 |
|
35.0 |
|
55,123 |
|
(2.5 |
) |
|||
Energy Marketing |
|
59,089 |
|
42,739 |
|
38.3 |
|
28,457 |
|
50.2 |
|
|||
Total net operating revenues |
|
$ |
275,010 |
|
$ |
253,364 |
|
8.5 |
|
$ |
242,705 |
|
4.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Total operating expenses as a % of net operating revenues |
|
54.47 |
% |
61.22 |
% |
|
|
55.44 |
% |
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Operating income (thousands): |
|
|
|
|
|
|
|
|
|
|
|
|||
Distribution Operations (regulated) |
|
$ |
34,807 |
|
$ |
40,322 |
|
(13.7 |
) |
$ |
56,877 |
|
(29.1 |
) |
Pipeline Operations (regulated) |
|
33,240 |
|
17,345 |
|
91.6 |
|
24,656 |
|
(29.7 |
) |
|||
Energy Marketing |
|
57,162 |
|
40,587 |
|
40.8 |
|
26,616 |
|
52.5 |
|
|||
Total operating income |
|
$ |
125,209 |
|
$ |
98,254 |
|
27.4 |
|
$ |
108,149 |
|
(9.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion and amortization (DD&A) (thousands): |
|
|
|
|
|
|
|
|
|
|
|
|||
Distribution Operations |
|
$ |
19,938 |
|
$ |
19,483 |
|
2.3 |
|
$ |
17,474 |
|
11.5 |
|
Pipeline Operations |
|
8,737 |
|
8,317 |
|
5.0 |
|
7,985 |
|
4.2 |
|
|||
Energy Marketing |
|
56 |
|
74 |
|
(24.3 |
) |
170 |
|
(56.5 |
) |
|||
Total DD&A |
|
$ |
28,731 |
|
$ |
27,874 |
|
3.1 |
|
$ |
25,629 |
|
8.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Capital expenditures (thousands) |
|
$ |
64,974 |
|
$ |
61,349 |
|
5.9 |
|
$ |
56,274 |
|
9.0 |
|
25
|
|
Years Ended December 31, |
|
|||||||||||
|
|
2006 |
|
2005 |
|
%
|
|
2004 |
|
%
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
FINANCIAL DATA (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Distribution revenues (regulated) |
|
$ |
445,168 |
|
$ |
469,102 |
|
(5.1 |
) |
$ |
422,438 |
|
11.0 |
|
Pipeline revenues (regulated) |
|
74,010 |
|
57,534 |
|
28.6 |
|
55,123 |
|
4.4 |
|
|||
Marketing revenues |
|
380,149 |
|
365,625 |
|
4.0 |
|
300,513 |
|
21.7 |
|
|||
Less: intrasegment revenues |
|
(56,163 |
) |
(45,804 |
) |
22.6 |
|
(46,213 |
) |
(0.9 |
) |
|||
Total operating revenues |
|
843,164 |
|
846,457 |
|
(0.4 |
) |
731,861 |
|
15.7 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Purchased gas costs |
|
568,154 |
|
593,093 |
|
(4.2 |
) |
489,156 |
|
21.2 |
|
|||
Net operating revenues |
|
275,010 |
|
253,364 |
|
8.5 |
|
242,705 |
|
4.4 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|||
Operating and maintenance (O & M) |
|
58,186 |
|
57,315 |
|
1.5 |
|
52,481 |
|
9.2 |
|
|||
Selling, general and administrative (SG&A) |
|
65,280 |
|
66,080 |
|
(1.2 |
) |
56,446 |
|
17.1 |
|
|||
Impairment charges |
|
(2,396 |
) |
3,841 |
|
(162.4 |
) |
|
|
100.0 |
|
|||
DD&A |
|
28,731 |
|
27,874 |
|
3.1 |
|
25,629 |
|
8.8 |
|
|||
Total operating expenses |
|
149,801 |
|
155,110 |
|
(3.4 |
) |
134,556 |
|
15.3 |
|
|||
Operating income |
|
$ |
125,209 |
|
$ |
98,254 |
|
27.4 |
|
$ |
108,149 |
|
(9.1 |
) |
Fiscal Year Ended December 31, 2006 vs. December 31, 2005
Equitable Utilities operating income totaled $125.2 million for 2006 compared to $98.3 million for 2005. Equitable Utilities operating income increased $26.9 million primarily due to increased net marketing revenues, lower expenses related to defined benefit pension plans, increased pipeline operating income, reduction in bad debt expense, an impairment charge in 2005 in connection with the Companys office consolidation and a gain in 2006 as a result of the partial reversal of the office impairment charge recorded in 2005. These improvements are partially offset by the impact of costs incurred in planning for the pending acquisition of The Peoples Natural Gas Company and Hope Gas Inc. and a reduction in distribution gas sales margins due to weather 15% warmer than the 30-year average.
Net operating revenues were $275.0 million for 2006 compared to $253.4 million for 2005. The $21.6 million increase in net operating revenues was primarily due to increased pipeline and marketing net operating revenues, partially offset by lower distribution net operating revenues. Pipeline operations net operating revenues increased $18.8 million from 2005 to 2006 primarily due to the settlement of Equitrans 2003 FERC rate case and the implementation of new rates and contracts in connection with that settlement. The settlements approval, which occurred in April 2006, improved net operating revenues by $7.0 million related to years 2005 and prior and an additional $5.7 million related to the transfer of certain gathering assets from Equitable Supply. New contract rates and billing determinants in the settlement result in the remaining $6.1 increase in pipeline net operating revenues. The increase in marketing net operating revenues of $16.4 million resulted primarily from increased storage asset opportunities realized in the volatile natural gas commodity price environment. Distribution operations net operating revenues decreased $13.5 million primarily due to decreased residential sales and transportation volumes, which decreased 3,666 MMcf from 2005 to 2006 due primarily to warmer weather.
Operating expenses totaled $149.8 million for 2006 compared to $155.1 million for 2005. Operating expenses for 2005 included $16.0 million in charges related to the termination and settlement of certain defined benefit pension plans and a $3.8 million loss related to the impairment of certain leased offices, furniture and equipment in connection with the Companys relocation into its new, consolidated office space. Operating expenses for 2006 include $12.3 million of costs incurred in planning for the pending acquisition of The Peoples Natural Gas
26
Company and Hope Gas, Inc.; a $2.9 million increase in gathering expenses as a result of the transfer of certain assets from Equitable Supply; the recognition of $4.6 million of previously deferred post-retirement benefit obligation expenses in the pipeline business, both in connection with the FERC rate case settlement; and the reversal of $2.4 million of the 2005 office impairment charge, as the space previously abandoned was put back into use for the transition planning activities relating to the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. Excluding these items, operating expenses decreased $2.9 million, which was primarily a result of decreases in distribution and marketing bad debt expense totaling $5.2 million, offset by increases of $0.9 million in depreciation expense and $0.8 million in general liability insurance expenses. The improvements in bad debt expense are a result of the more timely termination of non-paying customers, improved efforts to obtain alternative funding for low income customers and other improvements in the collections process. The increased depreciation expense is a result of increased capital spending in Equitable Utilities over the past two years and is primarily related to computer hardware and software, distribution mainline and service line replacements and the installation of automated meter reading devices.
Fiscal Year Ended December 31, 2005 vs. December 31, 2004
Equitable Utilities operating income totaled $98.3 million for 2005 compared to $108.1 million for 2004. Net operating income for 2005 included charges for the termination and settlement of defined benefit pension plans and an impairment charge in connection with the Companys office consolidation.
Net operating revenues were $253.4 million for 2005 compared to $242.7 million for 2004. The $10.7 million increase in net operating revenues was primarily due to increased marketing net operating revenues of $14.2 million, resulting primarily from increased storage asset opportunities realized in a high and increasingly volatile natural gas commodity price environment. Distribution operations net operating revenues decreased $2.2 million due to decreased volumes. Distribution operations residential sales and transportation volumes decreased 840 MMcf from 2004 to 2005 due to decreased base load and lower customer use per degree day. These reductions resulted from increased customer conservation, more timely termination of non-paying customers in 2005 and other factors. Increased volumes as a result of colder weather partially offset these decreases in residential volumes, as heating degree days were 5,543 in 2005, which was 3% colder than the 5,360 heating degree days in 2004 although still warmer than normal. Distribution operations commercial and industrial volumes decreased 4,229 MMcf from 2004 to 2005 primarily due to a reduction in industrial throughput to two major steel-making customers. These high volume industrial sales have very low unit margins and did not significantly impact total net operating revenues. Pipeline operations net operating revenues decreased $1.3 million from 2004 to 2005 primarily due to a $3.8 million loss on fuel and retention in excess of the current rates. This loss was partially offset by increased revenues earned in loaning and parking services. These services are contracted on an as-available basis, as opposed to long-term firm storage contracts. This flexibility allows customers, including the Companys marketing affiliate, to take advantage of the pipelines available storage to secure future supply at favorable prices. These services were heavily subscribed in 2005, as higher volatility in natural gas prices provided substantial value for storage options.
Operating expenses totaled $155.1 million for 2005 compared to $134.6 million for 2004. Operating expenses for 2005 included $16.0 million in charges related to the termination and settlement of certain defined benefit pension plans and a $3.8 million loss related to the impairment of certain leased offices, furniture and equipment in connection with the Companys relocation into its new, consolidated office space. Excluding these items, operating expenses increased $0.7 million, which resulted from increases of $2.3 million in depreciation expense, $2.2 million in incentive compensation, $1.4 million in customer operations expenses and $1.1 million in employee benefit costs, largely offset by decreases of $4.7 million in bad debt expense and $1.4 million in insurance costs. The increased depreciation expense is a result of increased capital spending in Equitable Utilities over the past two years and is primarily related to computer hardware and software, distribution mainline and service line replacements and the installation of automated meter reading devices. The improvements in bad debt expense are a result of the more timely termination of non-paying customers, a full year impact of a $0.30 per Mcf regulatory surcharge instituted in April 2004, improved efforts to obtain alternative funding for low income customers and other improvements in the collections process. These improvements were offset somewhat in the fourth quarter of 2005 by high commodity rates and cold weather, which resulted in increased provisions for bad debt in that period compared to the prior year.
27
See Capital Resources and Liquidity section for discussion of Equitable Utilities capital expenditures during 2006, 2005 and 2004.
Outlook
Equitable Utilities business strategy is focused on operational excellence. Success in this strategy depends upon efficiently and effectively operating its gas distribution assets to optimize a return on assets. Going forward, Equitable Utilities expects to grow its gas distribution business selectively by acquisition. It also expects to continue to develop a portfolio of closely related unregulated businesses. Key elements of Equitable Utilities strategy include:
· Enhancing the value and growth potential of the regulated utility operations. Equitable Utilities will seek to enhance the value and growth of its existing utility assets by managing its capital spending effectively; establishing a reputation for excellent customer service; continuing to leverage technology; working to achieve authorized returns in each jurisdiction and, in those jurisdictions where it has performance-based rates, sharing the benefits with its customers; and maintaining earnings and rate stability through regulatory arrangements that fairly balance the interests of customers and shareholders.
· Closing and integrating the acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. Equitable Utilities is focused on obtaining the required regulatory approvals to close the acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. Transition planning activities have commenced at Equitable Utilities to plan for the integration of The Peoples Natural Gas Company and Hope Gas, Inc. into Equitable Resources, with $12.3 million of expenses incurred through December 31, 2006. The assets to be acquired will increase: customers in the distribution operations by 475,000 or 173%; total storage capacity by 33 Bcf or 60%, miles of gathering pipelines by 936 miles; gathered volumes by 40%; and miles of high pressure transmission by 466 miles or 42%. Based on the work completed to date, the Company expects that the conversion activities will continue at a similar monthly rate through June 2007 and increase Equitable Utilities operating expenses in the first and second quarter of 2007 in anticipation of closing the transaction.
· Selectively expanding Equitable Utilities natural gas storage and gathering operations. Equitable Utilities will endeavor to continue to expand its natural gas storage and gathering businesses to provide disciplined incremental earnings growth for shareholders. Equitable Utilities also intends to continue to invest capital in its underground storage business to expand its operational capabilities by increasing storage deliverability, thereby providing an opportunity to capture increased value from the volatility in natural gas prices. Equitable Utilities intends to grow its asset management business by providing its customers with gas supply, storage and asset management options; capturing value from increased natural gas gathering margins; providing producers with access to markets for their increased production; and arbitraging pipeline and storage assets across various gas markets and time horizons. Capturing this value from Equitable Utilities storage assets may increase the volatility of reported earnings from this business. Equitable Utilities will continue to focus on marketing energy to customers from its own assets; controlling costs; and managing its portfolio with smart business decisions while looking for additional opportunities to provide economical storage services in the regions in which the Company operates.
28
Equitable Supply
Overview
Equitable Supplys sales revenues for 2006 were essentially flat in comparison with 2005 revenues. Sales volumes increased more than 5% from 2005 excluding volumes from properties sold during 2005, primarily as a result of increased production from the 2006 and 2005 drilling programs partially offset by the normal production decline in the Companys existing wells. Equitable Supply drilled 560 gross operated wells in 2006 compared to 420 gross operated wells in 2005, a 33% increase. The 560 operated wells included 5 horizontal wells and 16 wells drilled as part of a coal bed methane infill pilot.
The positive results experienced from the increased sales volumes were more than offset by a 7% decline in the average well-head sales price, due primarily to decreased market prices. The average NYMEX price decreased 16% in 2006 from the abnormally high price levels in 2005, negatively impacting revenues from sales of unhedged volumes.
Operating expenses at Equitable Supply increased 12% primarily due to certain non-recurring charges for royalty disputes, bad debt expenses and pension and other postretirement plans, as well as higher DD&A and gathering and compression expenses resulting from increased drilling and infrastructure investments, as the Company continues to expand its development and midstream activities in the Appalachian Basin.
29
Results of Operations
|
|
Years Ended December 31, |
|
|||||||||||
|
|
2006 |
|
2005 |
|
%
|
|
2004 |
|
%
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
OPERATIONAL DATA |
|
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Capital expenditures (thousands) (a) |
|
$ |
336,748 |
|
$ |
264,095 |
|
27.5 |
|
$ |
141,661 |
|
86.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Production: |
|
|
|
|
|
|
|
|
|
|
|
|||
Total sales volumes (MMcfe) |
|
76,156 |
|
73,909 |
|
3.0 |
|
67,731 |
|
9.1 |
|
|||
Average (well-head) sales price ($/Mcfe) |
|
$ |
4.83 |
|
$ |
5.17 |
|
(6.6 |
) |
$ |
4.46 |
|
15.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Company usage, line loss (MMcfe) |
|
5,215 |
|
4,897 |
|
6.5 |
|
5,090 |
|
(3.8 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Natural gas inventory usage, net (MMcfe) |
|
|
|
(51 |
) |
100.0 |
|
(61 |
) |
(16.4 |
) |
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Natural gas and oil production (MMcfe) (b) |
|
81,371 |
|
78,755 |
|
3.3 |
|
72,760 |
|
8.2 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Lease operating expenses (LOE), excluding production taxes ($/Mcfe) |
|
$ |
0.30 |
|
$ |
0.29 |
|
3.4 |
|
$ |
0.26 |
|
11.5 |
|
Production taxes ($/Mcfe) |
|
$ |
0.48 |
|
$ |
0.49 |
|
(2.0 |
) |
$ |
0.34 |
|
44.1 |
|
Production depletion ($/Mcfe) |
|
$ |
0.62 |
|
$ |
0.59 |
|
5.1 |
|
$ |
0.54 |
|
9.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Gathering: |
|
|
|
|
|
|
|
|
|
|
|
|||
Gathered volumes (MMcfe) |
|
108,592 |
|
121,044 |
|
(10.3 |
) |
127,339 |
|
(4.9 |
) |
|||
Average gathering fee ($/Mcfe) |
|
$ |
1.02 |
|
$ |
0.82 |
|
24.4 |
|
$ |
0.58 |
|
41.4 |
|
Gathering and compression expense ($/Mcfe) |
|
$ |
0.42 |
|
$ |
0.31 |
|
35.5 |
|
$ |
0.28 |
|
10.7 |
|
Gathering and compression depreciation ($/Mcfe) |
|
$ |
0.14 |
|
$ |
0.12 |
|
16.7 |
|
$ |
0.11 |
|
9.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|||
Production operating income |
|
$ |
231,849 |
|
$ |
260,931 |
|
(11.1 |
) |
$ |
212,657 |
|
22.7 |
|
Gathering operating income |
|
37,315 |
|
32,650 |
|
14.3 |
|
14,712 |
|
121.9 |
|
|||
Total operating income |
|
$ |
269,164 |
|
$ |
293,581 |
|
(8.3 |
) |
$ |
227,369 |
|
29.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Production depletion |
|
$ |
50,330 |
|
$ |
46,750 |
|
7.7 |
|
$ |
39,100 |
|
19.6 |
|
Gathering and compression depreciation |
|
15,411 |
|
14,312 |
|
7.7 |
|
13,441 |
|
6.5 |
|
|||
Other DD&A |
|
4,759 |
|
3,835 |
|
24.1 |
|
3,295 |
|
16.4 |
|
|||
Total DD&A |
|
$ |
70,500 |
|
$ |
64,897 |
|
8.6 |
|
$ |
55,836 |
|
16.2 |
|
30
|
|
Years Ended December 31, |
|
|||||||||||
|
|
2006 |
|
2005 |
|
%
|
|
2004 |
|
%
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
FINANCIAL DATA (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Production revenues |
|
$ |
377,626 |
|
$ |
390,290 |
|
(3.2 |
) |
$ |
315,986 |
|
23.5 |
|
Gathering revenues (c) |
|
110,945 |
|
98,901 |
|
12.2 |
|
74,442 |
|
32.9 |
|
|||
Total operating revenues |
|
488,571 |
|
489,191 |
|
(0.1 |
) |
390,428 |
|
25.3 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|||
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|||
LOE, excluding production taxes |
|
24,620 |
|
23,195 |
|
6.1 |
|
18,685 |
|
24.1 |
|
|||
Production taxes (d) |
|
38,653 |
|
38,288 |
|
1.0 |
|
24,589 |
|
55.7 |
|
|||
Gathering and compression (O&M) |
|
45,860 |
|
38,101 |
|
20.4 |
|
35,494 |
|
7.3 |
|
|||
SG&A |
|
39,774 |
|
30,610 |
|
29.9 |
|
28,455 |
|
7.6 |
|
|||
Impairment charges |
|
|
|
519 |
|
(100.0 |
) |
|
|
100.0 |
|
|||
DD&A |
|
70,500 |
|
64,897 |
|
8.6 |
|
55,836 |
|
16.2 |
|
|||
Total operating expenses |
|
219,407 |
|
195,610 |
|
12.2 |
|
163,059 |
|
20.0 |
|
|||
Operating income |
|
$ |
269,164 |
|
$ |
293,581 |
|
(8.3 |
) |
$ |
227,369 |
|
29.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Equity in earnings of nonconsolidated investments |
|
$ |
129 |
|
$ |
493 |
|
(73.8 |
) |
$ |
688 |
|
(28.3 |
) |
Other income, net |
|
$ |
|
|
$ |
|
|
|
|
$ |
576 |
|
(100.0 |
) |
(a) 2005 capital expenditures include $57.5 million for the acquisition of the limited partnership interest in Eastern Seven Partners, L.P. (ESP).
(b) Natural gas and oil production represents the Companys interest in gas and oil production measured at the well-head. It is equal to the sum of total sales volumes, Company usage, line loss, and natural gas inventory usage, net.
(c) Revenues associated with the use of pipelines and other equipment to collect, process and deliver natural gas from the field to the trunk or main transmission line. Many contracts are for a blended gas commodity and gathering price, in which case the Company utilizes standard measures in order to split the price into its two components.
(d) Production taxes include severance and production-related ad valorem and other property taxes.
Fiscal Year Ended December 31, 2006 vs. December 31, 2005
Equitable Supplys operating income totaled $269.2 million for 2006 compared to $293.6 million for 2005, a decrease of $24.4 million between years. Production operating income decreased $29.1 million primarily due to a decrease in well-head sales price and an increase in production operating expenses, partially offset by increased sales volumes. Gathering operating income increased $4.7 million due to an increase in the average gathering fee, partially offset by decreased gathered volumes and increased gathering operating expenses.
Total operating revenues were $488.6 million for 2006 compared to $489.2 million for 2005. The $0.6 million decrease in net operating revenues was primarily due to a 7% per Mcfe decrease in the average well-head sales price, partially offset by a 3% increase in production total sales volumes and a 12% increase in gathering revenues. The $0.34 per Mcfe decrease in the average well-head sales price was mainly attributable to decreased market prices on unhedged volumes and increased gathering charges, partially offset by the absence of a 2005
31
negative price adjustment. The 2005 adjustment was principally due to the Companys conclusion that the well-head sales price allocated to a third partys working interest gas in previous periods may have been lower than the Company was obligated to pay. The 3% increase in production total sales volumes was primarily the result of the 2006 and 2005 drilling programs, partially offset by the sale of certain non-core gas properties in 2005 and the normal production decline in the Companys wells. The 12% increase in gathering revenues was attributable to a 24% increase in the average gathering fee, partially offset by a 10% decline in gathered volumes. The increase in average gathering fee is reflective of the Companys commitment to an increased infrastructure capital program, along with higher gas prices and related operating cost increases. The average gathering fee was also positively impacted by the transfer of certain regulated gathering facilities to Equitable Utilities. The decrease in gathered volumes in 2006 was primarily due to the transfer of gathering facilities to Equitable Utilities, the sale of gathering assets in 2005 and third-party customer volume shut-ins caused by maintenance projects on interstate pipelines. These factors were partially offset by increased gathered volumes for Company production in 2006.
Operating expenses totaled $219.4 million for 2006 compared to $195.6 million for 2005. The $23.8 million increase in operating expenses was due to increases of $9.2 million in SG&A, $7.8 million in gathering and compression, $5.6 million in DD&A, $1.4 million in LOE, and $0.4 million in production taxes, partially offset by a $0.5 million impairment charge in 2005 related to the Companys office consolidation. The increase in SG&A was the result of reserves established in connection with West Virginia royalty disputes and bad debt expenses. The increase in gathering and compression was primarily due to pension and other postretirement benefits charges for an early retirement program totaling $3.3 million, increased compressor station operation and repair costs, including electricity on newly installed compressors, increased property taxes and increased field labor and related employment costs. These factors were partially offset by the transfer of gathering facilities to Equitable Utilities and the sale of gathering assets in 2005. The increase in DD&A was due to a $0.03 per Mcf increase in the unit depletion rate ($2.0 million), increased depreciation on a higher asset base ($2.0 million) and increased produced volumes ($1.6 million). The increase in the unit depletion rate was primarily due to the net development capital additions in 2005 on a relatively consistent proved reserve base. The increase in LOE was primarily due to increased direct well expenses and well and location repairs and maintenance, partially offset by the sale of gas properties in 2005. The increase in production taxes was due to increased property taxes ($2.4 million), partially offset by decreased severance taxes ($2.0 million). The increase in property taxes was a direct result of increased prices and sales volumes in prior years, as property taxes in several of the taxing jurisdictions where the Companys wells are located are calculated based on historical gas commodity prices and sales volumes. The decrease in severance taxes (a production tax directly imposed on the value of gas extracted) was primarily due to lower gas commodity prices in the various taxing jurisdictions that impose such taxes. The impairment charges in 2005 were related to the Companys relocation of its corporate headquarters and other operations of its new consolidated office space.
Fiscal Year Ended December 31, 2005 vs. December 31, 2004
Equitable Supplys operating income totaled $293.6 million for 2005 compared to $227.4 million for 2004, an increase of $66.2 million between years. Production operating income increased $48.2 million primarily due to an increase in well-head sales price and an increase in sales volumes, partially offset by increased production operating expenses. Gathering operating income increased $18.0 million due to an increase in the average gathering fee, partially offset by decreased gathered volumes and increased gathering operating expenses.
Total operating revenues were $489.2 million for 2005 compared to $390.4 million for 2004. The $98.8 million increase in net operating revenues was primarily due to a 16% increase in the average well-head sales price, a 9% increase in production total sales volumes and a 33% increase in gathering revenues. The $0.71 per Mcfe increase in the average well-head sales price was mainly attributable to increased market prices on unhedged volumes partially offset by the adjustment related to a third partys working interest gas as previously discussed. The 9% increase in production total sales volumes was primarily the result of the purchase of ESP, partially offset by the sale of gas properties. The 33% increase in revenues from gathering fees was attributable to a 41% increase in the average gathering fee, partially offset by a 5% decline in gathered volumes. The increase in average gathering fee is reflective of the Companys commitment to an increased infrastructure capital program, along with higher gas prices and related operating cost increases. The decrease in gathered volumes in 2005 was primarily due to the sale of gathering assets and third-party customer volume shut-ins caused by maintenance projects on interstate pipelines. These factors were partially offset by increased gathered volumes for Company production in 2005. These increases
32
in production and gathering revenues were partially offset by the recognition of a gain of $2.7 million in 2004 that resulted from the renegotiation of a processing agreement.
Operating expenses totaled $195.6 million for 2005 compared to $163.1 million for 2004. A significant reason for this $32.5 million increase was due to additional costs of $15.0 million resulting from the purchase of ESP. The $15.0 million of costs were primarily related to DD&A ($4.7 million), production taxes ($4.6 million), lease operating expenses ($3.7 million) and gathering expenses ($2.0 million). Excluding the ESP costs, the $17.5 million increase in operating expenses was due to increases of $9.1 million in production taxes, $4.4 million in DD&A, $2.1 million in SG&A, $0.8 million in LOE, $0.6 million in gathering expenses and $0.5 million in impairment charges related to the Companys office consolidation. The increase in production taxes was due to increased property taxes ($5.4 million) and severance taxes ($3.7 million). The increase in property taxes was a direct result of increased prices and sales volumes in prior years. The increase in severance taxes was primarily due to higher gas commodity prices and sales volumes in 2005 as compared to prior years.
The increase in DD&A excluding ESP was due to a $0.05 per Mcf increase in the unit depletion rate ($4.3 million) and increased depreciation on a higher asset base ($1.4 million), partially offset by lower depletion as a result of decreased volumes from the sale of gas properties ($1.3 million). The increase in the unit depletion rate was primarily due to the net development capital additions in 2005 and 2004. The increase in SG&A was the result of increased legal and professional fees and bad debt expenses. The increase in LOE was the result of the Companys strategy to focus on current infrastructure as well as increased costs from vendors due to higher gas prices. The increase in gathering expenses was primarily attributable to increased electricity charges resulting from newly installed electric compressors, field labor and related employment costs and compressor station operation and repair costs. The gathering and compression increases are consistent with the Companys strategic decision to focus on improving gathering and compression and metering effectiveness. Such increases were partially offset by reductions in gathering expenses due to reduced gathered volumes.
Other income, net for 2004 was the result of a $6.1 million settlement received from a previously disputed insurance coverage claim, offset by a $5.5 million expense related to the Companys settlement of a prepaid forward contract in 2004.
See Capital Resources and Liquidity section for discussion of Equitable Supplys capital expenditures during 2006, 2005 and 2004.
Outlook
Equitable Supplys Appalachian Basin business strategy is focused on growing through expansion of its drilling program and gathering systems. The Company will continue to emphasize operational excellence, including cost control in all areas of its operations. Key elements of Equitable Supplys strategy include:
· Expanding production through the drilling program. Equitable Supply has a multi-year drilling program which includes increased drilling of conventional wells, down spacing coal bed methane wells, continuing its horizontal drilling efforts and selectively participating in non-operated wells developed on acreage held by the Company. These efforts will enable the Company to continue the growth of its production business. Equitable Supply intends to drill 650 gross operated wells in 2007, including at least 25 horizontal wells, a 16% increase over the 560 gross operated wells drilled in 2006. Through testing a variety of horizontal drilling techniques, the Company expects to better understand reservoir response and the economic viability of reserve development through horizontal drilling. Similarly, through the ongoing infill pilot, the Company will evaluate the economic viability of accelerating production by down spacing coal bed methane wells . Equitable Supply believes that its 772 Bcfe of proved undeveloped reserves will be developed within a reasonable time period (currently estimated to be five years) because Equitable Supply (i) completed substantially all of the wells it drilled in the last three years and (ii) developed proved undeveloped reserves of 60 Bcfe and 70 Bcfe during 2006 and 2005, respectively. Equitable Supplys plans include developing similar levels of proved undeveloped reserves going forward.
33
· Investing in midstream gathering and processing in the Appalachian Basin. Infrastructure to support the Companys increased drilling, to mitigate curtailments on and increase flexibility and reliability of gathering systems and to move gas from wellhead to market presents an acute need but also a significant opportunity for the Company.
· Through its Equitrans affiliate, the Company is constructing the Big Sandy Pipeline, which will provide for a significant increase in midstream throughput capacity. The Company is also planning an upgrade to the Company-operated hydrocarbon processing plant in Langley, Kentucky for completion in early 2008. The projects are projected to cost an aggregate of $191 million.
· The Company plans to expand its gathering systems by approximately 200 miles of gathering line and approximately 25,000 horsepower of compression in 2007. Many of the existing gathering lines will be increased in size to handle these additional volumes and new gathering lines will be constructed to expanded drilling areas. The Company plans to build new compression stations as well as expand existing stations in order to transport gas to sales points on interstate pipelines.
· The Company is also evaluating several other processing, gathering line and compression expansion opportunities in Appalachia and expects to invest in additional projects in 2007 and beyond.
These efforts will assist the Company to move not only its gas, but also third party producer gas, from wellhead to market.
Other Income Statement Items
|
|
Years Ended December 31, |
|
|||||||
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
Income (loss) from discontinued operations |
|
$ |
4,261 |
|
$ |
1,481 |
|
$ |
(18,936 |
) |
Gain on sale of available-for-sale securities, net |
|
|
|
110,280 |
|
3,024 |
|
|||
Other income, net |
|
|
|
1,195 |
|
3,692 |
|
|||
Gain on exchange of Westport for Kerr-McGee shares |
|
|
|
|
|
217,212 |
|
|||
Charitable foundation contribution |
|
|
|
|
|
(18,226 |
) |
|||
As noted in Item 1, the Companys NORESCO business is classified as discontinued operations due to the sale of the NORESCO domestic business in 2005 and sale of the Companys remaining international investment in early 2006. Income (loss) from discontinued operations for 2006 included a tax benefit of $3.2 million due to a reduced tax liability on the sale and after-tax income of $1.1 million resulting from the Companys reassessment of its remaining obligations for costs incurred related to the sale. Income (loss) from discontinued operations for 2004 included approximately $23.9 million of after-tax impairments on international investments and charges for related reserves, while income (loss) from discontinued operations for 2005 included the reversal of approximately $7.8 million of these reserves (after tax) due to improved business conditions in the related international markets, as well as a $6.4 million tax benefit from the reorganization of the Companys international assets in 2005. These increases in 2005 as compared to 2004 were partially offset by $18.7 million in after-tax charges recorded in 2005, related to the recording of $13.7 million of income taxes on the sale and other costs incurred as a result of the sale transaction.
During 2005, the Company sold its remaining 7.0 million Kerr-McGee shares resulting in pre-tax gains net of collar termination costs totaling $110.3 million. During 2004, the Company sold 0.8 million Kerr-McGee shares, resulting in a pre-tax gain of $3.0 million.
Other income, net includes pre-tax dividend income relating to the Kerr-McGee shares held by the Company of $1.2 million and $3.1 million for 2005 and 2004, respectively.
34
As a result of the 2004 merger between Westport and Kerr-McGee, the Company recognized a gain of $217.2 million on the exchange of its Westport shares for Kerr-McGee shares. See Note 9 to the Companys Consolidated Financial Statements for further information on this transaction.
In 2004, the Company contributed approximately 0.4 million Kerr-McGee shares to Equitable Resources Foundation, Inc., resulting in the Company recording a charitable foundation contribution expense of $18.2 million during 2004. See Note 9 to the Companys Consolidated Financial Statements for further information on this transaction.
Interest Expense
|
|
Years Ended December 31, |
|
|||||||
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
|
|
|
|
|
|
|
|
|||
Interest expense |
|
$ |
47,052 |
|
$ |
44,437 |
|
$ |
42,520 |
|
Interest expense increased by $2.7 million from 2005 to 2006 primarily due to a full year of interest expense in 2006 from the issuance of $150 million of notes with a stated interest rate of 5% on September 30, 2005 and an increase in the average annual short-term debt interest rate, partially offset by lower average short-term debt during 2006.
Interest expense increased by $1.9 million from 2004 to 2005 primarily due to the issuance of $150 million of notes with a stated interest rate of 5% on September 30, 2005 and an increase in the average annual short-term debt interest rate. These increases were partially offset by the maturity of $10 million of medium-term notes during 2005.
Average annual interest rates on the Companys short-term debt were 4.6%, 3.5%, and 1.7% for 2006, 2005 and 2004, respectively.
Capital Resources and Liquidity
Operating Activities
Cash flows provided by operating activities totaled $619.3 million for 2006 as compared to $312.0 million of cash flows used in operating activities for 2005, a net increase of $931.3 million in cash flows provided by operating activities between years. The increase in cash flows provided by operating activities was attributable to the following:
· a $598.7 million net reduction in cash required for margin deposit requirements on the Companys natural gas hedge agreements, primarily due to significantly higher than normal gas prices in 2005 which resulted in increased deposit remittances in that year;
· a decrease in tax payments to $58.6 million in 2006 from $251.5 million in 2005, primarily due to taxes paid in 2005 related to the sale of the Companys Kerr-McGee shares, the sale of the NORESCO discontinued operations and the sale of non-core gas properties for significant taxable gains, all in 2005;
· a decrease in accounts receivable of $63.5 million in 2006 compared to an increase of $78.0 million in 2005, primarily due to decreased natural gas prices during 2006 as compared to significant increases in prices in 2005;
· a decrease in inventory of $20.8 million during 2006 as compared to an increase of $85.3 million in 2005, primarily due to increased natural gas prices on volumes stored in 2005 as well as decreased prices in 2006;
35
partially offset by:
· a decrease in accounts payable of $29.3 million in 2006 compared to an increase of $71.5 million in 2005, primarily due to decreased natural gas prices during 2006 as compared to significant increases in prices in 2005;
· a large reduction in other current liabilities during 2006, as significant amounts were outstanding at December 31, 2005 for which payment was remitted shortly after the 2005 year-end.
Cash flows used in operating activities totaled $312.0 million for 2005 as compared to $180.0 million of cash flows provided by operating activities for 2004, a net increase of $492.0 in cash flows used in operating activities between years. The increase in cash flows used in operating activities was attributable to the following:
· an increase in margin deposit requirements to $317.8 million as of December 31, 2005, from $36.9 million as of December 31, 2004, primarily resulting from increased natural gas prices during 2005;
· an increase in tax payments to $251.5 million in 2005 compared to $23.0 million in 2004 as described above;
· an increase in inventory to $289.9 million as of December 31, 2005, from $204.6 million as of December 31, 2004, primarily due to increased natural gas prices on volumes stored in 2005 compared to 2004;
partially offset by:
· an increase in accounts payable to $242.6 million as of December 31, 2005, from $171.2 million as of December 31, 2004, largely due to increased operating costs resulting from increased drilling activity and higher natural gas prices.
Investing Activities
Cash flows used in investing activities totaled $407.7 million for 2006 as compared to $347.7 million of cash flows provided by investing activities for 2005, a net increase of $755.4 million in cash flows used in investing activities between years. The increase in cash flows used in investing activities was attributable to the following:
· net proceeds of $460.5 million received from the sale of approximately 7.0 million shares of Kerr-McGee Corporation common stock in 2005;
· proceeds of $142.0 million from the sale of certain non-core gas properties and associated gathering assets in 2005;
· an increase in capital expenditures to $404.5 million in 2006 from $275.8 million in 2005. See discussion of capital expenditures below;
· proceeds of $80.0 million from the sale of the domestic operations of the Companys NORESCO business segment in 2005;
partially offset by:
· the Companys acquisition of the 99% limited partnership interest in ESP for $57.5 million in 2005.
36
Cash flows provided by investing activities totaled $347.7 million for 2005 as compared to $158.5 million of cash flows used in investing activities for 2004, a net increase of $506.2 million in cash flows provided by investing activities between years. The increase in cash flows provided by investing activities was attributable to the following:
· a $417.6 million year-over-year increase in net proceeds received from the sale of shares of Kerr-McGee;
· proceeds of $142.0 million from the sale of properties in 2005;
· proceeds of $80.0 million from the sale of NORESCO in 2005;
partially offset by:
· an increase in capital expenditures to $333.3 million in 2005 from $201.8 million in 2004. See discussion of capital expenditures below.
Capital Commitments and Expenditures
The Company forecasts $588 million of capital commitments for 2007. This forecast includes $237 million for well development, $256 million for Supply infrastructure, $92 million for Equitable Utilities and $3 million for Headquarters. A portion of these capital commitments is not expected to impact cash flow until 2008 and beyond.
Capital Expenditures
|
|
2007 Forecast |
|
2006 Actual |
|
2005 Actual |
|
2004 Actual |
|
||||
Well development (primarily drilling) |
|
$ |
231 million |
|
$ |
200 million |
|
$131 million
|
|
$ |
92 million |
|
|
Supply infrastructure |
|
$ |
396 million |
|
$ |
137 million |
|
$ |
75 million |
|
$ |
50 million |
|
Equitable Utilities |
|
$ |
82 million |
|
$ |
65 million |
|
$ |
61 million |
|
$ |
56 million |
|
Headquarters |
|
$ |
3 million |
|
$ |
3 million |
|
$ |
8 million |
|
$ |
4 million |
|
Total* |
|
$ |
712 million |
* |
$ |
405 million |
|
$ |
333 million |
|
$ |
202 million |
|
* The 2007 capital expenditures do not include amounts related to the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. The 2007 capital expenditures include 2006 capital commitments totaling $361 million, including $257 million for Supply infrastructure, $92 million for well development, and $12 million for Equitable Utilities.
Capital expenditures for well development and Supply infrastructure increased in 2006 as compared to 2005 primarily due to an increased drilling and development plan in 2006, capital expended for construction of the Big Sandy Pipeline and other throughput optimization projects. Capital expenditures for well development and Supply infrastructure increased in 2005 as compared to 2004 primarily due to an increased drilling and development plan in 2005.
Capital expenditures for Equitable Utilities increased in 2006 as compared to 2005 primarily due to increased transmission pipeline replacement associated with pipeline integrity under The Pipeline Safety Improvement Act of 2002 and increased gathering infrastructure expenditures. Capital expenditures for Equitable Utilities increased in 2005 as compared to 2004 due to the installation of electronic meter reading technology on meters in the distribution operations, a project that was substantially completed in the third quarter of 2006.
37
The Companys capital expenditures forecasted for 2007 represent a significant increase over capital expenditures in 2006. The $231 million targeted for well development in 2007 represents a $31 million increase over 2006 which is attributable to an expanded drilling program. The $396 million forecasted for 2007 Supply infrastructure includes further expansions in infrastructure to support the Companys current and future drilling plans as well as expenditures for the Big Sandy Pipeline and Langley plant projects. The $82 million forecasted for Equitable Utilities includes $77 million for infrastructure improvements and $5 million for new business development. The infrastructure improvements include improvements to existing distribution lines, an increase in transmission pipeline replacement and additional investment in gathering system improvements and extensions. The new business capital is planned for extensions of existing infrastructure into adjacent geographic areas.
The Company expects to finance its capital expenditures with cash generated from operations and with short-term debt. See discussion in the Short-term Borrowings section below regarding the financing capacity of the Company.
Financing Activities
Cash flows used in financing activities totaled $286.5 million for 2006 as compared to $39.2 million of cash flows provided by financing activities for 2005, a net increase of $325.7 million in cash flows used in financing activities between years. The increase in cash flows used in financing activities was attributable largely to the following:
· a $229.3 million decrease in amounts borrowed under short-term loans in 2006 compared to a $69.8 million increase in short-term borrowings in 2005. The decrease in short-term borrowings in 2006 was primarily the result of decreased requirements for funding margin deposits as previously discussed;
· proceeds in 2005 from the September 2005 issuance of $150.0 million of notes with a stated interest rate of 5% and a maturity date of October 1, 2015;
partially offset by:
· no repurchases of shares of the Companys outstanding common stock under the Companys share repurchase program during 2006 in anticipation of the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc., compared to repurchases of $122.3 million of common stock in 2005.
Cash flows provided by financing activities totaled $39.2 million for 2005 as compared to $55.8 million of cash flows used in financing activities for 2004, a net increase of $95.0 million in cash flows provided by financing activities between years. The increase in cash flows provided by financing activities from 2004 to 2005 was attributable largely to the following:
· proceeds of $150.0 million from the issuance of notes in September 2005;
partially offset by:
· less of an increase in amounts borrowed under short-term loans in 2005 as compared to 2004.
The Company believes that cash generated from operations, amounts available under its credit facilities and amounts which the Company could obtain in the debt and equity markets given its financial position, are more than adequate to meet the Companys reasonably foreseeable liquidity requirements. The Company anticipates financing its capital expenditures and the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. through a combination of debt, equity, and asset sales.
38
Short-term Borrowings
Cash required for operations is affected primarily by the seasonal nature of the Companys natural gas distribution operations and the volatility of oil and natural gas commodity prices. The Companys $1.5 billion, five-year revolving credit agreement may be used for working capital, capital expenditures, share repurchases and other purposes including support of the Companys commercial paper program. Historically, short-term borrowings under the commercial paper program have been used mainly to support working capital requirements during the summer months and are repaid as natural gas is sold during the heating season. Due to decreased natural gas prices and increased margin deposit thresholds with financial institutions during 2006 and resulting decreases in the Companys net liability position under its natural gas swap agreements, the Company borrowed decreased amounts through its commercial paper program to fund its interest-bearing margin deposits under its natural gas hedge agreements. The amount of commercial paper outstanding at December 31, 2006 was $136.0 million. Interest rates on these short-term loans averaged 4.6% during 2006.
Security Ratings and Financing Triggers
The table below reflects the current credit ratings for the outstanding debt instruments of the Company. Changes in credit ratings may affect the Companys cost of short-term and long-term debt and its access to the credit markets.
Rating Service |
|
Unsecured
|
|
Commercial
|
|
Moodys Investors Service |
|
A-2 |
|
P-1 |
|
Standard & Poors Ratings Services |
|
A - |
|
A-2 |
|
On March 2, 2006, Standard & Poors Ratings Services placed the Companys short and long-term credit ratings on CreditWatch with negative implications and Moodys Investors Service placed the ratings under review for possible downgrade. These actions resulted from the Companys announcement that it had entered into a definitive agreement to acquire The Peoples Natural Gas Company and Hope Gas, Inc., subject to anti-trust and regulatory approvals. The final ratings outcomes are expected to be determined after the acquisition financing plan has been reviewed by the ratings agencies and the regulatory approval process is near completion.
The Companys credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. The Company cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant. If the credit rating agencies downgrade the Companys ratings, particularly below investment grade, it may significantly limit the Companys access to the commercial paper market and borrowing costs would increase. In addition, the Company would likely be required to pay a higher interest rate in future financings, incur increased margin deposit requirements with respect to its hedging instruments, and the potential pool of investors and funding sources would decrease.
The Companys credit ratings on its non-credit-enhanced, senior unsecured long-term debt determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Companys credit rating, the higher the level of fees and interest rate. As of December 31, 2006, the Company had no outstanding borrowings against these lines of credit. The Company pays facility fees to maintain credit availability.
The Companys debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. The most important default events include maintaining covenants with respect to maximum leverage ratio, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations, and change of control provisions. The Companys current credit facilitys financial covenants require a total debt-to-total capitalization ratio of no greater than 65%. The calculation of this ratio excludes accumulated other comprehensive income
39
(loss). During an acquisition period, which is defined as the period beginning with the funding of the purchase price for the stock of The Peoples Natural Gas Company and Hope Gas, Inc. and ending on the first fiscal quarter end at least 365 days after the funding of such purchase price, the covenant is relaxed from 65% to 70%. As of December 31, 2006, the Company is in compliance with all existing debt provisions and covenants.
Commodity Risk Management
The Companys overall objective in its hedging program is to protect earnings from undue exposure to the risk of changing commodity prices. The Companys risk management program includes the use of exchange-traded natural gas futures contracts and options and OTC natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and for trading purposes. The preponderance of derivative commodity instruments currently utilized by the Company are fixed price swaps or collars.
During 2006, the Company increased its hedge position for 2007 through 2013. As a result, the approximate volumes and prices of the Companys total hedge position for 2007 through 2009 are:
|
|
2007 |
|
2008 |
|
2009 |
|
|||
Swaps |
|
|
|
|
|
|
|
|||
Total Volume (Bcf) |
|
56 |
|
54 |
|
38 |
|
|||
Average Price per Mcf (NYMEX)* |
|
$ |
4.74 |
|
$ |
4.64 |
|
$ |
5.90 |
|
|
|
|
|
|
|
|
|
|||
Collars |
|
|
|
|
|
|
|
|||
Total Volume (Bcf) |
|
10 |
|
10 |
|
10 |
|
|||
Average Floor Price per Mcf (NYMEX)* |
|
$ |
7.61 |
|
$ |
7.61 |
|
$ |
7.61 |
|
Average Cap Price per Mcf (NYMEX)* |
|
$ |
11.27 |
|
$ |
11.27 |
|
$ |
11.27 |
|
* The above price is based on a conversion rate of 1.05 MMBtu/Mcf
The Companys current hedged position provides price protection for a substantial portion of expected equity production for the years 2007 through 2009 and a significant portion of expected equity production for the years 2010 through 2013. The Companys exposure to a $0.10 change in average NYMEX natural gas price is approximately $0.01 per diluted share for 2007 and ranges from $0.01 to $0.03 per diluted share per year for 2008 and 2009. The Company also engages in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices. See Note 3 to the Companys Consolidated Financial Statements for further discussion.
Investment Securities
The Companys available-for-sale investments as of December 31, 2006 and 2005 consist of approximately $31.3 million and $25.2 million, respectively, of equity securities that are intended to fund certain liabilities for which the Company is self-insured. These investments are recorded at fair market value. During 2005, the Company sold all of its remaining 7.0 million shares of Kerr-McGee in various transactions for total net pre-tax proceeds of $460.5 million and a total pre-tax gain of $110.3 million, net of $95.8 million in costs associated with the termination of the three related variable share forward transactions entered into in June 2004 subsequent to the Westport/Kerr-McGee merger.
Other Items
Off-Balance Sheet Arrangements
The Company has a non-equity interest in a variable interest entity, Appalachian NPI, LLC (ANPI), in which Equitable was not deemed to be the primary beneficiary. As of December 31, 2006, ANPI had $214 million of total assets and $336 million of total liabilities (including $137 million of long-term debt, including current maturities), excluding minority interest.
40
The Company provides a liquidity reserve guarantee to ANPI, which is subject to certain restrictions and limitations, and is secured by the fair market value of the assets purchased by the Appalachian Natural Gas Trust (ANGT). The Company received a market-based fee for the issuance of the reserve guarantee. As of December 31, 2006, the maximum potential amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be approximately $50 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN 45 and has not been modified subsequent to issuance.
The Company has entered into an agreement with ANGT to provide gathering and operating services to deliver ANGTs gas to market. In addition, the Company receives a marketing fee for the sale of gas based on the net revenue for gas delivered. The revenue earned from these fees totaled approximately $16.8 million for 2006.
In connection with the sale of its NORESCO domestic business in 2005, the Company agreed to maintain certain guarantees which benefit NORESCO. These guarantees, the majority of which predate the sale of NORESCO, became off-balance sheet arrangements upon the closing of the sale of NORESCO. These arrangements include guarantees of NORESCOs obligations to the purchasers of certain of NORESCOs contract receivables and agreements to maintain guarantees supporting NORESCOs obligations under certain customer contracts. In addition, NORESCO and the purchaser agreed that NORESCO would fully perform its obligations under each underlying agreement and that the purchaser or NORESCO would reimburse the Company for losses under the guarantees. The purchasers obligations to reimburse the Company are capped at $6 million. The Company determined that the likelihood the Company will be required to perform on these arrangements is remote, and as such, the Company has not recorded any liabilities in its Consolidated Balance Sheets related to these guarantees. The total maximum potential obligation under these arrangements is estimated to be approximately $484 million as of December 31, 2006, and decreases over time as the guarantees expire or the underlying obligations are fulfilled by NORESCO.
See Note 20 to the Consolidated Financial Statements for further discussion of the Companys guarantees.
Pension Plans
In September 2006, the FASB issued SFAS No. 158, which requires an employer to recognize a benefit plans funded status in its statement of financial position, measure a benefit plans assets and obligations as of the end of the employers fiscal year and recognize the changes in the benefit plans funded status in other comprehensive income in the year in which the changes occur. SFAS No. 158s requirement to recognize the funded status of a benefit plan and the new disclosure requirements were effective for the year-ended December 31, 2006. See Footnote 13 for information regarding the adoption of SFAS No. 158 as of December 31, 2006.
Total pension expense recognized by the Company in 2006, 2005 and 2004, excluding special termination benefits, settlement losses and curtailment losses, totaled $0.1 million, $0.4 million and $0.4 million, respectively. The Company recognized special termination benefits, settlement losses and curtailment losses in 2006, 2005 and 2004 of $3.0 million, $18.4 million and $16.2 million, respectively. As a result of these costs, the Companys projected benefit obligation decreased by approximately $36.0 million.
During the fourth quarter of 2006, the Company recognized a settlement expense of approximately $2.7 million for an early retirement program.
During 2005, the Company settled its pension obligation with the United Steelworkers of America, Local Union 12050 representing 182 employees. As a result of this settlement, the Company recognized a settlement expense of $12.1 million during 2005. During the fourth quarter of 2005, the Company settled its pension obligation with certain non-represented employees. As a result of this settlement, the Company recognized a settlement expense of approximately $2.4 million in 2005.
Effective December 31, 2004, the Company settled the pension obligation of those non-represented employees (cash balance participants) whose benefits were frozen as of December 31, 2003. As a result of this settlement, the Company recognized settlement expense of $13.4 million in 2004.
41
The Company made cash contributions of approximately $1.8 million and $20.4 million to its pension plan during 2006 and 2005, respectively, as a result of the previously described settlements. The Company expects to make cash contributions of approximately $1.0 million to its pension plan during 2007. The Company was not required to, and consequently did not make any contribution to its pension plans during the year ended December 31, 2004.
Incentive Compensation
The Company adopted SFAS No. 123R on January 1, 2006, which results in the Company recognizing compensation cost for all forms of share-based payments to employees, including employee stock options, as an expense in its income statement. The Company previously applied APB No. 25 in accounting for its share-based compensation and consequently did not recognize any compensation cost for its stock option awards. The Companys estimate of compensation cost for stock options is based on the use of the Black-Scholes option-pricing model. The Black-Scholes model is considered a theoretical or probability model used to estimate the price an option would sell for in the market today. The Company does not represent that this method yields an exact value of what an unrelated third party (i.e., the market) would be willing to pay to acquire such options.
The Company adopted SFAS No. 123R using the modified prospective method, under which the Company recorded compensation expense for its unvested stock options beginning January 1, 2006. As such, the Company did not restate any prior period income statement amounts. In addition, the adoption of SFAS No. 123R did not result in any significant changes to the Companys method for valuing its stock options from that previously used for pro forma disclosures under SFAS No. 123.
The adoption of SFAS No. 123R did not have a significant impact on the Companys operating results for 2006, as the Company has shifted its compensation focus to the issuance of performance-based units and time-restricted stock awards for which it already recognized compensation expense under generally accepted accounting principles. Management and the Board of Directors believe that such an incentive compensation approach more closely aligns managements incentives with shareholder rewards than is the case with traditional stock options. No new stock options have been awarded since 2003; all stock options granted subsequent to 2003 have comprised options granted for reload rights associated with previously-awarded options.
The Company recorded approximately $1.0 million of compensation expense related to stock options in 2006, the majority of which related to stock option reloads which immediately vested under the terms of the related stock option award agreements. The majority of the Companys previously issued stock options were already vested at the time of adoption of SFAS No. 123R, and associated compensation expense yet to be recognized was insignificant. All stock options outstanding as of December 31, 2006 are fully vested, and as such, the Company does not anticipate incurring any additional compensation expense related to currently outstanding stock options.
Had compensation cost been determined based on the fair value at the grant date for prior periods stock option grants consistent with the methodology prescribed in SFAS No. 123R, net income would have been reduced by an estimated $1.5 million, or approximately $0.01 per diluted share, for 2005, and an estimated $4.2 million, or approximately $0.04 per diluted share, for 2004.
The Company recorded the following incentive compensation expense in continuing operations for the periods indicated below:
|
|
Year Ended December 31, |
|
|||||||
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(millions) |
|
|||||||
Short-term incentive compensation expense |
|
$ |
16.7 |
|
$ |
12.9 |
|
$ |
13.7 |
|
Long-term incentive compensation expense |
|
26.6 |
|
46.4 |
|
28.3 |
|
|||
Total incentive compensation expense |
|
$ |
43.3 |
|
$ |
59.3 |
|
$ |
42.0 |
|
42
The long-term incentive compensation expenses are primarily associated with Executive Performance Incentive Programs (the Programs) that were instituted starting in 2002. The long-term incentive compensation expenses during 2006 were lower than during 2005 due to a greater number of unvested units outstanding during 2005 than during 2006, as there were two Programs in effect during 2005 and only one in 2006. The long-term incentive compensation expenses during 2005 were higher than during 2004 primarily due to a higher estimated share price for the Programs being expensed, as a result of the Companys share price appreciation, and a greater number of unvested units outstanding during 2005 than during 2004.
The Company currently estimates 2007 total incentive compensation expense of approximately $38 million.
Federal Legislation
During 2005, the Company completed its review of the American Jobs Creation Act of 2004s impact on the Companys executive compensation plans, and the Compensation Committee of the Companys Board of Directors decided to end the Companys deferred compensation programs for employees. As a result, in 2005 the Company recorded $15.3 million in tax benefit disallowances under Section 162(m) of the IRC, primarily due to the impairment of previously recorded deferred tax assets related to the employee deferred compensation programs and the 2003 Executive Performance Incentive Program.
Rate Regulation
The Companys distribution operations and pipeline operations are subject to various forms of regulation as previously discussed. Accounting for the Companys regulated operations is performed in accordance with the provisions of SFAS No. 71. As described in Notes 1 and 10 to the Consolidated Financial Statements, regulatory assets and liabilities are recorded to reflect future collections or payments through the regulatory process. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of the deferred costs.
Schedule of Contractual Obligations
The following table details the future projected payments associated with the Companys contractual obligations as of December 31, 2006.
|
|
Total |
|
2007 |
|
2008-2009 |
|
2010-2011 |
|
2012+ |
|
|||||
|
|
(Thousands) |
|
|||||||||||||
Long-term debt |
|
$ |
763,500 |
|
$ |
10,000 |
|
$ |
4,300 |
|
$ |
6,000 |
|
$ |
743,200 |
|
Interest expense |
|
497,705 |
|
44,663 |
|
88,526 |
|
87,860 |
|
276,656 |
|
|||||
Purchase obligations |
|
211,716 |
|
41,126 |
|
68,670 |
|
57,203 |
|
44,717 |
|
|||||
Operating leases |
|
55,964 |
|
6,767 |
|
10,273 |
|
6,108 |
|
32,816 |
|
|||||
Other long-term liabilities |
|
87,152 |
|
|
|
87,152 |
|
|
|
|
|
|||||
Total contractual obligations |
|
$ |
1,616,037 |
|
$ |
102,556 |
|
$ |
258,921 |
|
$ |
157,171 |
|
$ |
1,097,389 |
|
Included within the purchase obligations amount in the table above are annual commitments of approximately $37.8 million relating to the Companys natural gas distribution and production operations for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to ten years. Approximately $26.4 million of these costs are believed to be recoverable in customer rates.
Operating leases are primarily entered into for various office locations and warehouse buildings, as well as a limited amount of equipment. The relocation of the Company to a new corporate headquarters in 2005 resulted in the early termination of several operating leases for facilities deemed to have no economic benefit to the Company. These obligations, which totaled $6.6 million as of December 31, 2006, are included in operating lease obligations detailed above.
43
The other long-term liabilities line represents the total estimated payout for the 2005 Executive Performance Incentive Program. See section titled Critical Accounting Policies Involving Significant Estimates and Note 16 to the Consolidated Financial Statements for further discussion regarding factors that affect the ultimate amount of the payout of this obligation.
Contingent Liabilities and Commitments
The various regulatory authorities that oversee Equitables operations will, from time to time, make inquiries or investigations into the activities of the Company. It is the Companys policy to comply with applicable laws and cooperate when regulatory bodies make requests.
In June 2006, the West Virginia Supreme Court of Appeals issued a decision involving interpretation of certain types of oil and gas leases of an unrelated party, in which a class of royalty owners in the state of West Virginia filed a lawsuit claiming that the defendant in the case underpaid royalties by deducting certain post-production costs not permitted by such types of leases and not paying a fair value for the gas produced from the royalty owners leases. In January 2007, the jury in the aforementioned case returned a verdict in favor of the plaintiff royalty owners, awarding the plaintiffs significant compensatory and punitive damages for the alleged underpayment of royalties. While the defendant plans to appeal the verdict, this decision may ultimately impact other royalty interest rights in West Virginia. Claims have been brought against others in the oil and gas industry, including the Company. The actions against the Company are in the early stages of proceedings. The Company believes that the claims and facts decided in the unrelated lawsuit can be differentiated from those asserted against the Company. Nevertheless, the Company has reviewed its West Virginia royalty agreements and established a reserve it believes to be appropriate.
See Note 19 to the Consolidated Financial Statements for further discussion of the Companys contingent liabilities and commitments.
44
The Companys significant accounting policies are described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Form 10-K. The discussion and analysis of the Consolidated Financial Statements and results of operations are based upon Equitables Consolidated Financial Statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these Consolidated Financial Statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the related disclosure of contingent assets and liabilities. The following critical accounting policies, which were reviewed and approved by the Companys Audit Committee, relate to the Companys more significant judgments and estimates used in the preparation of its Consolidated Financial Statements. There can be no assurance that actual results will not differ from those estimates.
Provision for Doubtful Accounts: The Company encounters risks associated with the collection of its accounts receivable. Equitable Gass state regulated relationship with its customers is particularly complex. Equitable Gas records a monthly provision for accounts receivable that are considered to be uncollectible. In order to calculate the appropriate monthly provision, Equitable Gas primarily utilizes a historical rate of accounts receivable write-offs as a percentage of total revenue. This historical rate is applied to the current revenues on a monthly basis and is updated periodically based on events that may change the rate, such as a significant increase or decrease in commodity prices or a significant change in the weather. Both of these items ultimately impact the customers ability to pay and the rates that are charged to the customers due to the pass-through of purchased gas costs to the customers. Management reviews the adequacy of the allowance on a quarterly basis using the assumptions that apply at that time.
The monthly provision for uncollectible accounts amounted to approximately 1% and 2% of residential sales for 2006 and 2005, respectively. Beginning in April 2004, the Company began collecting a regulatory surcharge in the amount of $0.30 per Mcfe of gas sold to residential customers to help recover the costs associated with providing gas service to low-income customers. This surcharge is credited to the reserve for uncollectible accounts and reduces the amount which would otherwise be recognized as bad debt expense. This surcharge totaled $5.5 million in 2006, $6.5 million in 2005, and $3.3 million in 2004. In addition, during 2004, Equitable Gas implemented a new customer information and billing system that has enabled the Company to better segment customer information in order to identify customers who may have difficulty paying. Also, under the Responsible Utility Customer Protection Act, Equitable Gas is permitted to send winter termination notices to customers whose household income exceeds 250% of the federal poverty level and to complete customer terminations without approval from the PA PUC. The Company took advantage of these winter terminations in an effort to reduce its uncollectible accounts receivable.
The Company believes that the accounting estimates related to the allowance for doubtful accounts are critical accounting estimates because the underlying assumptions used for the allowance can change from period to period and the changes in the allowance could potentially cause a material impact to the income statement and working capital. The actual weather, commodity prices and other internal and external economic conditions, such as the mix of the customer base between residential, commercial and industrial, may vary significantly from managements assumptions and may impact the ultimate collectibility of customer accounts. Additionally, the regulatory environment allows certain customers to enter into long-term payment arrangements, the ultimate collectibility of which is difficult to determine.
Executive Performance Incentive Programs: The Company treats its Executive Performance Incentive Programs as variable plans. The actual cost to be recorded for the 2005 Executive Performance Incentive Program (2005 Program) will not be known until the measurement date, which is December 31, 2008, requiring the Company to estimate the total expense to be recognized. The number of units to be paid out under the 2005 Program is dependent upon a combination of a level of total shareholder return relative to the performance of a peer group and the Companys average absolute return on capital during the four-year performance period. The Company reviews these assumptions on a quarterly basis and adjusts its accrual for the 2005 Program when changes in these assumptions result in a material change in the value of the ultimate payout. In the current period, the Company estimated that the performance measures would be met at 175% of the full value of the units for the 2005 Program and that the estimated end of 2008 share price would be $45.00.
45
The Company believes that the accounting estimate related to the 2005 Program is a critical accounting estimate because it is likely to change from period to period based on the market price of the Companys shares and the performance of the peer group. Additionally, the impact on net income of these changes could be material. Managements assumptions about future stock price and Company performance relative to the peer group requires significant judgment. Each companys inherent volatility combined with the volatility in commodity prices impact the ultimate amount of the payout and make it difficult to provide sensitivity metrics to demonstrate what impact a change in the Companys stock price will have on the estimate. However, assuming no change in the attainment of performance measures, a 10% increase in the Companys stock price assumptions for December 31, 2008 would result in an increase in 2007 compensation expense under the 2005 Program of approximately $6 million. A 10% decrease in the Companys stock price assumptions would result in a decrease in 2007 compensation expense of the same amount.
Income Taxes: The Company accounts for income taxes under the provisions of SFAS No. 109, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the Companys Consolidated Financial Statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. See Note 6 to the Companys Consolidated Financial Statements for further discussion.
The Company has recorded deferred tax assets principally resulting from mark-to-market hedging losses recorded in other comprehensive loss, deferred revenues and expenses and state net operating loss carryforwards. The Company has established a valuation allowance against a portion of the deferred tax assets related to the state net operating loss carryforwards, as it is believed that it is more likely than not that these deferred tax assets will not all be realized. The Company also recorded a $0.1 million charge in 2006 and a $15.3 million charge in 2005 related to compensation deferred and accrued under certain executive compensation plans, as it was determined that this compensation will not be deductible under Section 162(m) of the IRC. No other valuation allowances have been established, as it is believed that future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize these assets. Any change in the valuation allowance would impact the Companys income tax expense and net income in the period in which such a determination is made.
The Company believes that the accounting estimate related to income taxes is a critical accounting estimate because the Company must assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that it is believed to be more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, a valuation allowance must be established. Significant management judgment is required in determining any valuation allowance recorded against deferred tax assets. The Company considers all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about the Companys current financial position and results of operations for the current and preceding years, as well as all currently available information about future years, including the Companys anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies available to the Company. To the extent that a valuation allowance is established or increased or decreased during a period, the Company must include an expense or benefit within tax expense in the income statement.
Contingencies : The Company is involved in various regulatory and legal proceedings that arise in the ordinary course of business. The Company records a liability for contingencies based upon its assessment that a loss is probable and the amount of the loss can be reasonably estimated. The recording of contingencies is guided by the principles of SFAS No. 5. The Company considers many factors in making these assessments, including history and specifics of each matter. Estimates are developed in consultation with legal counsel and are based upon an analysis of potential results.
The Company believes that the accounting estimate related to contingencies is a critical accounting estimate because future results of operations for any particular quarterly or annual period could be materially affected by changes in the Companys assumptions.
46
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Derivative Commodity Instruments
The Companys primary market risk exposure is the volatility of future prices for natural gas, which can affect the operating results of the Company primarily through the Equitable Supply segment and the unregulated marketing group within the Equitable Utilities segment. The Companys use of derivatives to reduce the effect of this volatility is described in Notes 1 and 3 to the Consolidated Financial Statements and under the caption Commodity Risk Management in Managements Discussion and Analysis of Financial Condition and Results of Operations (Item 7) of this Form 10-K. The Company uses non-leveraged derivative commodity instruments that are placed with major financial institutions whose creditworthiness is continually monitored. The Company also enters into energy trading contracts to leverage its assets and limit its exposure to shifts in market prices. The Companys use of these derivative financial instruments is implemented under a set of policies approved by the Companys Corporate Risk Committee and Board of Directors.
Commodity Price Risk
The following sensitivity analysis estimates the potential effect on fair value or future earnings from derivative commodity instruments due to a 10% increase and a 10% decrease in commodity prices.
For the derivative commodity instruments used to hedge the Companys forecasted production, the Company sets policy limits relative to the expected production and sales levels, which are exposed to price risk. The financial instruments currently utilized by the Company include futures contracts, swap agreements and collar agreements, which may require payments to or receipt of payments from counterparties based on the differential between a fixed and variable price for the commodity. The Company also considers options and other contractual agreements in determining its commodity hedging strategy. Management monitors price and production levels on a continuous basis and will make adjustments to quantities hedged as warranted. In general, the Companys strategy is to hedge production at prices considered to be favorable to the Company. The Company attempts to take advantage of price fluctuations by hedging more aggressively when market prices move above historical averages and by taking more price risk when prices are significantly below these levels. The goal of these actions is to earn a return above the cost of capital and to lower the cost of capital by reducing cash flow volatility. To the extent that the Company has hedged its production at prices below the current market price, the Company is unable to benefit fully from increases in the price of natural gas.
With respect to the derivative commodity instruments held by the Company for purposes other than trading as of December 31, 2006, the Company hedged portions of expected equity production through 2013 by utilizing futures contracts, swap agreements and collar agreements covering approximately 310.1 Bcf of natural gas. See the Commodity Risk Management and Capital Resources and Liquidity sections of Managements Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K for further discussion. For the sensitivity analysis set forth below, the Company determined the change in the fair value of the derivative commodity instruments using a model similar to its normal change in fair value as described in Note 1 to the consolidated financial statements. The Company assumed a 10% change in the price of natural gas from its levels at December 31, 2006. The price change was then applied to the derivative commodity instruments recorded on the Companys balance sheet, resulting in the change in fair value.
A hypothetical decrease of 10% in the market price of natural gas from the December 31, 2006 levels would increase the fair value of non-trading natural gas derivative instruments by approximately $222.3 million. A hypothetical increase of 10% in the market price of natural gas from the December 31, 2006 levels would decrease the fair value of non-trading natural gas derivative instruments by approximately $221.8 million.
The above analysis of the derivative commodity instruments held by the Company for purposes other than trading does not include the offsetting impact that the same hypothetical price movement may have on the Company and its subsidiaries physical sales of natural gas. The portfolio of derivative commodity instruments held for risk management purposes approximates the notional quantity of a portion of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the derivative commodity instrument portfolio is managed to complement the physical transaction portfolio, reducing overall risks
47
within limits. Therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held for risk management purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions, assuming the derivative commodity instruments are not closed out in advance of their expected term, the derivative commodity instruments continue to function effectively as hedges of the underlying risk and the anticipated transactions occur as expected.
If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur, or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.
For derivative commodity instruments held for trading purposes, the Company engages in financial transactions also subject to policies that limit the net positions to specific value at risk limits. The financial instruments currently utilized by the Company for trading purposes include forward contracts and swap agreements.
A hypothetical increase or decrease of 10% in the market price of natural gas from the December 31, 2006 levels would not have a significant impact on the fair value of derivative commodity instruments held by the Company for trading purposes as of December 31, 2006.
Other Market Risks
The Company has variable rate short-term debt. As such, there is some exposure to future earnings due to changes in interest rates. A 100 basis point increase or decrease in interest rates would not have a significant impact on future earnings of the Company under its current capital structure. The Company maintains fixed rate long-term debt that is not subject to risk exposure from fluctuating interest rates.
The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. The Company believes that NYMEX-traded futures contracts have minimal credit risk because futures exchanges are the counterparties. The Company manages the credit risk of the other derivative contracts by limiting dealings to those counterparties who meet the Companys criteria for credit and liquidity strength.
48
Item 8. Financial Statements and Supplementary Data
|
|
|
|
|
|
Statements of Consolidated Income for each of the three years in the period ended December 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheets as of December 31, 2006 and 2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
49
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUTING FIRM
The Board of Directors and Shareholders
Equitable Resources, Inc.
We have audited the accompanying consolidated balance sheets of Equitable Resources, Inc. and Subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, common stockholders equity and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Equitable Resources, Inc. and Subsidiaries at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, in 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Equitable Resources, Inc.s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2007, expressed an unqualified opinion thereon.
Pittsburgh, Pennsylvania
February 19, 2007
50
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUTING FIRM
The Board of Directors and Shareholders
Equitable Resources, Inc.
We have audited managements assessment, included in Managements Report on Internal Control over Financial Reporting and appearing in the accompanying Item 9A Controls and Procedures, that Equitable Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Equitable Resources, Inc.s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on managements assessment and an opinion on the effectiveness of the companys internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating managements assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys 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 companys internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys 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.
In our opinion, managements assessment that Equitable Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Equitable Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Equitable Resources, Inc. and Subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, common stockholders equity and cash flows for each of the three years in the period ended December 31, 2006 and our report dated February 19, 2007 expressed an unqualified opinion thereon.
Pittsburgh, Pennsylvania
February 19, 2007
51
EQUITABLE RESOURCES, INC. AND SUBSIDIRIES
STATEMENTS OF CONSOLIDATED INCOME
YEAR ENDED DECEMBER 31,
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands except per share amounts) |
|
|||||||
|
|
|
|
|
|
|
|
|||
Operating revenues |
|
$ |
1,267,910 |
|
$ |
1,253,724 |
|
$ |
1,045,183 |
|
Cost of sales |
|
504,329 |
|
511,169 |
|
412,050 |
|
|||
Net operating revenues (see Note 1) |
|
763,581 |
|
742,555 |
|
633,133 |
|
|||
Operating expenses: |
|
|
|
|
|
|
|
|||
Operation and maintenance |
|
104,620 |
|
95,369 |
|
87,988 |
|
|||
Production |
|
63,273 |
|
61,483 |
|
43,274 |
|
|||
Selling, general and administrative |
|
125,951 |
|
140,529 |
|
130,090 |
|
|||
Office consolidation impairment charges |
|
(2,908 |
) |
7,835 |
|
|
|
|||
Depreciation, depletion and amortization |
|
100,122 |
|
93,527 |
|
82,076 |
|
|||
Total operating expenses (see Note 1) |
|
391,058 |
|
398,743 |
|
343,428 |
|
|||
Operating income |
|
372,523 |
|
343,812 |
|
289,705 |
|
|||
Gain on sale of available-for-sale securities, net |
|
|
|
110,280 |
|
3,024 |
|
|||
Gain on exchange of Westport for Kerr-McGee shares |
|
|
|
|
|
217,212 |
|
|||
Charitable foundation contribution |
|
|
|
|
|
(18,226 |
) |
|||
Equity in earnings of nonconsolidated investments |
|
260 |
|
762 |
|
856 |
|
|||
Other income, net |
|
|
|
1,195 |
|
3,692 |
|
|||
Interest expense |
|
47,052 |
|
44,437 |
|
42,520 |
|
|||
Income from continuing operations before income taxes |
|
325,731 |
|
411,612 |
|
453,743 |
|
|||
Income taxes |
|
109,706 |
|
153,038 |
|
154,953 |
|
|||
Income from continuing operations |
|
216,025 |
|
258,574 |
|
298,790 |
|
|||
Income (loss) from discontinued operations, net of tax (benefit) provision of ($3,246), $10,485, and ($12,259) for the years ended December 31, 2006, 2005 and 2004, respectively |
|
4,261 |
|
1,481 |
|
(18,936 |
) |
|||
Net income |
|
$ |
220,286 |
|
$ |
260,055 |
|
$ |
279,854 |
|
Earnings per share of common stock: |
|
|
|
|
|
|
|
|||
Basic: |
|
|
|
|
|
|
|
|||
Income from continuing operations |
|
$ |
1.79 |
|
$ |
2.14 |
|
$ |
2.42 |
|
Income (loss) from discontinued operations |
|
0.04 |
|
0.01 |
|
(0.15 |
) |
|||
Net income |
|
$ |
1.83 |
|
$ |
2.15 |
|
$ |
2.27 |
|
Diluted: |
|
|
|
|
|
|
|
|||
Income from continuing operations |
|
$ |
1.77 |
|
$ |
2.09 |
|
$ |
2.37 |
|
Income (loss) from discontinued operations |
|
0.03 |
|
0.01 |
|
(0.15 |
) |
|||
Net income |
|
$ |
1.80 |
|
$ |
2.10 |
|
$ |
2.22 |
|
See notes to consolidated financial statements.
52
EQUITABLE RESOURCES, INC. AND SUBSIDIRIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
YEARS ENDED DECEMBER 31,
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|||
Net income |
|
$ |
220,286 |
|
$ |
260,055 |
|
$ |
279,854 |
|
Adjustments to reconcile net income to net cash provided by (used in) operating activities: |
|
|
|
|
|
|
|
|||
(Income) loss from discontinued operations, net of tax |
|
(4,261 |
) |
(1,481 |
) |
18,936 |
|
|||
Provision for losses on accounts receivable |
|
4,715 |
|
8,273 |
|
19,659 |
|
|||
Depreciation, depletion and amortization |
|
100,122 |
|
93,527 |
|
82,076 |
|
|||
Office consolidation impairment charges |
|
(2,908 |
) |
7,835 |
|
|
|
|||
Deferred income taxes |
|
31,267 |
|
(92,912 |
) |
113,437 |
|
|||
Excess tax benefits from share-based payment arrangements |
|
(15,739 |
) |
|
|
|
|
|||
Gain on sale of available-for-sale securities, net |
|
|
|
(110,280 |
) |
(3,024 |
) |
|||
Gain on exchange of Westport for Kerr-McGee shares |
|
|
|
|
|
(217,212 |
) |
|||
Charitable foundation contribution |
|
|
|
|
|
18,226 |
|
|||
Recognition of prepaid forward production revenue |
|
|
|
|
|
(10,363 |
) |
|||
Amendment of prepaid forward contract, net |
|
|
|
|
|
(31,260 |
) |
|||
Changes in other assets and liabilities: |
|
|
|
|
|
|
|
|||
Accounts receivable and unbilled revenues |
|
63,527 |
|
(78,049 |
) |
(69,024 |
) |
|||
Margin deposits |
|
317,821 |
|
(280,935 |
) |
(32,463 |
) |
|||
Inventory |
|
20,793 |
|
(85,296 |
) |
(45,420 |
) |
|||
Prepaid expenses and other |
|
(1,791 |
) |
(27,564 |
) |
(16,360 |
) |
|||
Regulatory assets |
|
1,146 |
|
(2,847 |
) |
506 |
|
|||
Accounts payable |
|
(29,292 |
) |
71,451 |
|
43,544 |
|
|||
Derivative instruments, at fair value |
|
(53,846 |
) |
(40,962 |
) |
994 |
|
|||
Deferred income taxes |
|
33,375 |
|
(32,288 |
) |
34,111 |
|
|||
Pension contributions and settlements |
|
(1,751 |
) |
(20,364 |
) |
|
|
|||
Other assets |
|
6,960 |
|
(20,950 |
) |
(746 |
) |
|||
Other current liabilities |
|
(57,222 |
) |
83,059 |
|
28,198 |
|
|||
Other credits |
|
(13,914 |
) |
8,257 |
|
17,455 |
|
|||
Net cash provided by (used in) continuing operating activities |
|
619,288 |
|
(261,471 |
) |
231,124 |
|
|||
Net cash used in discontinued operating activities |
|
|
|
(50,491 |
) |
(51,126 |
) |
|||
Net cash provided by (used in) operating activities. |
|
619,288 |
|
(311,962 |
) |
179,998 |
|
|||
Cash flows from investing activities: |
|
|
|
|
|
|
|
|||
Capital expenditures |
|
(404,536 |
) |
(275,798 |
) |
(201,813 |
) |
|||
Purchase of interest in Eastern Seven Partners, L.P. |
|
|
|
(57,500 |
) |
|
|
|||
Investment in available-for-sale securities |
|
(2,471 |
) |
(4,009 |
) |
|
|
|||
Proceeds from sale of discontinued operations, net of purchase price adjustments |
|
(724 |
) |
80,000 |
|
|
|
|||
Proceeds from sale of Kerr-McGee shares |
|
|
|
460,467 |
|
42,880 |
|
|||
Proceeds from sale of properties |
|
|
|
141,991 |
|
|
|
|||
Net cash (used in) provided by continuing investing activities |
|
(407,731 |
) |
345,151 |
|
(158,933 |
) |
|||
Net cash provided by discontinued investing activities |
|
|
|
2,595 |
|
439 |
|
|||
Net cash (used in) provided by investing activities |
|
(407,731 |
) |
347,746 |
|
(158,494 |
) |
|||
Cash flows from financing activities: |
|
|
|
|
|
|
|
|||
Dividends paid |
|
(104,871 |
) |
(99,737 |
) |
(89,364 |
) |
|||
Purchase of treasury stock |
|
|
|
(122,250 |
) |
(118,472 |
) |
|||
Proceeds from exercises under employee compensation plans |
|
34,910 |
|
25,016 |
|
26,776 |
|
|||
Excess tax benefits from share-based payment arrangements |
|
15,739 |
|
|
|
|
|
|||
Repayments and retirements of long-term debt |
|
(3,000 |
) |
(10,000 |
) |
(20,500 |
) |
|||
Proceeds from issuance of long-term debt |
|
|
|
150,000 |
|
|
|
|||
(Decrease) increase in short-term loans |
|
(229,301 |
) |
69,801 |
|
95,899 |
|
|||
Net cash (used in) provided by continuing financing activities |
|
(286,523 |
) |
12,830 |
|
(105,661 |
) |
|||
Net cash provided by discontinued financing activities |
|
|
|
26,352 |
|
49,863 |
|
|||
Net cash (used in) provided by financing activities |
|
(286,523 |
) |
39,182 |
|
(55,798 |
) |
|||
Net (decrease) increase in cash and cash equivalents |
|
(74,966 |
) |
74,966 |
|
(34,294 |
) |
|||
Cash and cash equivalents at beginning of year |
|
74,966 |
|
|
|
34,294 |
|
|||
Cash and cash equivalents at end of year |
|
$ |
|
|
$ |
74,966 |
|
$ |
|
|
Cash paid during the year for: |
|
|
|
|
|
|
|
|||
Interest (net of amount capitalized) |
|
$ |
47,260 |
|
$ |
49,085 |
|
$ |
49,656 |
|
Income taxes |
|
$ |
58,631 |
|
$ |
251,486 |
|
$ |
23,043 |
|
See notes to consolidated financial statements.
53
EQUITABLE RESOURCES, INC. AND SUBSIDIRIES
CONSOLIDATED BALANCE SHEETS ENDED
DECEMBER 31,
|
|
2006 |
|
2005 |
|
||
|
|
(Thousands) |
|
||||
Assets |
|
|
|
|
|
||
Current assets: |
|
|
|
|
|
||
Cash and cash equivalents |
|
$ |
|
|
$ |
74,966 |
|
Accounts receivable (less accumulated provision for doubtful accounts: 2006, $20,442; 2005, $23,329) |
|
199,486 |
|
249,397 |
|
||
Unbilled revenues |
|
40,627 |
|
58,958 |
|
||
Margin deposits with financial institutions |
|
11 |
|
317,832 |
|
||
Inventory |
|
269,128 |
|
289,921 |
|
||
Derivative instruments, at fair value |
|
129,675 |
|
42,899 |
|
||
Prepaid expenses and other |
|
62,523 |
|
60,732 |
|
||
Assets held for sale from discontinued operations |
|
|
|
2,518 |
|
||
Total current assets |
|
701,450 |
|
1,097,223 |
|
||
Equity in nonconsolidated investment |
|
35,023 |
|
35,555 |
|
||
Property, plant and equipment: |
|
|
|
|
|
||
Equitable Utilities |
|
1,215,177 |
|
1,155,946 |
|
||
Equitable Supply |
|
2,402,120 |
|
2,080,151 |
|
||
Total property, plant and equipment |
|
3,617,297 |
|
3,236,097 |
|
||
Less: accumulated depreciation and depletion |
|
1,239,826 |
|
1,152,892 |
|
||
Net property, plant and equipment |
|
2,377,471 |
|
2,083,205 |
|
||
Investments, available-for-sale |
|
31,270 |
|
25,194 |
|
||
Other assets: |
|
|
|
|
|
||
Regulatory assets |
|
78,719 |
|
70,055 |
|
||
Other |
|
32,978 |
|
31,053 |
|
||
Total other assets |
|
111,697 |
|
101,108 |
|
||
Total assets |
|
$ |
3,256,911 |
|
$ |
3,342,285 |
|
See notes to consolidated financial statements.
54
EQUITABLE
RESOURCES, INC. AND SUBSIDIRIES
CONSOLIDATED BALANCE SHEETS ENDED
DECEMBER 31,
|
|
2006 |
|
2005 |
|
||
|
|
(Thousands) |
|
||||
Liabilities and Common Stockholders Equity |
|
|
|
|
|
||
Current liabilities: |
|
|
|
|
|
||
Current portion of long-term debt |
|
$ |
10,000 |
|
$ |
3,000 |
|
Short-term loans |
|
135,999 |
|
365,300 |
|
||
Accounts payable |
|
213,326 |
|
242,618 |
|
||
Derivative instruments, at fair value |
|
570,251 |
|
1,264,204 |
|
||
Other current liabilities |
|
150,203 |
|
217,374 |
|
||
Total current liabilities |
|
1,079,779 |
|
2,092,496 |
|
||
Debentures and medium-term notes |
|
753,500 |
|
763,500 |
|
||
Deferred and other credits: |
|
|
|
|
|
||
Deferred income taxes and investment tax credits |
|
338,012 |
|
24,042 |
|
||
Pension and other post-retirement benefits |
|
50,947 |
|
20,870 |
|
||
Other credits |
|
88,393 |
|
86,909 |
|
||
Common stockholders equity: |
|
|
|
|
|
||
Common stock, no par value, authorized 320,000 shares; shares issued: 2006 and 2005, 149,008 |
|
366,856 |
|
358,684 |
|
||
Treasury stock, shares at cost: 2006, 27,405; 2005, 29,102; (net of shares and cost held in trust for deferred compensation of 159, $2,724 and 142, $2,429) |
|
(469,584 |
) |
(496,511 |
) |
||
Retained earnings |
|
1,363,310 |
|
1,247,895 |
|
||
Accumulated other comprehensive loss |
|
(314,302 |
) |
(755,600 |
) |
||
Total common stockholders equity |
|
946,280 |
|
354,468 |
|
||
Total liabilities and common stockholders equity |
|
$ |
3,256,911 |
|
$ |
3,342,285 |
|
See notes to consolidated financial statements.
55
EQUITABLE RESOURCES, INC. AND SUBSIDIRIES
STATEMENTS OF COMMON STOCKHOLDERS EQUITY
YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
|
|
Common Stock |
|
|
|
Accumulated
|
|
Common |
|
||||||
|
|
Shares
|
|
No
|
|
Retained
|
|
Comprehensive
|
|
Stockholders
|
|
||||
|
|
(Thousands) |
|
||||||||||||
Balance, December 31, 2003 |
|
124,732 |
|
$ |
52,988 |
|
$ |
897,087 |
|
$ |
15,265 |
|
$ |
965,340 |
|
Comprehensive income (net of tax): |
|
|
|
|
|
|
|
|
|
|
|
||||
Net income |
|
|
|
|
|
279,854 |
|
|
|
279,854 |
|
||||
Net change in cash flow hedges: Natural gas, net of tax benefit of $82,277 (see Note 3) |
|
|
|
|
|
|
|
(138,926) |
|
(138,926) |
|
||||
Interest rate |
|
|
|
|
|
|
|
397 |
|
397 |
|
||||
Gain on exchange of Westport stock |
|
|
|
|
|
|
|
(143,360 |
) |
(143,360 |
) |
||||
Unrealized gain on available-for-sale securities: Westport (to date of merger) |
|
|
|
|
|
|
|
43,731 |
|
43,731 |
|
||||
Kerr-McGee (from date of merger) |
|
|
|
|
|
|
|
36,334 |
|
36,334 |
|
||||
Other |
|
|
|
|
|
|
|
371 |
|
371 |
|
||||
Minimum pension liability adjustment, net of tax benefit of $3,009 |
|
|
|
|
|
|
|
5,841 |
|
5,841 |
|
||||
Total comprehensive income |
|
|
|
|
|
|
|
|
|
84,242 |
|
||||
Dividends ($0.720 per share) |
|
|
|
|
|
(89,364 |
) |
|
|
(89,364 |
) |
||||
Stock-based compensation plans, net |
|
2,030 |
|
32,926 |
|
|
|
|
|
32,926 |
|
||||
Stock repurchases |
|
(4,700 |
) |
(118,472 |
) |
|
|
|
|
(118,472 |
) |
||||
Balance, December 31, 2004 |
|
122,062 |
|
(32,558 |
) |
1,087,577 |
|
(180,347 |
) |
874,672 |
|
||||
Comprehensive income (net of tax): |
|
|
|
|
|
|
|
|
|
|
|
||||
Net income |
|
|
|
|
|
260,055 |
|
|
|
260,055 |
|
||||
Net change in cash flow hedges: Natural gas, net of tax benefit of $324,817 (see Note 3) |
|
|
|
|
|
|
|
(543,716 |
) |
(543,716 |
) |
||||
Interest rate |
|
|
|
|
|
|
|
97 |
|
97 |
|
||||
Unrealized gain on available-for-sale securities: Kerr-McGee |
|
|
|
|
|
|
|
(36,334 |
) |
(36,334 |
) |
||||
Other |
|
|
|
|
|
|
|
375 |
|
375 |
|
||||
Minimum pension liability adjustment, net of tax benefit of $211 |
|
|
|
|
|
|
|
4,325 |
|
4,325 |
|
||||
Total comprehensive loss |
|
|
|
|
|
|
|
|
|
(315,198 |
) |
||||
Dividends ($0.820 per share) |
|
|
|
|
|
(99,737 |
) |
|
|
(99,737 |
) |
||||
Stock-based compensation plans, net |
|
1,412 |
|
16,981 |
|
|
|
|
|
16,981 |
|
||||
Stock repurchases |
|
(3,568 |
) |
(122,250 |
) |
|
|
|
|
(122,250 |
) |
||||
Balance, December 31, 2005 |
|
119,906 |
|
(137,827 |
) |
1,247,895 |
|
(755,600 |
) |
354,468 |
|
||||
Comprehensive income (net of tax): |
|
|
|
|
|
|
|
|
|
|
|
||||
Net income |
|
|
|
|
|
220,286 |
|
|
|
220,286 |
|
||||
Net change in cash flow hedges: Natural gas, net of tax of $272,066 (see Note 3) |
|
|
|
|
|
|
|
454,817 |
|
454,817 |
|
||||
Interest rate |
|
|
|
|
|
|
|
116 |
|
116 |
|
||||
Unrealized gain on available-for-sale securities |
|
|
|
|
|
|
|
2,399 |
|
2,399 |
|
||||
Pension and other post-retirement benefits liability adjustment prior to the adoption of SFAS No. 158, net of tax benefit of $730 |
|
|
|
|
|
|
|
(1,024 |
) |
(1,024 |
) |
||||
Total comprehensive income |
|
|
|
|
|
|
|
|
|
676,594 |
|
||||
Pension and other post-retirement benefits liability adjustment due to the adoption of SFAS No. 158, net of tax benefit of $9,988 |
|
|
|
|
|
|
|
(15,010 |
) |
(15,010 |
) |
||||
Dividends ($0.87 per share) |
|
|
|
|
|
(104,871 |
) |
|
|
(104,871 |
) |
||||
Stock-based compensation plans, net |
|
1,697 |
|
35,099 |
|
|
|
|
|
35,099 |
|
||||
Balance, December 31, 2006 |
|
121,603 |
|
$ |
(102,728 |
) |
$ |
1,363,310 |
|
$ |
(314,302 |
) |
$ |
946,280 |
|
Common shares authorized: 320,000,000 shares. Preferred shares authorized: 3,000,000 shares. There are no preferred shares issued or outstanding.
See notes to consolidated financial statements.
56
EQUITABLE RESOURCES, INC. AND SUBSIDIRIES
DECEMBER 31
, 2006
1. Summary of Significant Accounting Policies
Principles of Consolidation: The Consolidated Financial Statements include the accounts of Equitable Resources, Inc. and all subsidiaries, ventures and partnerships in which a controlling equity interest is held (Equitable or the Company). All significant intercompany accounts and transactions have been eliminated in consolidation. Equitable utilizes the equity method of accounting for companies where its ownership is less than or equal to 50% and significant influence exists.
Reclassification: The Consolidated Financial Statements and related footnote disclosures have been reclassified to reflect the operating results of the NORESCO segment as discontinued operations for all periods presented. See Note 7 for further information. Additionally, c ertain previously reported amounts have been reclassified to conform to the current year presentation.
Stock Split: On September 1, 2005, the Company effected a two-for-one stock split payable to shareholders of record on August 12, 2005. All share and per share information has been retroactively adjusted to reflect the stock split.
Use of Estimates: The preparation of financial statements in conformity with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and accompanying notes. Actual results could differ from those estimates.
Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. These investments are accounted for at cost. Interest earned on cash equivalents is included as a reduction of interest expense.
Inventories: The Companys inventory balance consists of natural gas stored underground and materials and supplies recorded at the lower of average cost or market.
Property, Plant and Equipment: The Companys property, plant and equipment consists of the following:
|
|
December 31, |
|
||||
|
|
2006 |
|
2005 |
|
||
|
|
(Thousands) |
|
||||
Utility plant |
|
$ |
1,207,311 |
|
$ |
1,148,063 |
|
Accumulated depreciation and amortization |
|
413,215 |
|
392,877 |
|
||
Net utility plant |
|
794,096 |
|
755,186 |
|
||
Oil and gas producing properties, successful efforts method |
|
1,752,222 |
|
1,551,677 |
|
||
Accumulated depletion |
|
566,118 |
|
518,426 |
|
||
Net oil and gas producing properties |
|
1,186,104 |
|
1,033,251 |
|
||
Other properties, at cost less accumulated depreciation |
|
397,271 |
|
294,768 |
|
||
Net property, plant and equipment |
|
$ |
2,377,471 |
|
$ |
2,083,205 |
|
Utility property, plant and equipment, principally regulated property, is carried at cost. Depreciation is recorded using composite rates on a straight-line basis. The overall rate of depreciation for the years ended December 31, 2006, and December 31, 2005, was approximately 4% of net Utility properties.
Oil and gas producing properties use the successful efforts method of accounting for production activities. Under this method, the cost of productive wells, including mineral interests, wells and related equipment, development dry holes, as well as productive acreage, are capitalized and depleted on the unit-of-production method. The depletion is calculated based on the annual actual production multiplied by the depletion rate per unit.
57
The depletion rate is derived by dividing the total costs capitalized over the number of units expected to be produced over the life of the reserves. Equitable Supply calculates a single depletion field including all reserves located in Kentucky, West Virginia, Virginia and Pennsylvania. Costs of exploratory dry holes, geological and geophysical, delay rentals and other property carrying costs are charged to expense. The majority of the Companys oil and gas producing properties consists of gas producing properties which were depleted at a rate of $0.62/Mcf and $0.59/Mcf produced for the years ended December 31, 2006, and December 31, 2005, respectively.
The carrying values of the Companys proved oil and gas properties are reviewed for indications of impairment whenever events or circumstances indicate that the remaining carrying value may not be recoverable. In order to determine whether impairment has occurred, the Company estimates the expected future cash flows (on an undiscounted basis) from its proved oil and gas properties and compares them to their respective carrying values. The estimated future cash flows used to test those properties for recoverability are based on proved reserves utilizing assumptions about the use of the asset and forward market prices for oil and gas. Proved oil and gas properties that have carrying amounts in excess of estimated future cash flows are deemed unrecoverable. Those properties are then written down to fair value, which is estimated using assumptions that marketplace participants would use in their estimates of fair value. In developing estimates of fair value, the Company used forward market prices. For the years ended December 31, 2006, 2005 and 2004, the Company did not recognize impairment charges on oil and gas properties.
Additionally, the costs of unproved oil and gas properties are periodically assessed. If unproved properties are determined to be productive, the related costs are transferred to proved oil and gas properties. If unproved properties are determined not to be productive, or if the value has been otherwise impaired, the excess carrying value is charged to expense. For additional information on oil and gas properties, see Note 24 (unaudited).
The Company also had $397.3 million and $294.8 million of other net property at December 31, 2006, and December 31, 2005, respectively. These items are carried at cost and depreciation is calculated using the straight-line method based on estimated service lives. This property consists largely of gathering systems (25 year estimated service life), buildings (35 year estimated service life), office equipment (3-7 year estimated service life), vehicles (5 year estimated service life), and computer and telecommunications equipment and systems (3-7 year estimated service life).
Major maintenance projects that do not increase the overall life of the related assets are expensed. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized.
Sales and Retirements Policies: No gain or loss is recognized on the partial sale of oil and gas reserves from the depletion pool unless non-recognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of the proceeds.
Regulatory Accounting: The Companys distribution operations are subject to comprehensive regulation by the PA PUC and the WV PSC. The Company also provides field line service, also referred to as farm tap service, in Kentucky which is subject only to rate regulation by the Kentucky Public Service Commission. The Companys interstate pipeline operations are subject to regulation by the FERC. Accounting for the Companys regulated operations is performed in accordance with the provisions of SFAS No. 71. The application of this accounting policy allows the Company to defer expenses and income on its Consolidated Balance Sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the Statements of Consolidated Income for a non-regulated company. The deferred regulatory assets and liabilities are then recognized in the Statements of Consolidated Income in the period in which the same amounts are reflected in rates.
Where permitted by regulatory authority under purchased natural gas adjustment clauses or similar tariff provisions, the Company defers the difference between its purchased natural gas cost, less refunds, and the billing of
58
such cost and amortizes the deferral over subsequent periods in which billings either recover or repay such amounts. Such amounts are reflected on the Companys Consolidated Balance Sheets as other current assets or liabilities.
When any portion of the Companys distribution or pipeline operations ceases to meet the criteria for application of regulatory accounting treatment for all or part of their operations, the regulatory assets and liabilities related to those portions are eliminated from the Consolidated Balance Sheets and are included in the Statements of Consolidated Income in the period in which the discontinuance of regulatory accounting treatment occurs.
The following table presents the total regulated net revenue and operating expenses of the Company:
|
|
Years Ended December 31, |
|
|||||||
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
Distribution revenues |
|
$ |
445,168 |
|
$ |
469,102 |
|
$ |
422,438 |
|
Pipeline revenues |
|
74,010 |
|
57,534 |
|
55,123 |
|
|||
Total regulated revenue |
|
519,178 |
|
526,636 |
|
477,561 |
|
|||
|
|
|
|
|
|
|
|
|||
Distribution purchased gas costs |
|
301,833 |
|
312,244 |
|
263,313 |
|
|||
Pipeline purchased gas costs |
|
1,424 |
|
3,767 |
|
|
|
|||
Total purchased gas costs |
|
303,257 |
|
316,011 |
|
263,313 |
|
|||
|
|
|
|
|
|
|
|
|||
Distribution net revenue |
|
143,335 |
|
156,858 |
|
159,125 |
|
|||
Pipeline net revenue |
|
72,586 |
|
53,767 |
|
55,123 |
|
|||
Total regulated net revenue |
|
215,921 |
|
210,625 |
|
214,248 |
|
|||
|
|
|
|
|
|
|
|
|||
Distribution operating expenses |
|
108,528 |
|
116,536 |
|
102,248 |
|
|||
Pipeline operating expenses |
|
39,346 |
|
36,422 |
|
30,467 |
|
|||
Total regulated operating expenses |
|
$ |
147,874 |
|
$ |
152,958 |
|
$ |
132,715 |
|
Derivative Instruments: Derivatives are held as part of a formally documented risk management program. The Companys risk management activities are subject to the management, direction and control of the Companys Corporate Risk Committee (CRC). The CRC reports to the Audit Committee of the Board of Directors and is comprised of the chief executive officer, the executive vice-president of finance and administration, the chief financial officer and other officers and employees.
The Companys risk management program includes the consideration and, when appropriate, the use of (i) exchange-traded natural gas futures contracts and options and OTC natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and for trading purposes and (ii) interest rate swap agreements to hedge exposures to fluctuations in interest rates. At contract inception, the Company designates its derivative instruments as hedging or trading activities.
All derivative instruments are accounted for in accordance with SFAS No. 133. As a result, the Company recognizes all derivative instruments as either assets or liabilities and measures the effectiveness of the hedges, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at fair value. If the gain (loss) for the hedging instrument is greater than the loss (gain) on the hedged item, hedge ineffectiveness is recorded. The measurement of fair value is based upon actively quoted market prices when available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based upon valuation methodologies deemed
59
appropriate by the Companys CRC. The Company assesses the effectiveness of hedging relationships both at the inception of the hedge and on an on-going basis.
The accounting for the changes in fair value of the Companys derivative instruments depends on the use of the derivative instruments. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income (loss), net of tax, and is subsequently reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The ineffective portion of the cash flow hedge is immediately recognized in operating revenues in the Statements of Consolidated Income. If a cash flow hedge is terminated before the settlement date of the hedged item, the amount of accumulated other comprehensive income (loss) recorded up to that date would remain accrued provided that the forecasted transaction remains probable of occurring, and going forward, the change in fair value of the derivative instrument would be recorded in earnings. The derivative instruments that comprise the amount recorded in accumulated other comprehensive income (loss) have been designated and qualify as cash flow hedges. The Company reports all gains and losses on its energy trading contracts net on its Statements of Consolidated Income in accordance with EITF No. 02-3.
Capitalized Interest: Interest costs for the construction of certain long-term assets are capitalized and amortized over the related assets estimated useful lives. Interest costs during 2006, 2005 and 2004 of $0.3 million, $0.2 million and $0.1 million, respectively, were capitalized as a portion of the cost of the related long-term assets.
Impairment of Long-Lived Assets: In accordance with SFAS No. 144, whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, the Company reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets undiscounted cash flows, the Company estimates an impairment loss by taking the difference between the carrying value and fair value of the assets.
Revenue Recognition: Sales of natural gas to utility customers are billed on a monthly cycle basis; however, the billing cycle periods for certain customers do not necessarily coincide with accounting periods used for financial reporting purposes. The Company follows the revenue accrual method of accounting for utility segment revenue whereby revenues applicable to gas delivered to customers but not yet billed under the cycle billing method are estimated and accrued and the related costs are charged to expense. Revenue is recognized for production activities when deliveries of natural gas, crude oil and natural gas liquids are made. Revenues from natural gas transportation and storage activities are recognized in the period service is provided. Revenues from energy marketing activities are recognized when deliveries occur. In accordance with EITF No. 02-3, only revenues associated with energy trading activities that do not result in physical delivery of an energy commodity (i.e. are settled in cash) are recorded using mark-to-market accounting. The revenues associated with the physical delivery of an energy commodity are recognized at contract value when delivered. Revenues associated with the Companys natural gas advance sales contracts are recognized as natural gas is gathered and delivered.
Investments : Investments in companies in which the Company has the ability to exert significant influence over operating and financial policies (generally 20% to 50% ownership) are accounted for using the equity method. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. These investments are classified as equity in nonconsolidated investments on the Consolidated Balance Sheets.
Other investments in equity securities which are generally under 20% ownership and where the Company does not exert significant influence over operating and financial polices are accounted for as available-for-sale in accordance with SFAS No. 115 and are classified as investments, available-for-sale on the Consolidated Balance Sheets. Available-for-sale securities are required to be carried at fair value, with any unrealized gains and losses reported on the Consolidated Balance Sheets within a separate component of equity, accumulated other
60
comprehensive income (loss). The Company utilizes the specific identification method to determine the cost of the securities sold.
APB No. 18 requires a company to recognize a loss in the value of an equity method investment that is other than a temporary decline. The Company analyzes its equity method investments based on its share of estimated future cash flows from the investment to determine whether the carrying amount will be recoverable. In accordance with SFAS No. 115, the Company continually reviews its available-for-sale investments to determine whether a decline in fair value below the cost basis is other than temporary. If the decline in fair value is judged to be other than temporary, the cost basis of the security is written down to fair value and the amount of the write-down is included in the Statements of Consolidated Income. No other than temporary decline in fair value was recorded in 2006, 2005 or 2004.
Income Taxes: The Company files a consolidated Federal income tax return and utilizes the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable, net of amounts refunded or estimated to be refunded, for the current year and the change in deferred taxes. Any refinements to prior years taxes made due to subsequent information are reflected as adjustments in the current period. Separate income taxes are calculated for income from continuing operations, discontinued operations, and items charged or credited directly to stockholders equity.
Deferred income tax assets and liabilities are determined based on temporary differences between the financial reporting and tax bases of assets and liabilities in accordance with SFAS No. 109 which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of such temporary differences. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. Where deferred tax liabilities will be passed through to customers in regulated rates, the Company establishes a corresponding regulatory asset for the increase in future revenues that will result when the temporary differences reverse.
Investment tax credits realized in prior years were deferred and are being amortized over the estimated service lives of the related properties where required by ratemaking rules.
Provision for Doubtful Accounts: Judgment is required to assess the ultimate realization of the Companys accounts receivable, including assessing the probability of collection and the credit-worthiness of certain customers. Reserves for uncollectible accounts are recorded as part of selling, general and administrative expense on the Statements of Consolidated Income. The reserves are based on historical experience, current and expected economic trends and specific information about customer accounts. Accordingly, actual results may differ from these estimates under different assumptions or conditions.
Earnings Per Share (EPS): Basic EPS is computed by dividing net income by the weighted average number of common shares outstanding during the period, without considering any dilutive items. Diluted EPS is computed by dividing net income adjusted for the assumed conversion of debt by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Purchases of treasury shares are calculated using the average share price for the Companys common stock during the period. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards. See Note 14 for a detailed calculation.
Asset Retirement Obligations : SFAS No. 143 requires that the fair value of the Companys plugging and abandonment obligations be recorded at the time the obligations are incurred, which is typically at the time the wells are drilled. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to depreciation, depletion, and amortization, and the initial capitalized costs are depleted over the useful lives of the related assets.
61
The following table presents a reconciliation of the beginning and ending carrying amounts of the Companys asset retirement obligations. The Company does not have any assets that are legally restricted for purposes of settling these obligations.
|
|
Year ended |
|
|
|
|
December 31, |
|
|
|
|
2006 |
|
|
|
|
(Thousands) |
|
|
Asset retirement obligation as of beginning of period |
|
$ |
46,126 |
|
Accretion expense |
|
3,134 |
|
|
Liabilities incurred |
|
619 |
|
|
Liabilities settled |
|
(1,359 |
) |
|
Asset retirement obligation as of end of period |
|
$ |
48,520 |
|
Self-Insurance: The Company is self-insured for certain losses related to workers compensation. The Company maintains stop loss coverage with third-party insurers to limit the total exposure for general liability, automobile liability, environmental liability and workers compensation. The recorded reserves represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are based on analyses of historical data and actuarial estimates and are not discounted. The liabilities are reviewed by management quarterly and by independent actuaries annually to ensure that they are appropriate. While the Company believes these estimates are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of claims or fluctuations in premiums, differ from estimates.
Recently Issued Accounting Standards:
Share-Based Compensation
The Company adopted SFAS No. 123R as of January 1, 2006. The Company previously accounted for share-based compensation transactions using the intrinsic value method of APB No. 25. Under SFAS No. 123R, an entity must recognize the compensation cost related to employee services received in exchange for all forms of share-based payments to employees, including employee stock options, as an expense in its income statement. The compensation cost of the award is generally measured based on the grant-date fair value of the award. See Note 16 for further discussion of the Companys accounting for share-based payments.
Employers Accounting for Defined Benefit Pension and Other Postretirement Plans
In September 2006, the FASB issued SFAS No. 158, which requires an employer to recognize a benefit plans funded status in its statement of financial position, measure a benefit plans assets and obligations as of the end of the employers fiscal year and recognize the changes in the benefit plans funded status in other comprehensive income in the year in which the changes occur. SFAS No. 158s requirement to recognize the funded status of a benefit plan and the new disclosure requirements were effective as of December 31, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employers fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. See Footnote 13 for information regarding the adoption of SFAS No. 158 as of December 31, 2006.
The Fair Value Option for Financial Assets and Financial Liabilities
In February 2007, the FASB issued SFAS No. 159, which provides entities with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This Statement is effective as of the beginning of the first fiscal year that begins after
62
November 15, 2007. The Company is currently evaluating the impact that SFAS No. 159 will have on its consolidated financial statements.
Fair Value Measurements
In September 2006, the FASB issued SFAS No. 157, which establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the impact that SFAS No. 157 will have on its consolidated financial statements.
Accounting for Uncertain Tax Positions
In June 2006, the FASB issued FIN 48, which applies to all open tax positions accounted for in accordance with SFAS No. 109. This Interpretation is intended to result in increased relevance and comparability in financial reporting of income taxes and to provide more information about the uncertainty in income tax assets and liabilities. This Interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact of this Interpretation and does not expect it to be material.
2. Financial Information by Business Segment
Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and are subject to evaluation by the Companys chief executive officer (chief operating decision maker) in deciding how to allocate resources. The Company reports its operations in two segments, which reflect its lines of business. The Equitable Utilities segments operations comprise the sale and transportation of natural gas to customers at state-regulated rates, interstate pipeline gathering, transportation and storage of natural gas subject to federal regulation, the unregulated marketing of natural gas and limited trading activities. The Equitable Supply segments activities comprise the development, production, gathering, marketing and sale of natural gas and a small amount of associated oil and the extraction and sale of natural gas liquids.
Operating segments are evaluated on their contribution to the Companys consolidated results based on operating income, equity in earnings of nonconsolidated investments, and other income, net. Interest expense and income taxes are managed on a consolidated basis. Headquarters costs are billed to the operating segments based upon a fixed allocation of the headquarters annual operating budget. Differences between budget and actual headquarters expenses are not allocated to the operating segments.
Substantially all of the Companys operating revenues, income from continuing operations and assets are generated or located in the United States.
63
|
|
Years Ended December 31, |
|
|||||||
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
Revenues from external customers: |
|
|
|
|
|
|
|
|||
Equitable Utilities |
|
$ |
843,164 |
|
$ |
846,457 |
|
$ |
731,861 |
|
Equitable Supply |
|
488,571 |
|
489,191 |
|
390,428 |
|
|||
Less: intersegment revenues (a) |
|
(63,825 |
) |
(81,924 |
) |
(77,106 |
) |
|||
Total |
|
$ |
1,267,910 |
|
$ |
1,253,724 |
|
$ |
1,045,183 |
|
Total operating expenses: |
|
|
|
|
|
|
|
|||
Equitable Utilities |
|
$ |
149,801 |
|
$ |
155,110 |
|
$ |
134,556 |
|
Equitable Supply |
|
219,407 |
|
195,610 |
|
163,059 |
|
|||
Unallocated expenses (b) |
|
21,850 |
|
48,023 |
|
45,813 |
|
|||
Total |
|
$ |
391,058 |
|
$ |
398,743 |
|
$ |
343,428 |
|
Operating income: |
|
|
|
|
|
|
|
|||
Equitable Utilities |
|
$ |
125,209 |
|
$ |
98,254 |
|
$ |
108,149 |
|
Equitable Supply |
|
269,164 |
|
293,581 |
|
227,369 |
|
|||
Unallocated expenses (b) |
|
(21,850 |
) |
(48,023 |
) |
(45,813 |
) |
|||
Total operating income |
|
$ |
372,523 |
|
$ |
343,812 |
|
$ |
289,705 |
|
|
|
Years Ended December 31, |
|
|||||||||
|
|
2006 |
|
2005 |
|
2004 |
|
|||||
|
|
(Thousands) |
|
|||||||||
Reconciliation of operating income to net income: |
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|||||
Equity in earnings of nonconsolidated investments: |
|
|
|
|
|
|
|
|||||
Equitable Supply |
|
$ |
129 |
|
$ |
493 |
|
$ |
688 |
|
||
Unallocated |
|
131 |
|
269 |
|
168 |
|
|||||
Total |
|
$ |
260 |
|
$ |
762 |
|
$ |
856 |
|
||
Other income, net: |
|
|
|
|
|
|
|
|||||
Equitable Supply |
|
$ |
|
|
$ |
|
|
$ |
576 |
|
||
Unallocated (c) |
|
|
|
1,195 |
|
3,116 |
|
|||||
Total |
|
$ |
|
|
$ |
1,195 |
|
$ |
3,692 |
|
||
|
|
|
|
|
|
|
|
|||||
Gain on sale of available-for-sale securities, net |
|
|
|
110,280 |
|
3,024 |
|
|||||
Gain on exchange of Westport for Kerr-McGee shares |
|
|
|
|
|
217,212 |
|
|||||
Charitable foundation contribution |
|
|
|
|
|
(18,226 |
) |
|||||
Interest expense |
|
47,052 |
|
44,437 |
|
42,520 |
|
|||||
Income taxes |
|
109,706 |
|
153,038 |
|
154,953 |
|
|||||
Income from continuing operations |
|
216,025 |
|
258,574 |
|
298,790 |
|
|||||
Income (loss) from discontinued operations |
|
4,261 |
|
1,481 |
|
(18,936 |
) |
|||||
Net income |
|
$ |
220,286 |
|
$ |
260,055 |
|
$ |
279,854 |
|
||
64
|
|
As of December 31, |
|
||||
|
|
2006 |
|
2005 |
|
||
|
|
(Thousands) |
|
||||
Segment assets: |
|
|
|
|
|
||
Equitable Utilities |
|
$ |
1,407,024 |
|
$ |
1,412,215 |
|
Equitable Supply |
|
1,794,485 |
|
1,844,883 |
|
||
Total operating segments |
|
3,201,509 |
|
3,257,098 |
|
||
Headquarters assets, including cash and short-term investments |
|
55,402 |
|
82,669 |
|
||
Total operating assets |
|
3,256,911 |
|
3,339,767 |
|
||
Assets held for sale from discontinued operations |
|
|
|
2,518 |
|
||
Total assets |
|
$ |
3,256,911 |
|
$ |
3,342,285 |
|
|
|
Years Ended December 31, |
|
|||||||
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
Significant noncash expense (income) items: |
|
|
|
|
|
|
|
|||
Equitable Utilities: |
|
|
|
|
|
|
|
|||
Increase in deferred purchased natural gas cost |
|
$ |
3,591 |
|
$ |
35,806 |
|
$ |
13,270 |
|
Increase (decrease) in regulatory asset valuation allowance |
|
24 |
|
(204 |
) |
6,004 |
|
|||
Impairment charges (d) |
|
(2,396 |
) |
3,841 |
|
|
|
|||
Equitable Supply: |
|
|
|
|
|
|
|
|||
Impairment charges (d) |
|
|
|
519 |
|
|
|
|||
Unallocated: |
|
|
|
|
|
|
|
|||
Impairment charges (d) |
|
(512 |
) |
3,475 |
|
|
|
|||
Total |
|
$ |
707 |
|
$ |
43,437 |
|
$ |
19,274 |
|
|
|
Years Ended December 31, |
|
|||||||
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
Depreciation, depletion and amortization: |
|
|
|
|
|
|
|
|||
Equitable Utilities |
|
$ |
28,731 |
|
$ |
27,874 |
|
$ |
25,629 |
|
Equitable Supply |
|
70,500 |
|
64,897 |
|
55,836 |
|
|||
Other |
|
891 |
|
756 |
|
611 |
|
|||
Total |
|
$ |
100,122 |
|
$ |
93,527 |
|
$ |
82,076 |
|
Expenditures for segment assets: |
|
|
|
|
|
|
|
|||
Equitable Utilities |
|
$ |
64,974 |
|
$ |
61,349 |
|
$ |
56,274 |
|
Equitable Supply (e) |
|
336,748 |
|
264,095 |
|
141,661 |
|
|||
Other |
|
2,814 |
|
7,854 |
|
3,878 |
|
|||
Total |
|
$ |
404,536 |
|
$ |
333,298 |
|
$ |
201,813 |
|
(a) Intersegment revenues primarily represent sales from Equitable Supply to the unregulated marketing affiliate of Equitable Utilities.
(b) Unallocated expenses consist primarily of certain performance-related incentive costs and administrative costs that are not allocated to the operating segments. For the year ended December 31, 2004, unallocated expenses also include $13.4 million related to the settlement of the cash balance portion of a defined benefit pension plan as more fully discussed in Note 13.
(c) Unallocated other income, net for the years ended December 31, 2005 and 2004 relates to pre-tax dividend income of $1.2 million and $3.1 million, respectively, for the Kerr-McGee Corporation shares held by the Company during those periods.
65
(d) The impairment charges for the years ended December 31, 2006 and 2005 relate to the consolidation of the Companys administrative operations in a building at the North Shore in Pittsburgh, Pennsylvania. See Note 21.
(e) Expenditures for segment assets for 2005 include $57.5 million for the acquisition of the 99% limited partnership interest in Eastern Seven Partners, L.P. See Note 5.
3. Derivative Instruments
Derivative Commodity Instruments
The various derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Companys forecasted sale of equity production and forecasted natural gas purchases and sales have been designated and qualify as cash flow hedges. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from counterparties based on the differential between a fixed and variable price for the commodity. Collar agreements require the counterparty to pay the Company if the index price falls below the floor price and the Company to pay the counterparty if the index price rises above the cap price. Exchange-traded instruments are generally settled with offsetting positions but may be settled by delivery or receipt of commodities. OTC arrangements require settlement in cash.
The fair value of these derivative commodity instruments is presented below:
|
|
As of December 31, |
|
||||
|
|
2006 |
|
2005 |
|
||
|
|
(Thousands) |
|
||||
Asset |
|
$ |
129,675 |
|
$ |
36,005 |
|
Liability |
|
(544,444 |
) |
(1,209,580 |
) |
||
Net liability |
|
$ |
(414,769 |
) |
$ |
(1,173,575 |
) |
These amounts are included in the Consolidated Balance Sheets as derivative instruments, at fair value. The net amount of derivative instruments, at fair value, changed between years primarily as a result of the decrease in natural gas prices. The absolute quantities of the Companys derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 392.6 Bcf and 383.5 Bcf as of December 31, 2006 and 2005, respectively, and are primarily related to natural gas swaps. The open positions at December 31, 2006 had maturities extending through December 2013.
The Company had deferred net losses of $286.2 million and $741.0 million in accumulated other comprehensive loss, net of tax, as of December 31, 2006 and 2005, respectively, associated with the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $89.1 million of net unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of December 31, 2006 will be recog nized in earnings during the next twelve months due to the physical settlement of hedged transactions. This recognition occurs through a reduction in the Companys net operating revenues resulting in the average hedged price becoming the realized sales price.
66
The net change in accumulated other comprehensive loss related to derivatives is presented below:
|
|
Years Ended December 31, |
|
|||||||
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
Net unrealized gain (loss) |
|
$ |
370,395 |
|
$ |
(690,893 |
) |
$ |
(182,504 |
) |
Net realized loss |
|
84,422 |
|
147,177 |
|
43,578 |
|
|||
Net gain (loss) |
|
$ |
454,817 |
|
$ |
(543,716 |
) |
$ |
(138,926 |
) |
|
|
|
|
|
|
|
|
For the years ended December 31, 2006, 2005 and 2004, ineffectiveness associated with the Companys derivative instruments designated as cash flow hedges increased (decreased) earnings by approximately $0.4 million, $(0.1) million and $(2.0) mil lion, respectively. These amounts are included in operating revenues in the Statements of Consolidated Income.
The Company conducts trading activities through its unregulated marketing group. The function of the Companys trading business is to contribute to the Companys earnings by taking market positions within defined limits subject to the Companys corporate risk management policy. At December 31, 2006, the absolute notional quantities of the futures and swaps held for trading purposes totaled 3.4 Bcf and 22.4 Bcf, respectively.
Below is a summary of the activity of the fair value of the Companys derivative commodity contracts with third parties held for trading purposes during the year ended December 31, 2006 (in thousands).
Fair value of contracts outstanding as of December 31, 2005 |
|
$ |
(330 |
) |
Contracts realized or otherwise settled |
|
137 |
|
|
Other changes in fair value |
|
774 |
|
|
Fair value of contracts outstanding as of December 31, 2006 |
|
$ |
581 |
|
There were no significant adjustments to the fair value of the Companys derivative contracts held for trading purposes relating to changes in valuation techniques and assumptions during the years ended December 31, 2006 and 2005.
The following table presents the maturities and the fair valuation source for the Companys derivative instruments that were held for trading purposes as of December 31, 2006.
Source of Fair Value |
|
Maturity
|
|
Maturity
|
|
Maturity
|
|
Maturity in
|
|
Total Fair
|
|
|||||
|
|
(Thousands) |
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Prices actively quoted (NYMEX) (1) |
|
$ |
396 |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
396 |
|
Prices provided by other external sources (2) |
|
173 |
|
12 |
|
|
|
|
|
185 |
|
|||||
Net derivative assets |
|
$ |
569 |
|
$ |
12 |
|
$ |
|
|
$ |
|
|
$ |
581 |
|
(1) Contracts include futures and fixed price swaps
(2) Contracts include basis swaps
The overall portfolio of the Companys energy derivatives held for risk management purposes approximates the notional quantity of a portion of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the energy derivative portfolio is managed to
67
complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of energy derivatives held for risk management purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying physical transactions, assuming the energy derivatives are not closed out in advance of their expected term, the energy derivatives continue to function effectively as hedges of the underlying risk and the anticipated transactions occur as expected.
As part of the purchase of the limited partnership interest in Eastern Seven Partners, L.P. (ESP) as discussed in Note 5, the Company assumed derivative liabilities of $47.3 million for the fair value of ESPs hedges. These hedges were effectively closed out at acquisition by the purchase of offsetting positions. The Company does not treat these derivatives as hedging instruments under SFAS No. 133. The fair value of these derivative instruments at December 31, 2006 was a $10.0 million liability. These amounts are included in the Consolidated Balance Sheet as derivative instruments, at fair value.
In May 2005, the Company sold certain non-core gas properties, as discussed in Note 4 . As part of this transaction, the Company closed out certain cash flow hedges associated with forecasted production at these locations by purchasing offsetting positions. The Company does not treat these derivatives as hedging instruments under SFAS No. 133. The fair value of these derivative instruments at December 31, 2006 was a $14.3 million liability. These amounts are included in the Consolidated Balance Sheet as derivative instruments, at fair value.
When the net fair value of any of the Companys swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company had less than $0.1 million of such deposits in its Consolidated Balance Sheet as of December 31, 2006. As of December 31, 2005, the Company recorded such deposits in the amount of $267.9 million in its Consolidated Balance Sheet.
When the Company enters into exchange-traded natural gas contracts, exchanges require participants, including the Company, to remit funds to the corresponding broker as good-faith deposits to guard against the risks associated with changing market conditions. Participants must make such deposits based on an established initial margin requirement as well as the net liability position, if any, of the fair value of the associated contracts. In the case where the fair value of such contracts is in a net asset position, the broker may remit funds to the Company, in which case the Company records a current liability for such amounts received. The initial margin requirements are established by the exchanges based on prices, volatility and the time to expiration of the related contract and are subject to change at the exchanges discretion. The Company recorded a liability of $7.9 million in its Consolidated Balance Sheet as of December 31, 2006, representing amounts received from brokers as a result of the related contracts having a positive fair value. The Company recorded an asset for deposits in the amount of $49.9 million in its Consolidated Balance Sheet as of December 31, 2005.
Other Derivative Instruments
In July 2004, the Company entered into three 7.5 year secured variable share forward transactions. Each transaction had a different counterparty, covered 2.0 million shares of Kerr-McGee Corporation (Kerr-McGee) common stock, contained a collar and permitted receipt of an amount up to the net present value of the floor price prior to maturity. Upon maturity of each transaction, the Company was obligated to deliver to the applicable counterparty, at the Companys option, no more than 2.0 million Kerr-McGee shares or cash in an equivalent value. The collars effectively limited the Companys cash flow exposure upon the forecasted disposal of 6.0 million Kerr-McGee shares. A variable portion of the dividends received on the underlying Kerr-McGee shares was paid to each counterparty depending upon the hedged position of such counterparty.
I n May 2005, the Company terminated the three variable share forward transactions. In connection with the termination, the Company incurred a termination cost of $95.8 million and sold 4.3 million Kerr-McGee shares to its
68
three counterparties to cover its counterparties respective hedged positions. See Note 9 for further discussion of transactions related to the Kerr-McGee shares.
4. Sale of Properties
In May 2005, the Company sold certain non-core gas properties and associated gathering assets for approximately $142 million after purchase price adjustments . In accordance with SFAS No. 19, this sale of only a portion of the Companys gas properties was treated as a normal retirement with no gain or loss recognized, as doing so did not significantly affect the depletion rate . See Note 24 for further discussion of changes to the Companys reserves during 2005.
5. Acquisitions
On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion Resources, Inc.s natural gas distribution assets in Pennsylvania and in West Virginia for approximately $970 million, subject to adjustments, in a cash transaction for the stock of The Peoples Natural Gas Company and Hope Gas, Inc. The transaction requires approvals from the PA PUC and the WV PSC and is also under review by the Pennsylvania Attorney General and by the Federal Trade Commission (FTC). On February 9, 2007 an administrative law judge for the PA PUC issued an initial decision approving the stock acquisition, subject to the terms and conditions of the Joint Petition for Settlement filed by the Company and a number of the intervening parties. The Joint Petition for Settlement includes, among other things, an agreement by the Company that Equitable Gas Company and The Peoples Natural Gas Company will not make base rate case filings prior to January 1, 2009. Under the Commissions rules a period for filing exceptions and reply exceptions has begun to run. Based upon the thorough manner in which the administrative law judge addressed the testimony of opposing parties, the Company believes it likely that the PA PUC will approve the stock acquisition when it reviews the application in March or April of 2007. The WV PSC procedural schedule calls for hearings in mid-May 2007. The WV PSC staff and consumer advocate, the Independent Oil and Gas Association of West Virginia and the Utility Workers Union of America Local 69 Division 1 have intervened in the West Virginia regulatory case. The Company continues to engage in settlement negotiations with these interveners. The Company is complying with the information requests of the Pennsylvania Attorney General and the FTC and is targeting an approval timeframe not long after receiving approval from the PA PUC. No assurance is given that the targeted timeframes will be achieved. The Companys acquisition agreement expires on March 31, 2007 unless a closing has not occurred due to a failure to obtain a required governmental consent or authorization and such is being diligently pursued, in which case the expiration date is automatically extended to June 30, 2007. The agreement will then terminate if no closing occurs by June 30, 2007, unless the parties agree to an extension. The assets to be acquired will increase: customers in the distribution operations by 475,000 or 173%; total storage capacity by 33 Bcf or 60%, miles of gathering pipelines by 936 miles; gathered volumes by 40%; and miles of high pressure transmission by 466 miles or 42%. Transition planning activities have commenced at Equitable Utilities to plan for the integration of the assets, resources, and business processes of The Peoples Natural Gas Company and Hope Gas, Inc.s into Equitable Resources.
In January 2005, the Company purchased the limited partnership interest in ESP for cash of $57.5 million and assumed liabilities of $47.3 million. See Note 24 for further discussion of changes to the Companys reserves during 2005.
69
6. Income Taxes
The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.
|
|
December 31, |
|
||||
|
|
2006 |
|
2005 |
|
||
|
|
(Thousands) |
|
||||
Deferred tax liabilities (assets): |
|
|
|
|
|
||
Drilling and development costs expensed for income tax reporting |
|
$ |
410,721 |
|
$ |
380,283 |
|
Other comprehensive loss |
|
(192,612 |
) |
(455,215 |
) |
||
Tax depreciation in excess of book depreciation |
|
105,318 |
|
88,485 |
|
||
Regulatory temporary differences |
|
29,326 |
|
27,281 |
|
||
Deferred purchased gas cost |
|
21,358 |
|
10,196 |
|
||
Deferred compensation plans |
|
(2,130 |
) |
(2,235 |
) |
||
Investment tax credit |
|
(3,654 |
) |
(3,921 |
) |
||
Uncollectible accounts |
|
(9,210 |
) |
(8,211 |
) |
||
Postretirement benefits |
|
(9,245 |
) |
(4,348 |
) |
||
Other, net of valuation allowance of $3,773 and $6,830, respectively |
|
(5,753 |
) |
(16,501 |
) |
||
Total (including amounts classified as current liabilities of $15,011 and $1,736 for 2006 and 2005, respectively) |
|
$ |
344,119 |
|
$ |
15,814 |
|
The net deferred tax asset relating to the Companys accumulated other comprehensive loss balance as of December 31, 2006 was comprised of a $173.7 million deferred tax asset related to the Companys net unrealized loss from hedging transactions, a $9.5 million deferred tax asset related to other post-retirement benefits, a $11.5 million deferred tax asset related to the pension plans, and a $2.1 million deferred tax liability related to the Companys net unrealized gain on available-for-sale securities. The net deferred tax asset relating to the Companys other comprehensive loss balance as of December 31, 2005 was comprised of a $445.7 million deferred tax asset related to the Companys net unrealized loss from hedging transactions, a $10.4 million deferred tax asset related to the minimum pension liability adjustment and an $0.9 million deferred tax liability related to the Companys net unrealized gain on available-for-sale securities.
Income tax expense is summarized as follows:
70
Provisions for income taxes differ from amounts computed at the Federal statutory rate of 35% on pretax income from continuing operations. The reasons for the difference are summarized as follows:
|
|
Years Ended December 31, |
|
|||||||
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
Tax at statutory rate |
|
$ |
114,006 |
|
$ |
144,064 |
|
$ |
158,810 |
|
State income taxes |
|
(8,130 |
) |
5,076 |
|
1,645 |
|
|||
Federal tax credits and incentives |
|
(1,609 |
) |
(3,604 |
) |
(707 |
) |
|||
Book/Tax basis differences |
|
(1,050 |
) |
(4,410 |
) |
(3,215 |
) |
|||
Incentive or deferred compensation |
|
93 |
|
15,300 |
|
1,400 |
|
|||
Other |
|
6,396 |
|
(3,388 |
) |
(2,980 |
) |
|||
Income tax expense |
|
$ |
109,706 |
|
$ |
153,038 |
|
$ |
154,953 |
|
Effective tax rate |
|
33.7 |
% |
37.2 |
% |
34.2 |
% |
During 2006, state income taxes decreased as a result of a change to state income tax rates as computed in accordance with SFAS No. 109 and the release of a state valuation allowance related to a state net operating loss carryover. During 2006, the Company reduced its valuation allowance for state net operating loss carryovers by $3.1 million as a result of an anticipated increase in prospective realization of those deferred tax assets. The other category does not include any items that are individually significant.
During 2005, following a moratorium imposed on the Company by the IRS for claiming any research and development (R&D) tax credits, the Company completed an analysis of its R&D expenditures for the years 2001 through 2005. This analysis resulted in a research tax credit that generated a tax benefit of $3.8 million for those periods, net of a tax reserve of $1.2 million. The study was extended to 2006 with a recorded tax benefit of $0.6 million, net of a tax reserve of $0.3 million.
During 2005, the Qualified Production Activities Deduction under Section 199 of the IRC, which provides for a phased-in deduction related to qualifying production activities, was provided for the first time under the American Jobs Creation Act of 2004. The Company recorded an income tax benefit for certain qualifying production activities of approximately $0.6 million and $1.9 million for 2006 and 2005, respectively.
During 2005, the Company recorded $15.3 million in tax benefit disallowances under Section 162(m) of the IRC, primarily as the result of impairment of previously recorded deferred tax assets related to the employee deferred compensation programs and the 2003 Executive Performance Incentive Program.
During 2003, the Company requested permission to change its method of accounting for inventory and self-constructed property in accordance with IRC Section 263A to use the simplified service cost method and simplified production method of capitalizing costs. During 2005, the IRS and the U.S. Treasury Department issued guidance providing for further clarification indicating that certain self-constructed property does not qualify as eligible property for the simplified methods. In 2006, the Company requested and was granted permission to conform its capitalization method to the facts and circumstances method and believes that it is appropriately reserved for any tax exposures for prior years.
The consolidated Federal income tax liability of the Company has been settled with the IRS through 1997. The IRS has completed its review of the Companys Federal income tax filings for the 1998 through 2000 years and the Company believes that only minor issues remain to be resolved. The IRS is expected to survey the 2001 and 2002 Federal income tax filings and audit years 2003 and forward. The Company also is the subject of various routine state income tax examinations. The Company believes that it is appropriately reserved for any tax exposures.
71
An income tax benefit of $18.6 million, $18.0 million and $7.8 million for the years ended December 31, 2006, 2005 and 2004, respectively, triggered by the exercise of nonqualified employee stock options and vesting of restricted share awards is reflected as an addition to common stockholders equity.
The Company has recorded a deferred tax asset of $7.3 million, net of valuation allowances of $2.9 million, related to tax benefits from state net operating loss carryforwards with various expiration dates ranging from 2013 to 2026.
7. Discontinued Operations
In the fourth quarter of 2005, the Company sold its NORESCO domestic business for $82 million before customary purchase price adjustments. Income from discontinued operations for the year ended December 31, 2005 included after-tax charges totaling $18.7 million, including $13.7 million which related to the recording of income taxes associated with the difference between the book and tax basis of the NORESCO assets sold, and $5.0 million of after-tax losses on the sale related to other costs incurred as a result of this sale.
In the fourth quarter of 2006, the Company recorded a tax benefit of $3.2 million related to a reduced tax liability on the sale. The Company also reassessed its remaining reserves for costs incurred related to the sale and recorded after-tax income of $1.1 million as a result. These items are included in income from discontinued operations in the Companys Statement of Consolidated Income for the year ended December 31, 2006.
In 2006, the Company completed the sale of the remaining interest in its investment in IGC/ERI Pan-Am Thermal Generating Limited (Pan Am), previously included in the NORESCO business segment, for total proceeds of $2.6 million. The Company did not record a gain or loss on this sale.
Cash flows generated from the discontinued operations and the proceeds received from the sale of the Pan Am investment of $2.6 million and of the NORESCO Domestic operations of $80.0 million are included in the Consolidated Statements of Cash Flows for the years ended December 31, 2006 and 2005, respectively.
Total operating revenues reclassified to discontinued operations for the years ended December 31, 2005 and 2004 were $143.5 million and $146.4 million, respectively. Interest expense of discontinued operations allocated based upon a ratio of the net assets of the discontinued operations to the overall net assets of the Company was $1.5 million for each of the years ended December 31, 2005 and 2004.
8. Equity in Nonconsolidated Investment
The Company has an ownership interest in a nonconsolidated investment that is accounted for under the equity method of accounting. The following table summarizes the equity in the nonconsolidated investment.
|
|
|
|
Interest |
|
Ownership
|
|
December 31, |
|
||||
Investees |
|
Location |
|
Type |
|
31, 2006 |
|
2006 |
|
2005 |
|
||
|
|
|
|
|
|
|
|
(Thousands) |
|
||||
Appalachian Natural Gas Trust (ANGT) |
|
USA |
|
Limited |
|
1 |
% |
$ |
35,023 |
|
$ |
35,555 |
|
The Companys ownership share of the earnings for 2006, 2005 and 2004 related to the total investments was $0.3 million, $0.8 million and $0.9 million, respectively.
Equitable Supplys equity investment in ANGT represents an ownership interest in transactions by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. As of December 31, 2006, Equitable Supplys investment in ANGT totaled $23.3 million, while the Companys total
72
investment was $35.0 million. As of December 31, 2005, Equitable Supplys investment in ANGT totaled $23.7 million, while the Companys total investment was $35.6 million. The Company did not make any additional equity investments in nonconsolidated investments during 2006 or 2005.
As discussed in Note 5, the Company purchased the 99% limited partnership interest in ESP in January 2005. The financial position and results of operations of ESP have been consolidated in the Companys Consolidated Financial Statements as of and for the years ending December 31, 2006 and 2005.
The following tables summarize the financial information for ANGT for the periods noted:
Summarized Balance Sheets
|
|
As of December 31, |
|
||||
|
|
2006 |
|
2005 |
|
||
|
|
(unaudited) |
|
|
|
||
|
|
(Thousands) |
|
||||
Current assets |
|
$ |
5,085 |
|
$ |
12,228 |
|
Noncurrent assets |
|
188,742 |
|
206,085 |
|
||
Total assets |
|
$ |
193,827 |
|
$ |
218,313 |
|
|
|
|
|
|
|
||
Current liabilities |
|
$ |
3,194 |
|
$ |
17 |
|
Stockholders equity |
|
190,633 |
|
218,296 |
|
||
Total liabilities and stockholders equity |
|
$ |
193,827 |
|
$ |
218,313 |
|
Summarized Statements of Income
|
|
Year Ended December 31, |
|
|||||||
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(unaudited) |
|
|
|
|
|
|||
|
|
(Thousands) |
|
|||||||
Revenues |
|
$ |
94,477 |
|
$ |
108,307 |
|
$ |
89,513 |
|
Costs and expenses applicable to revenues |
|
|
|
|
|
|
|
|||
Net revenues |
|
94,477 |
|
108,307 |
|
89,513 |
|
|||
Operating expenses |
|
43,056 |
|
39,601 |
|
39,462 |
|
|||
Net income |
|
$ |
51,421 |
|
$ |
68,706 |
|
$ |
50, 051 |
|
73
9. Investments, Available-For-Sale
As of December 31, 2006, the investments classified by the Company as available-for-sale consist of approximately $31.3 million of equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures. Any unrealized gains or losses with respect to investments classified as available-for-sale are recognized within the Consolidated Balance Sheets as a component of equity, accumulated other comprehensive loss.
|
|
December 31, 2006 |
|
||||||||||
|
|
Cost |
|
Gross
|
|
Gross
|
|
Fair
|
|
||||
|
|
(Thousands) |
|
||||||||||
Corporate equity securities |
|
$ |
25,164 |
|
$ |
6,106 |
|
$ |
|
|
$ |
31,270 |
|
Total investments |
|
$ |
25,164 |
|
$ |
6,106 |
|
$ |
|
|
$ |
31,270 |
|
|
|
December 31, 2005 |
|
||||||||||
|
|
Cost |
|
Gross
|
|
Gross
|
|
Fair
|
|
||||
|
|
(Thousands) |
|
||||||||||
Corporate equity securities |
|
$ |
22,742 |
|
$ |
2,452 |
|
$ |
|
|
$ |
25,194 |
|
Total investments |
|
$ |
22,742 |
|
$ |
2,452 |
|
$ |
|
|
$ |
25,194 |
|
In May 2005, the three variable share forward transactions associated with Kerr-McGee shares were terminated as described in Note 3. The Company concurrently s old 4.3 million Kerr-McGee shares to its three counterparties and received $227.4 million in pre-tax net proceeds at an average price of $75.43 per share. In addition, the Company unconditionally tendered 1.7 million Kerr-McGee shares at $85.00 per share to Kerr-McGee in connection with Kerr-McGees Dutch auction tender offer to purchase its own shares. Accordingly, as a result of its tender of shares, the Company received approximately $49.0 million in pre-tax proceeds on the sale of approximately 0.6 million shares. These transactions resulted in pre-tax gains to the Company totaling $34.2 million, net of collar termination costs.
In various transactions during 2005, the Company sold its remaining approximately 2.1 million Kerr-McGee shares for total pre-tax proceeds of $184.1 million. The sale of these shares resulted in pre-tax gains to the Company totaling $76.1 million. The Company has no further interest or ownership in any Kerr-McGee shares.
The Company recorded pre-tax dividend income, net of payments to the counterparties for the aforementioned collars, of $1.2 million and $3.1 million for the years ended December 31, 2005 and 2004, respectively. This dividend income is recorded in other income, net on the Statements of Consolidated Income.
Under the terms of the merger agreement between Westport and Kerr-McGee, the Company received 0.71 shares of Kerr-McGee for each Westport share owned, or 8.2 million shares of Kerr-McGee, in the second quarter of 2004. Accordingly, the Company recognized a gain of $217.2 million on the exchange of the Westport shares for Kerr-McGee shares in 2004.
Subsequent to the Kerr-McGee/Westport merger, the Company sold 0.8 million Kerr-McGee shares for pre-tax proceeds of $42.9 million in 2004. The sale resulted in the Company recognizing a gain of $3.0 million in 2004.
In 2004, the Company contributed approximately 0.4 million Kerr-McGee shares to Equitable Resources Foundation, Inc. This resulted in the Company recording a charitable foundation contribution expense of $18.2 million during 2004, with a corresponding one-time tax benefit of $6.8 million.
74
The Company utilizes the specific identification method to determine the cost of all investment securities sold.
10. Regulatory Assets
The following table summarizes the Companys regulatory assets, net of amortization, as of December 31, 2006 and 2005. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of its regulatory assets.
|
|
December 31, |
|
||||
Description |
|
2006 |
|
2005 |
|
||
|
|
(Thousands) |
|
||||
Deferred taxes |
|
$ |
59,932 |
|
$ |
56,208 |
|
Delinquency Reduction Opportunity Program |
|
3,006 |
|
5,049 |
|
||
Other postretirement benefits (SFAS No. 106) |
|
15,590 |
|
8,626 |
|
||
Deferred purchase gas costs |
|
54,062 |
|
50,472 |
|
||
Other |
|
191 |
|
172 |
|
||
Total regulatory assets |
|
132,781 |
|
120,527 |
|
||
Amounts classified as other current assets |
|
54,062 |
|
50,472 |
|
||
Total long-term regulatory assets |
|
$ |
78,719 |
|
$ |
70,055 |
|
The regulatory asset associated with deferred taxes primarily represents deferred income taxes recoverable through future rates once the taxes become current. The Company expects to recover the amortization of this asset through rates.
The regulatory asset associated with a Delinquency Reduction Opportunity Program at Equitable Gas relates to uncollectible accounts receivable resulting from unusually high natural gas prices and unseasonably cold weather experienced during the winter of 2000-2001. The regulatory asset was initially established based upon the Companys ability to recover these costs through a surcharge in rates. In 2002, the PA PUC issued an order approving a Delinquency Reduction Opportunity Program that gives incentives to low-income customers to make payments that exceed their current bill amount in order to receive additional credits from the Company intended to speed the reduction of the customers delinquent balance. This program is funded through customer contributions and through the existing surcharge in rates.
Under the Equitrans (a subsidiary of the Company) rate case settlement, the Company began amortization of postretirement benefits other than pensions previously deferred as well as recognizing expenses for on-going postretirement benefits other than pensions, which are now subject to recovery from July 1, 2005 forward in the approved rates. The reduction in the Companys regulatory asset for amortization of postretirement benefits other than pensions previously deferred was approximately $1.4 million for the year ended December 31, 2006. In addition, as a part of the rate case settlement, the Companys regulatory asset was reduced approximately $1.3 million in 2006 for amortization of postretirement benefits other than pensions previously deferred and on-going postretirement benefits other than pensions for the period July 1, 2005 to December 31, 2005.
In September 2006, the FASB issued SFAS No. 158, which requires an employer to recognize a benefit plans funded status in its statement of financial position, measure a benefit plans assets and obligations as of the end of the employers fiscal year and recognize the changes in the benefit plans funded status in other comprehensive income in the year in which the changes occur. SFAS No. 158s requirement to recognize the funded status of a benefit plan and the new disclosure requirements were effective as of December 31, 2006. The Company recorded $9.8 million as a regulatory asset for Equitrans other postretirement benefits in applying SFAS No. 158 as of December 31, 2006. The Company believes the future recovery of the unfunded status of the Equitrans other postretirement benefits is probable in accordance with the requirements of SFAS No. 71.
75
The following regulatory assets do not earn a return on investment: deferred taxes, Delinquency Reduction Opportunity Program and other postretirement benefits (SFAS No. 106). The associated remaining recovery period for the regulatory assets associated with both the Delinquency Reduction Opportunity Program and other postretirement benefits is four years at December 31, 2006. The associated remaining recovery period for the regulatory assets associated with deferred taxes is variable depending on the life of the book/tax difference generating the deferred item.
11. Short-Term Loans
On October 27, 2006, the Company entered into a $1.5 billion, five-year revolving credit agreement, which replaced the Companys previous $1 billion, five-year revolving credit agreement. On December 15, 2006, the maturity date was extended to October 26, 2011 pursuant to its terms. Additionally, the Company may request two one-year extensions of the stated maturity date. The revolving credit agreement may be used for working capital, capital expenditures, share repurchases and other purposes including support of the Companys commercial paper program. Subject to certain terms and conditions, the Company may, on a one time basis, request that the lenders commitments be increased to an aggregate amount of up to $2.0 billion.
The Company is not required to maintain compensating bank balances. The Companys debt issuer credit ratings, as determined by either Standard & Poors or Moodys on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Companys debt credit rating, the higher the level of fees and borrowing rate. As of December 31, 2006, the Company had not borrowed any amounts against these lines of credit. Commitment fees averaging one-seventeenth and one-thirteenth of one percent in 2006 and 2005, respectively, were paid to maintain credit availability.
Short-term loans were comprised of commercial paper balances of $136.0 million and $365.3 million with weighted average annual interest rates of 5.45% and 4.40% as of December 31, 2006 and 2005, respectively. The maximum amount of outstanding short-term loans at any time during the year was $467.5 million in 2006 and $631.5 million in 2005. The average daily balance of short-term loans outstanding over the course of the year was approximately $126.0 million and $309.6 million at weighted average annual interest rates of 4.63% and 3.48% during 2006 and 2005, respectively.
12. Long-Term Debt
|
|
December 31, |
|
||||
|
|
2006 |
|
2005 |
|
||
|
|
(Thousands) |
|
||||
5.15% notes, due March 1, 2018 |
|
$ |
200,000 |
|
$ |
200,000 |
|
5.15% notes, due November 15, 2012 |
|
200,000 |
|
200,000 |
|
||
5.00% notes, due October 1, 2015 |
|
150,000 |
|
150,000 |
|
||
7.75% debentures, due July 15, 2026 |
|
115,000 |
|
115,000 |
|
||
Medium-term notes: |
|
|
|
|
|
||
8.5% to 9.0% Series A, due 2009 thru 2021 |
|
50,500 |
|
53,500 |
|
||
7.3% to 7.6% Series B, due 2013 thru 2023 |
|
30,000 |
|
30,000 |
|
||
6.8% to 7.6% Series C, due 2007 thru 2018 |
|
18,000 |
|
18,000 |
|
||
|
|
763,500 |
|
766,500 |
|
||
Less debt payable within one year |
|
10,000 |
|
3,000 |
|
||
Total long-term debt |
|
$ |
753,500 |
|
$ |
763,500 |
|
The indentures and other agreements governing the Companys indebtedness contain certain restrictive financial and operating covenants including covenants that restrict the Companys ability to incur indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. The covenants do not contain a rating trigger. Therefore, in the event that the Companys
76
debt rating changes, this event would not trigger a default under the indentures and other agreements governing the Companys indebtedness.
Aggregate maturities of long-term debt are $10.0 million in 2007, $0 in 2008, $4.3 million in 2009, $0 in 2010 and $6.0 million in 2011.
13. Pension and Other Postretirement Benefit Plans
During the fourth quarter of 2006, the Company recognized a settlement expense of approximately $3.3 million, comprised of $2.7 million for pension benefits and $0.6 million for other postretirement benefits, for an early retirement program, which was accounted for under SFAS No. 88 and SFAS No. 106. This settlement expense was primarily the result of special termination benefits. Under this settlement, the affected employees were provided the option to either receive the lump-sum value or an insured monthly annuity of their pension benefit or roll over the lump-sum value of their pension benefit to the Companys defined contribution plan. The $3.3 million settlement expense is recorded as a gathering and compression expense included within operating expense of the Equitable Supply business segment (see Note 2). As a result of this settlement, the Companys projected benefit obligation decreased by approximately $1.4 million.
During 2006, the Company made certain retiree medical plan design changes, which were accounted for under SFAS No. 106, that decreased the Companys other postretirement benefits plan benefits obligation by approximately $10.2 million. These design changes included a decrease in the Companys capped contribution per retiree and the elimination of certain retiree benefits.
During 2005, the Company settled its pension obligation with the United Steelworkers of America, Local Union 12050 representing 182 employees. As a result of this settlement, which was accounted for under SFAS No. 88, the Company recognized a settlement expense of $12.1 million during 2005. During the fourth quarter of 2005, the Company settled its pension obligation with certain non-represented employees. As a result of this settlement, which was accounted for under SFAS No. 88, the Company recognized a settlement expense of approximately $2.4 million in 2005. These settlement expenses were primarily the result of accelerated recognition of unrecognized losses. Under these settlements, the affected employees were provided the option to either roll over the lump-sum value of their pension benefit to the Companys defined contribution plan or to receive an insured monthly annuity benefit at the time they retire. Additionally, $14.3 million of these pension settlement expenses are recorded as a selling, general and administrative expense within operating expense of the Equitable Utilities business segment, and $0.2 million is a gathering and compression expense included within operating expense of the Equitable Supply business segment (see Note 2). As a result of these settlements, the Companys projected benefit obligation decreased by approximately $13.9 million.
All other non-represented employees are participants in a defined contribution plan.
Effective December 31, 2004, the Company settled the pension obligation of those non-represented employees (cash balance participants) whose benefits were frozen as of December 31, 2003. As a result of this settlement, the Company recognized a one-time settlement expense of $13.4 million in 2004, which was primarily the result of accelerated recognition of previously deferred unrecognized losses. The pension settlement expense in 2004 is recorded as an unallocated expense in deriving total operating income for segment reporting purposes (see Note 2). As a result of this settlement, the Companys projected benefit obligation decreased by approximately $19.6 million.
In September 2006, the FASB issued SFAS No. 158, which requires an employer to recognize a benefit plans funded status in its statement of financial position, measure a benefit plans assets and obligations as of the end of the employers fiscal year and recognize the changes in the benefit plans funded status in other comprehensive income in the year in which the changes occur. SFAS No. 158s requirement to recognize the
77
funded status of a benefit plan and the new disclosure requirements were effective as of December 31, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employers fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. The incremental effect of applying SFAS No. 158 in the Companys statement of financial position as of December 31, 2006 is as follows:
|
|
December 31, 2006 |
|
|||||||
|
|
(Thousands) |
|
|||||||
|
|
Before
|
|
Adjustments |
|
After
|
|
|||
Incremental effect of applying SFAS No. 158 on individual line items in the statement of financial position: |
|
|
|
|
|
|
|
|||
Regulatory assets |
|
$ |
68,908 |
|
$ |
9,811 |
|
$ |
78,719 |
|
Other assets |
|
34,841 |
|
(1,863 |
) |
32,978 |
|
|||
Total other assets |
|
103,749 |
|
7,948 |
|
111,697 |
|
|||
Total assets |
|
3,248,963 |
|
7,948 |
|
3,256,911 |
|
|||
Other current liabilities |
|
144,525 |
|
5,678 |
|
150,203 |
|
|||
Total current liabilities |
|
1,074,101 |
|
5,678 |
|
1,079,779 |
|
|||
Deferred income taxes and investment tax credits |
|
348,729 |
|
(10,717 |
) |
338,012 |
|
|||
Pension and other postretirement benefits liabilities |
|
22,950 |
|
27,997 |
|
50,947 |
|
|||
Accumulated other comprehensive loss |
|
(299,292 |
) |
(15,010 |
) |
(314,302 |
) |
|||
Total common stockholders equity |
|
961,290 |
|
(15,010 |
) |
946,280 |
|
|||
Total liabilities and common stockholders equity |
|
3,248,963 |
|
7,948 |
|
3,256,911 |
|
|||
The following table sets forth the defined benefit pension and other postretirement benefit plans funded status and amounts recognized for those plans in the Companys Consolidated Balance Sheets:
|
|
Pension Benefits |
|
Other Benefits |
|
||||||||
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
||||
|
|
(Thousands) |
|
||||||||||
Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
||||
Benefit obligation at beginning of year |
|
$ |
82,153 |
|
$ |
116,255 |
|
$ |
54,257 |
|
$ |
55,673 |
|
Service cost |
|
430 |
|
899 |
|
553 |
|
541 |
|
||||
Interest cost |
|
4,389 |
|
5,891 |
|
2,899 |
|
3,168 |
|
||||
Amendments |
|
|
|
|
|
(10,180 |
) |
1,248 |
|
||||
Actuarial loss |
|
5,325 |
|
7,883 |
|
5,317 |
|
675 |
|
||||
Benefits paid |
|
(7,637 |
) |
(7,605 |
) |
(6,291 |
) |
(7,048 |
) |
||||
Curtailments |
|
227 |
|
1,048 |
|
410 |
|
|
|
||||
Settlements |
|
(4,181 |
) |
(42,218 |
) |
|
|
|
|
||||
Special termination benefits |
|
1,416 |
|
|
|
179 |
|
|
|
||||
Benefit obligation at end of year |
|
$ |
82,122 |
|
$ |
82,153 |
|
$ |
47,144 |
|
$ |
54,257 |
|
78
|
|
Pension Benefits |
|
Other Benefits |
|
||||||||
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
||||
|
|
(Thousands) |
|
||||||||||
Change in plan assets: |
|
|
|
|
|
|
|
|
|
||||
Fair value of plan assets at beginning of year |
|
$ |
75,079 |
|
$ |
100,917 |
|
$ |
|
|
$ |
|
|
Gain recognized at beginning of year |
|
|
|
41 |
|
|
|
|
|
||||
Actual gain on plan assets |
|
7,593 |
|
3,580 |
|
|
|
|
|
||||
Employer contributions |
|
1,751 |
|
20,364 |
|
|
|
|
|
||||
Benefits paid |
|
(7,637 |
) |
(7,605 |
) |
|
|
|
|
||||
Settlements |
|
(4,170 |
) |
(42,218 |
) |
|
|
|
|
||||
Fair value of plan assets at end of year |
|
$ |
72,616 |
|
$ |
75,079 |
|
$ |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Funded status at end of year |
|
$ |
(9,506 |
) |
$ |
(7,074 |
) |
$ |
(47,144 |
) |
$ |
(54,257 |
) |
|
|
|
|
|
|
|
|
|
|
||||
Amounts recognized in the statement of financial position consist of: |
|
|
|
|
|
|
|
|
|
||||
Current liabilities |
|
$ |
|
|
$ |
|
|
$ |
(5,678 |
) |
$ |
|
|
Noncurrent liabilities |
|
(9,506 |
) |
(7,074 |
) |
(41,466 |
) |
(13,796 |
) |
||||
Net amount recognized |
|
$ |
(9,506 |
) |
$ |
(7,074 |
) |
$ |
(47,144 |
) |
$ |
(13,796 |
) |
Amounts recognized in accumulated other comprehensive loss consist of, net of tax: |
|
|
|
|
|
|
|
|
|
||||
Net loss |
|
$ |
16,390 |
|
$ |
15,366 |
|
$ |
17,945 |
|
$ |
|
|
Net prior service cost (credit) |
|
727 |
|
|
|
(3,662 |
) |
|
|
||||
Net amount recognized |
|
$ |
17,117 |
|
$ |
15,366 |
|
$ |
14,283 |
|
$ |
|
|
The accumulated benefit obligation for all defined benefit pension plans was $82.1 million and $82.2 million at December 31, 2006 and 2005, respectively. The Company uses a December 31 measurement date for its defined benefit pension and other postretirement plans.
The Companys costs related to its defined benefit pension and other postretirement benefit plans were as follows:
|
|
Pension Benefits |
|
Other Benefits |
|
||||||||||||||
|
|
2006 |
|
2005 |
|
2004 |
|
2006 |
|
2005 |
|
2004 |
|
||||||
|
|
(Thousands) |
|
||||||||||||||||
Components of net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Service cost |
|
$ |
430 |
|
$ |
899 |
|
$ |
1,590 |
|
$ |
553 |
|
$ |
541 |
|
$ |
483 |
|
Interest cost |
|
4,389 |
|
5,891 |
|
6,970 |
|
2,899 |
|
3,168 |
|
3,273 |
|
||||||
Expected return on plan assets |
|
(6,132 |
) |
(8,032 |
) |
(9,828 |
) |
|
|
|
|
|
|
||||||
Amortization of prior service cost |
|
370 |
|
766 |
|
940 |
|
(137 |
) |
(42 |
) |
(42 |
) |
||||||
Recognized net actuarial loss |
|
1,069 |
|
867 |
|
745 |
|
2,146 |
|
2,299 |
|
2,000 |
|
||||||
Settlement loss and special termination benefits (a) |
|
2,348 |
|
15,713 |
|
13,733 |
|
179 |
|
|
|
|
|
||||||
Curtailment loss |
|
602 |
|
2,648 |
|
2,434 |
|
410 |
|
|
|
|
|
||||||
Net periodic benefit cost |
|
$ |
3,076 |
|
$ |
18,752 |
|
$ |
16,584 |
|
$ |
6,050 |
|
$ |
5,966 |
|
$ |
5,714 |
|
(a) The 2005 settlement loss and special termination benefits includes $10.4 million of loss recognition for the settlement of the Steelworkers pension benefit obligation and $1.3 million of loss associated with the non-represented employees portion of the pension benefit obligation which was settled during the fourth quarter of 2005 . The 2004 settlement loss and special termination benefits includes $11.0 million of loss recognition associated with the settlement of the cash balance participants pension benefit obligation at December 31, 2004, for those non-represented employees whose benefits under the pension plan were frozen in 2003.
79
Under the Equitrans rate case settlement, the Company began amortization of post-retirement benefits other than pensions previously deferred as well as recognizing expenses for on-going post-retirement benefits other than pensions, which are now subject to recovery from July 1, 2005 forward in the approved rates. Expenses recognized by the Company for the year ended December 31, 2006 for amortization of post-retirement benefits other than pensions previously deferred and on-going post-retirement benefits other than pensions were approximately $1.4 million and $1.2 million, respectively. In addition, as a part of the rate case settlement, the Company recognized expenses for year ended December 31, 2006 of approximately $1.3 million for amortization of post-retirement benefits other than pensions previously deferred and on-going post-retirement benefits other than pensions for the period July 1, 2005 to December 31, 2005.
|
|
Pension Benefits |
|
Other Benefits |
|
||||||||||||||
|
|
2006 |
|
2005 |
|
2004 |
|
2006 |
|
2005 |
|
2004 |
|
||||||
|
|
(Thousands) |
|
||||||||||||||||
Other changes in plan assets and benefit obligations recognized in other comprehensive loss, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net loss (gain) |
|
$ |
1,024 |
|
$ |
(4,325 |
) |
$ |
(5,841 |
) |
$ |
17,945 |
|
$ |
|
|
$ |
|
|
Net prior service cost (credit) |
|
727 |
|
|
|
|
|
(3,662 |
) |
|
|
|
|
||||||
Total recognized in other comprehensive income, net of tax |
|
1,751 |
|
(4,325 |
) |
(5,841 |
) |
14,283 |
|
|
|
|
|
||||||
Total recognized in net periodic benefit cost and other comprehensive income, net of tax |
|
$ |
4,827 |
|
$ |
14,427 |
|
$ |
10,743 |
|
$ |
20,333 |
|
$ |
5,966 |
|
$ |
5,714 |
|
The estimated net loss and net prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year are $1.4 million and $0.3 million, respectively. The estimated net loss and net prior service credit for the other postretirement benefit plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year are $2.3 million and ($0.8 million).
The following weighted average assumptions were used to determine the benefit obligations and net periodic benefit cost for the Companys defined benefit pension and other postretirement benefit plans:
|
|
Pension Benefits |
|
Other Benefits |
|
||||
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
5.75 |
% |
5.75 |
% |
5.75 |
% |
5.75 |
% |
Expected return on plan assets |
|
8.25 |
% |
8.25 |
% |
N/A |
|
N/A |
|
Rate of compensation increase |
|
N/A |
|
N/A |
|
N/A |
|
N/A |
|
The expected rate of return is established at the beginning of the fiscal year that it relates to based upon information available to the Company at that time, including the plans investment mix and the forecasted rates of return on these types of securities. The Company considered the historical rates of return earned on plan assets, an expected return percentage by asset class based upon a survey of investment managers and the Companys actual and targeted investment mix. Any differences between actual experience and assumed experience are deferred as an unrecognized actuarial gain or loss. The unrecognized actuarial gains or losses are amortized into the Companys net periodic benefit cost in accordance with SFAS No. 87. The expected rate of return determined as of January 1, 2007 totaled 8.25%. This assumption will be used to derive the Companys 2007 net periodic benefit cost. The rate of compensation increase is no longer applicable in determining future benefit obligations as a result of the conversion of certain non-represented employees to a defined contribution plan in 2003 as previously discussed. Pension expense increases as the expected long-term rate of rate of return decreases or if the discount rate is lowered. Lowering the expected long-term rate of return by 0.5% or lowering the discount rate by 0.5% as of December 31, 2006, would not have a significant impact on pension expense for 2007.
80
For measurement purposes, the annual rate of increase in the per capita cost of covered health care benefits in 2007 is 10.0% for both the Pre-65 and Post-65 medical charges. The rates were assumed to decrease gradually to ultimate rates of 5.0% in 2012.
Assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
|
|
One-Percentage-Point
|
|
One-Percentage-Point
|
|
||||||||||||||
|
|
(Thousands) |
|
(Thousands) |
|
||||||||||||||
|
|
2006 |
|
2005 |
|
2004 |
|
2006 |
|
2005 |
|
2004 |
|
||||||
Increase (decrease) to total of service and interest cost components |
|
$ |
115 |
|
$ |
91 |
|
$ |
108 |
|
$ |
(109 |
) |
$ |
(90 |
) |
$ |
(104 |
) |
Increase (decrease) to postretirement benefit obligation |
|
$ |
1,071 |
|
$ |
2,030 |
|
$ |
1,751 |
|
$ |
(1,000 |
) |
$ |
(1,897 |
) |
$ |
(1,659 |
) |
The Companys pension asset allocation at December 31, 2006 and 2005 and target allocation for 2007 by asset category are as follows:
|
|
Target |
|
Percentage of Plan Assets
|
|
||
Asset Category |
|
Allocation 2007 |
|
2006 |
|
2005 |
|
|
|
|
|
|
|
|
|
Domestic broadly diversified equity securities |
|
50% - 70% |
|
50% |
|
54% |
|
Fixed income securities and inflation hedge securities |
|
30% - 45% |
|
36% |
|
38% |
|
International broadly diversified equity securities |
|
5% - 15% |
|
11% |
|
7% |
|
Other |
|
0% - 15% |
|
3% |
|
1% |
|
|
|
|
|
100% |
|
100% |
|
The investment activities of the Companys pension plan are supervised and monitored by the Companys Benefits Investment Committee. The Benefits Investment Committee has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Benefits Investment Committee are to minimize high levels of risk at the total pension investment fund level. The Benefits Investment Committee monitors the actual asset allocation on a quarterly basis and adjustments are made, as needed, to rebalance the assets within the prescribed target ranges. Comparative market and peer group benchmarks are utilized to ensure that each of the firms investment managers is performing satisfactorily.
The Company made cash contributions of approximately $1.8 million and $20.4 million to its pension plan during 2006 and 2005, respectively, as a result of the previously described settlements. The Company expects to make cash contributions of approximately $1.0 million to its pension plan during 2007. The Company was not required to, and consequently did not make any contribution to its pension plans during the year ended December 31, 2004.
The following benefit payments, which reflect expected future service, are expected to be paid during each of the next five years and the five years thereafter: $10.1 million in 2007; $7.3 million in 2008; $7.4 million in 2009; $6.8 million in 2010; $7.3 million in 2011; and $33.5 million in the five years thereafter.
Expense recognized by the Company related to its 401(k) employee savings plans totaled $5.2 million in 2006, $5.1 million in 2005 and $4.5 million in 2004.
81
14. Common Stock and Earnings Per Share
At December 31, 2006, shares of Equitables authorized and unissued common stock were reserved as follows:
Earnings Per Share
The computation of basic and diluted earnings per common share is shown in the table below:
|
|
Years Ended December 31, |
|
|||||||
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands, except per share amounts) |
|
|||||||
Basic earnings per common share: |
|
|
|
|
|
|
|
|||
Income from continuing operations |
|
$ |
216,025 |
|
$ |
258,574 |
|
$ |
298,790 |
|
Income (loss) from discontinued operations, net of tax |
|
4,261 |
|
1,481 |
|
(18,936 |
) |
|||
Net income applicable to common stock |
|
$ |
220,286 |
|
$ |
260,055 |
|
$ |
279,854 |
|
Average common shares outstanding |
|
120,124 |
|
121,099 |
|
123,364 |
|
|||
Basic earnings per common share |
|
$ |
1.83 |
|
$ |
2.15 |
|
$ |
2.27 |
|
Diluted earnings per common share: |
|
|
|
|
|
|
|
|||
Income from continuing operations |
|
$ |
216,025 |
|
$ |
258,574 |
|
$ |
298,790 |
|
Income (loss) from discontinued operations, net of tax |
|
4,261 |
|
1,481 |
|
(18,936 |
) |
|||
Net income applicable to common stock |
|
$ |
220,286 |
|
$ |
260,055 |
|
$ |
279,854 |
|
Average common shares outstanding |
|
120,124 |
|
121,099 |
|
123,364 |
|
|||
Potentially dilutive securities: |
|
|
|
|
|
|
|
|||
Stock options and awards (a) |
|
1,989 |
|
2,616 |
|
2,838 |
|
|||
Total |
|
122,113 |
|
123,715 |
|
126,202 |
|
|||
Diluted earnings per common share |
|
$ |
1.80 |
|
$ |
2.10 |
|
$ |
2.22 |
|
(a) Options to purchase 53,093 shares of common stock were not included in the computation of diluted earnings per common share for 2006 because the options exercise prices were greater than the average market prices of the common shares. There were no antidilutive options for 2005 or 2004.
15. Accumulated Other Comprehensive Loss
The components of accumulated other comprehensive loss, net of tax, are as follows:
|
|
2006 |
|
2005 |
|
||
|
|
(Thousands) |
|
||||
|
|
|
|
|
|
||
Net unrealized loss from hedging transactions |
|
$ |
(286,871 |
) |
$ |
(741,804 |
) |
Unrealized gain on available-for-sale securities |
|
3,969 |
|
1,570 |
|
||
Pension and other post-retirement benefits adjustment |
|
(31,400 |
) |
(15,366 |
) |
||
Accumulated other comprehensive loss |
|
$ |
(314,302 |
) |
$ |
(755,600 |
) |
82
16. Share-Based Compensation Plans
The Company adopted SFAS No. 123R effective January 1, 2006, using the modified prospective method. Under the modified prospective method, compensation cost is recognized beginning with the effective date and prior period results are not restated. As such, compensation cost related to all share-based awards, including non-qualified stock options, was recorded as selling, general and administrative expense in the Companys Statement of Consolidated Income for the year ended December 31, 2006. The compensation cost that has been charged to expense for all of the Companys share-based compensation arrangements, described below, was $26.6 million, $48.4 million, and $30.8 million for the years ended December 31, 2006, 2005, and 2004, respectively.
The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123R to employee share-based awards for the years ended December 31, 2005 and December 31, 2004.
|
|
Year Ended
|
|
Year Ended
|
|
||
|
|
(Thousands) |
|
||||
Net income, as reported |
|
$ |
260,055 |
|
$ |
279,854 |
|
Add: Gross share-based employee compensation expense included in reported net income |
|
48,363 |
|
30,763 |
|
||
Deduct: Income tax benefit from share-based employee compensation expense included in reported net income |
|
(16,182 |
) |
(10,389 |
) |
||
Deduct: Total share-based employee compensation expense determined under fair value method for all awards, net of related tax effects |
|
(33,693 |
) |
(24,575 |
) |
||
Pro forma net income |
|
$ |
258,543 |
|
$ |
275,653 |
|
Earnings per share: |
|
|
|
|
|
||
Basic, as reported |
|
$ |
2.15 |
|
$ |
2.27 |
|
Basic, pro forma |
|
$ |
2.13 |
|
$ |
2.23 |
|
|
|
|
|
|
|
||
Diluted, as reported |
|
$ |
2.10 |
|
$ |
2.22 |
|
Diluted, pro forma |
|
$ |
2.09 |
|
$ |
2.18 |
|
Adoption of SFAS No. 123R had the effect of reducing operating income and income from continuing operations before income taxes by $1.0 million, and net income by $0.6 million or less than $0.01 per basic and diluted share, for the year ended December 31, 2006. Prior to the adoption of SFAS No. 123R, the Company presented all tax benefits for deductions resulting from the exercise of share-based awards as cash flows from operating activities in its Statements of Condensed Consolidated Cash Flows. SFAS No. 123R requires the benefits of tax deductions in excess of recognized compensation expense to be reported as a cash flow from financing activities, rather than as a cash flow from operating activities. This requirement reduced cash flows from operating activities and increased cash flows from financing activities by $15.7 million for the year ended December 31, 2006. Total net cash flows were not impacted by the adoption of SFAS No. 123R.
83
Cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2006, 2005, and 2004, was $34.9 million, $25.0 million and $26.9 million, respectively. The actual tax benefits realized for tax deductions from share-based payment arrangements for the years ended December 31, 2006, 2005, and 2004, were $18.9 million, $28.0 million and $13.6 million, respectively.
The Company typically funds restricted share obligations from treasury stock at the date of grant and has a policy of issuing shares from treasury stock to satisfy option exercises.
Executive Performance Incentive Programs
In February 2005, the Compensation Committee of the Board of Directors adopted the 2005 Executive Performance Incentive Program (2005 Program) under the 1999 Long-Term Incentive Plan. The 2005 Program was established to provide additional incentive benefits to retain executive officers and certain other employees of the Company to further align the interests of the persons primarily responsible for the success of the Company with the interests of the shareholders. A total of 1,029,800 stock units granted under the 2005 Program are outstanding as of December 31, 2006. No additional units may be granted. The vesting of these stock units will occur on December 31, 2008, contingent upon a combination of the level of total shareholder return relative to the 29 peer companies identified below and the Companys average absolute return on total capital during the four-year performance period. As a result, zero to 2,574,500 units (250% of the units outstanding) may be distributed in cash or stock. The Company anticipates, based on current estimates, that a certain level of performance will be met and has expensed a ratable estimate of the units accordingly. The 2005 Program expense for the years ended December 31, 2006 and 2005 was $21.1 million and $22.5 million, respectively, and is classified as selling, general and administrative expense in the Statements of Consolidated Income. A portion of the 2005 Program expense is included as an unallocated expense in deriving total operating income for segment reporting purposes. See Note 2.
The current peer companies for the 2005 Program are as follows:
The vesting of performance-based stock units granted under the 2003 Executive Performance Incentive Program (2003 Program) occurred on December 30, 2005, after the ordinary close of the performance period and resulted in approximately 1.3 million units (167% of the award) being distributed in cash on that date. This payment totaled $51.0 million. The 2003 Program expense for the years ended December 31, 2005 and 2004 was $21.3 million and $19.2 million, respectively, and is classified as selling, general and administrative expense.
In the first quarter of 2005, the Company paid out the 552,000 performance-based stock units that vested December 31, 2004, under the Companys 2002 Executive Performance Incentive Program (2002 Program). This payment totaled $16.7 million. The 2002 Program expense for the year ended December 31, 2004 was $7.0 million and is classified as selling, general and administrative expense.
84
Restricted Stock Awards
The Company granted 112,700, 138,400, and 291,100 restricted stock awards during the years ended December 31, 2006, 2005, and 2004, respectively, to key executives of the Company. The majority of these awards will be fully vested at the end of the three-year period commencing the date of grant. The fair value of each share is determined based on the market price of the Companys common stock on the date of grant. The weighted average fair value of these restricted stock grants, based on the grant date fair value of the Companys stock, was $36.11, $33.07, and $21.88, for the years ended December 31, 2006, 2005, and 2004, respectively. The total fair value of restricted stock awards vested during the years ended December 31, 2006, 2005, and 2004 was $1.5 million, $1.8 million and $0.1 million, respectively. Compensation expense recorded by the Company related to restricted stock awards was $3.5 million, $3.4 million and $3.8 million for the years ended December 31, 2006, 2005, and 2004, respectively.
As of December 31, 2006, there was $5.3 million of total unrecognized compensation cost related to nonvested restricted stock awards. That cost is expected to be recognized over a weighted average period of approximately 10.1 months.
A summary of restricted stock activity as of December 31, 2006, and changes during the year then ended, is presented below:
Restricted Stock |
|
Non-
|
|
Weighted
|
|
Weighted
|
|
Aggregate
|
|
||
|
|
|
|
|
|
|
|
|
|
||
Outstanding at January 1, 2006 |
|
520,435 |
|
$ |
22.82 |
|
|
|
$ |
11,877,895 |
|
|
|
|
|
|
|
|
|
|
|
||
Granted |
|
112,700 |
|
$ |
36.11 |
|
|
|
$ |
4,069,115 |
|
|
|
|
|
|
|
|
|
|
|
||
Vested |
|
(77,115 |
) |
$ |
18.91 |
|
|
|
$ |
(1,458,367 |
) |
|
|
|
|
|
|
|
|
|
|
||
Forfeited |
|
(12,680 |
) |
$ |
28.86 |
|
|
|
$ |
(365,928 |
) |
|
|
|
|
|
|
|
|
|
|
||
Outstanding at December 31, 2006 |
|
543,340 |
|
$ |
25.99 |
|
10.1 |
|
$ |
14,122,715 |
|
85
Stock Options
The fair value of the Companys option grants was estimated at the dates of grant using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the years ended December 31, 2006, 2005, and 2004. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The dividend yield is based on the historical dividend yield of the Companys stock. Expected volatilities are based on historical volatility of the Companys stock. The expected term of options granted represents the period of time that options granted are expected to be outstanding based on historical option exercise experience.
|
|
Years Ended December 31, |
|
||||
|
|
2006 |
|
2005 |
|
2004 |
|
|
|
|
|
|
|
|
|
Risk-free interest rate |
|
4.51% to 5.04% |
|
3.74% to 4.34% |
|
1.95% to 4.34% |
|
Dividend yield |
|
2.34% to 2.38% |
|
2.75% to 2.83% |
|
2.47% to 2.97% |
|
Volatility factor |
|
.212 to .226 |
|
.258 to .262 |
|
.214 to .263 |
|
Expected term |
|
7 years |
|
7 years |
|
7 years |
|
The Company granted 84,935, 68,898, and 126,858 stock options during the years ended December 31, 2006, 2005, and 2004, respectively, all of which comprised options granted for reload rights associated with previously-awarded options. The weighted average grant date fair value of these reload option grants was $9.43, $7.65, and $4.94 for the years ended December 31, 2006, 2005, and 2004, respectively. The total intrinsic value of options exercised during the years ended December 31, 2006, 2005, and 2004 was $52.2 million, $48.1 million and $22.2 million, respectively.
As of December 31, 2006, there was no unrecognized compensation cost related to outstanding nonvested stock options as all outstanding options were fully vested.
A summary of option activity as of December 31, 2006, and changes during the year then ended, is presented below:
Nonqualified Stock Options |
|
Shares |
|
Weighted
|
|
Weighted
|
|
Aggregate
|
|
||
|
|
|
|
|
|
|
|
|
|
||
Outstanding at January 1, 2006 |
|
5,110,421 |
|
$ |
16.32 |
|
|
|
|
|
|
Granted |
|
84,935 |
|
$ |
37.61 |
|
|
|
|
|
|
Exercised |
|
(2,228,966 |
) |
$ |
16.41 |
|
|
|
|
|
|
Forfeited |
|
(4,716 |
) |
$ |
17.46 |
|
|
|
|
|
|
Outstanding at December 31, 2006 |
|
2,961,674 |
|
$ |
16.86 |
|
4.8 years |
|
$ |
73,727,195 |
|
Exercisable at December 31, 2006 |
|
2,961,674 |
|
$ |
16.86 |
|
4.8 years |
|
$ |
73,727,195 |
|
Nonemployee Directors Stock Incentive Plan
At December 31, 2006, 160,904 options were outstanding under the 1999 Nonemployee Directors Stock Incentive Plan at prices ranging from $6.59 to $29.67 per share, and 537,200 options had been exercised under this plan since plan inception. The exercise price for each award is equal to the market price of the Companys common stock on the date of grant. Each option is subject to time-based vesting provisions and expires 5 to 10 years after date of grant.
86
The Company has also historically granted to non-employee directors stock units which vested upon award. The value of the stock units will be paid in cash on the earlier of the directors death or retirement from the Companys Board of Directors. A total of 72,960 non-employee director stock units were outstanding as of December 31, 2006. A total of 18,000, 18,000, and 21,120 stock units were granted to non-employee directors during the years ended December 31, 2006, 2005, and 2004, respectively.
17. Fair Value of Financial Instruments
The carrying value of cash and cash equivalents, as well as short-term loans, approximates fair value due to the short maturity of the instruments. The fair value of the available-for-sale securities is estimated based on quoted market prices for those investments.
The estimated fair value of long-term debt described in Note 12 at December 31, 2006 and 2005 was $786.0 million and $816.8 million, respectively. The fair value was estimated based on discounted values using a current discount rate reflective of the remaining maturity.
The estimated fair value of liabilities for derivative instruments described in Note 3, excluding trading activities which are marked-to-market, was a $129.7 million asset and a $544.4 million liability at December 31, 2006, and a $36.0 million asset and a $1.2 billion liability at December 31, 2005.
18. Concentrations of Credit Risk
Revenues and related accounts receivable from the Equitable Supply segments operations are generated primarily from the sale of produced natural gas and limited amounts of crude oil to certain marketers, Equitable Energy, LLC (an affiliate), other Appalachian Basin purchasers and utility and industrial customers located mainly in the Appalachian area; the sale of produced natural gas liquids to a gas processor in Kentucky; and gathering of natural gas in Kentucky, Virginia, Pennsylvania and West Virginia.
Equitable Utilities distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 274,000 residential, commercial and industrial customers located in southwestern Pennsylvania, northern West Virginia and eastern Kentucky. The Pipeline operations include FERC-regulated interstate pipeline transportation and storage service for the affiliated utility, Equitable Gas Company (Equitable Gas), as well as other utility and end-user customers located in the northeastern United States. The unregulated marketing operations provide commodity procurement and delivery, physical natural gas management operations and control, and customer support services to energy consumers including large industrial, utility, commercial, institutional and certain marketers primarily in the Appalachian and mid-Atlantic regions.
Under previous state regulations, Equitable Gas was required to provide continuous natural gas service to residential customers during the winter heating season. The Responsible Utility Customer Protection Act (Act 201), which became effective in Pennsylvania on December 14, 2004, established new procedures for utilities regarding collection activities with respect to deposits, payment plans and terminations for residential customers and is intended to help utility companies collect amounts due from customers. As a result of Act 201, the Company is permitted to send winter termination notices to customers whose household income exceeds 250% of the federal poverty level and complete customer terminations without approval from the PA PUC.
Approximately 73% and 69% of the Companys accounts receivable balance as of December 31, 2006 and 2005, respectively, represent amounts due from marketers. The Company manages the credit risk of sales to marketers by limiting its dealings to those marketers who meet the Companys criteria for credit and liquidity strength and by proactively monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a marketer in order for that marketer to meet the Companys credit criteria. As a result, the Company did not experience any significant defaults on sales of natural gas to marketers during the years ended December 31, 2006 and 2005.
87
The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. NYMEX-traded futures contracts have minimal credit risk because futures exchanges are the counterparties. The Company manages the credit risk of the other derivative contracts by limiting dealings to those counterparties who meet the Companys criteria for credit and liquidity strength. Some of the Companys agreements with counterparties contain netting provisions in order to mitigate the Companys short-term and long-term exposure in the event of default.
The Company is not aware of any significant credit risks that have not been recognized in provisions for doubtful accounts.
19. Commitments and Contingencies
The Company has annual commitments of approximately $37.8 million for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to ten years as of December 31, 2006, which relate to natural gas distribution and production operations. However, the Company believes that approximately $26.4 million of these costs are recoverable in customer rates.
In the ordinary course of business, various legal claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves for pending litigation, which it believes are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company.
In June 2006, the West Virginia Supreme Court of Appeals issued a decision involving interpretation of certain types of oil and gas leases of an unrelated party, in which a class of royalty owners in the state of West Virginia filed a lawsuit claiming that the defendant in the case underpaid royalties by deducting certain post-production costs not permitted by such types of leases and not paying a fair value for the gas produced from the royalty owners leases. In January 2007, the jury in the aforementioned case returned a verdict in favor of the plaintiff royalty owners, awarding the plaintiffs significant compensatory and punitive damages for the alleged underpayment of royalties. While the defendant plans to appeal the verdict, this decision may ultimately impact other royalty interest rights in West Virginia. Claims have been brought against others in the oil and gas industry, including the Company. The actions against the Company are in the early stages of proceedings. The Company believes that the claims and facts decided in the unrelated lawsuit can be differentiated from those asserted against the Company. Nevertheless, the Company has reviewed its West Virginia royalty agreements and established a reserve it believes to be appropriate.
The Company is subject to various federal, state and local environmental and environmentally related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, certain costs are deferred as regulatory assets when recoverable through regulated rates. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Companys financial position or results of operations. The Company has identified situations that require remedial action for which approximately $1.8 million is included in other credits in the Consolidated Balance Sheet as of December 31, 2006.
Operating lease rentals for office locations and warehouse buildings, as well as a limited amount of equipment, amounted to approximately $6.0 million in 2006, $4.9 million in 2005 and $4.2 million in 2004. Future lease payments under non-cancelable operating leases as of December 31, 2006 totaled $56.0 million (2007 - $6.8
88
million, 2008 - $6.0 million, 2009 - $4.3 million, 2010 - $3.7 million, 2011 - $2.4 million and thereafter - $32.8 million).
20. Guarantees
NORESCO Guarantees
In connection with the sale of its NORESCO domestic operations in December 2005, the Company agreed to maintain in place guarantees of certain of NORESCOs obligations previously issued to the purchasers of NORESCOs receivables. The guaranteed obligations of NORESCO include certain receivable sales and customer contracts, for which the undiscounted maximum aggregate payments that may be due is approximately $361 million as of December 31, 2006, extending at a decreasing amount for approximately 20 years. In addition, the Company agreed to maintain in place certain outstanding payment and performance bonds, letters of credit and other guarantee obligations supporting NORESCOs obligations under certain customer contracts, existing leases and other items with an undiscounted maximum exposure to the Company as of December 31, 2006 of approximately $123 million, of which approximately $107 million relates to work already completed under the associated contracts. In addition, approximately $116 million of these guarantee obligations will end or be terminated not later than December 30, 2010.
In exchange for the Companys agreement to maintain these guarantee obligations, the purchaser of the NORESCO business and NORESCO agreed, among other things, that NORESCO would fully perform its obligations under each underlying agreement and agreed to reimburse the Company for any loss under the guarantee obligations, provided that the purchasers reimbursement obligation will not exceed $6 million in the aggregate and will expire on November 18, 2014.
The Company has determined that the likelihood it will be required to perform on these arrangements is remote and has not recorded any liabilities in its Consolidated Balance Sheet related to these guarantees.
Other Guarantees
In November 1995, Equitable, through a subsidiary, guaranteed a tax indemnification to the limited partners of Appalachian Basin Partners, LP (ABP) for any potential tax losses resulting from a disallowance of the nonconventional fuels tax credits, if certain representations and warranties of the Company were not true. The Company guaranteed the tax indemnification until the tax statute of limitations closes. The Company does not have any recourse provisions with third parties or any collateral held by third parties associated with this guarantee that could be liquidated to recover amounts paid, if any, under the guarantee. As of December 31, 2006, the maximum potential amount of future payments the Company could be required to make is estimated to be approximately $46 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN 45, and has not been modified subsequent to issuance. Additionally, based on the status of the Companys IRS examinations, the Company has determined that any potential loss from this guarantee is remote.
In June 2000, Equitable sold certain properties and, through a subsidiary, guaranteed a tax indemnification to the buyer for any potential tax losses resulting from a disallowance of the nonconventional fuels tax credits, if certain representations and warranties of the Company were not true. The Company guaranteed the tax indemnification until the tax statute of limitations closed. The Company had not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN 45 and had not been modified subsequent to issuance. During 2006, the statue of limitations relating to the years in which the tax indemnification applied elapsed and as such, the Company no longer has any potential obligation under this guarantee.
In December 2000, the Company entered into a transaction with ANGT by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. ANGT manages the assets and produces, markets, and sells the related natural gas from the properties. Appalachian NPI, LLC (ANPI) contributed cash to ANGT. The assets of ANPI, including its interest in ANGT, collateralize ANPIs debt. The Company
89
provided ANPI with a liquidity reserve guarantee secured by the fair market value of the assets purchased by ANGT. This guarantee is subject to certain restrictions that limit the amount of the guarantee to the calculated present value of the projects future cash flows from the preceding year-end until the termination date of the agreement. The agreement also defines events of default, use of proceeds and demand procedures. The Company has received a market-based fee for providing the guarantee. As of December 31, 2006, the maximum potential amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be approximately $50 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN 45 and has not been modified subsequent to issuance.
21. Office Consolidation / Impairment Charges
In May 2005, the Company completed the relocation of its corporate headquarters and other operations to a newly constructed office building located at the North Shore in Pittsburgh. The relocation resulted in the early termination of several operating leases and the early retirement of assets and leasehold improvements at several locations. In accordance with SFAS No. 146, the Company recognized a loss of $5.3 million on the early termination of operating leases during 2005 for facilities deemed to have no economic benefit to the Company. The Company also recognized a loss on the impairment of assets of $2.5 million during 2005 in accordance with SFAS No. 144 associated with the office consolidations.
During the second quarter of 2006, the Company began to utilize certain of the leased space previously deemed to have no economic benefit to the Company to make space available for the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. transition planning activities. The Company reversed approximately $2.4 million of the associated early termination liability for these leases during the second quarter of 2006. Additionally, the Company recorded a $0.5 million reduction in the early termination liability during the second quarter of 2006 resulting from a revision of the amount of estimated cash flows for one of its operating leases.
22. Other Items
In June 2004, the Company amended its only remaining prepaid natural gas contract, which was viewed as debt by the rating agencies. The amendment required the Company to repay the net present value of the portion of the prepayment related to the undelivered quantities of natural gas in the original contract. The Company repaid the counterparty $36.8 million, removed the prepaid forward sale from the balance sheet and recorded a loss of $5.5 million in other income, net in the Statement of Consolidated Income for the year ended December 31, 2004, reflecting the difference between the net present value of the underlying quantities and the remaining unamortized balance recorded as deferred revenue.
In 2004, the Company settled a disputed property insurance coverage claim involving Kentucky West Virginia Gas Company, LLC, which is a part of the Equitable Supply operating segment. As a result of the settlement, the Company recognized income of approximately $6.1 million in 2004, which is included in other income, net, in the Statement of Consolidated Income for the year ended December 31, 2004.
90
23. Interim Financial Information (Unaudited)
The following quarterly summary of operating results reflects variations due primarily to the seasonal nature of the Companys utility business and volatility of natural gas and oil commodity prices. The 2005 quarterly results have been reclassified to reflect the Companys NORESCO business segment as discontinued operations for each period presented.
|
|
March 31 |
|
June 30 |
|
September 30 |
|
December 31 |
|
||||
|
|
(Thousands, except per share amounts) |
|
||||||||||
2006 (a) |
|
|
|
|
|
|
|
|
|
||||
Operating revenues |
|
$ |
430,119 |
|
$ |
251,207 |
|
$ |
232,801 |
|
$ |
353,783 |
|
Net operating revenues |
|
221,302 |
|
165,094 |
|
160,646 |
|
216,539 |
|
||||
Operating income |
|
127,657 |
|
74,119 |
|
61,135 |
|
109,612 |
|
||||
Income from continuing operations |
|
72,359 |
|
43,909 |
|
31,795 |
|
67,962 |
|
||||
Income from discontinued operations, net of tax |
|
|
|
|
|
|
|
4,261 |
|
||||
Net income |
|
72,359 |
|
43,909 |
|
31,795 |
|
72,223 |
|
||||
Earnings per share of common stock: |
|
|
|
|
|
|
|
|
|
||||
Income from continuing operations |
|
|
|
|
|
|
|
|
|
||||
Basic |
|
$ |
0.61 |
|
$ |
0.37 |
|
$ |
0.26 |
|
$ |
0.56 |
|
Diluted |
|
$ |
0.59 |
|
$ |
0.36 |
|
$ |
0.26 |
|
$ |
0.56 |
|
Income from discontinued operations, net of tax |
|
|
|
|
|
|
|
|
|
||||
Basic |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
0.04 |
|
Diluted |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
0.03 |
|
Net income |
|
|
|
|
|
|
|
|
|
||||
Basic |
|
$ |
0.61 |
|
$ |
0.37 |
|
$ |
0.26 |
|
$ |
0.60 |
|
Diluted |
|
$ |
0.59 |
|
$ |
0.36 |
|
$ |
0.26 |
|
$ |
0.59 |
|
91
|
|
March 31 |
|
June 30 |
|
September 30 |
|
December 31(b) |
|
||||
|
|
(Thousands, except per share amounts) |
|
||||||||||
2005 (a) |
|
|
|
|
|
|
|
|
|
||||
Operating revenues |
|
$ |
401,276 |
|
$ |
230,194 |
|
$ |
229,372 |
|
$ |
392,882 |
|
Net operating revenues |
|
212,545 |
|
154,277 |
|
163,416 |
|
212,317 |
|
||||
Operating income |
|
127,196 |
|
53,459 |
|
54,689 |
|
108,468 |
|
||||
Income from continuing operations |
|
74,791 |
|
57,953 |
|
45,811 |
|
80,019 |
|
||||
Income (loss) from discontinued operations, net of tax |
|
1,615 |
|
6,366 |
|
680 |
|
(7,180 |
) |
||||
Net income |
|
76,406 |
|
64,319 |
|
46,491 |
|
72,839 |
|
||||
Earnings per share of common stock: |
|
|
|
|
|
|
|
|
|
||||
Income from continuing operations |
|
|
|
|
|
|
|
|
|
||||
Basic |
|
$ |
0.62 |
|
$ |
0.48 |
|
$ |
0.37 |
|
$ |
0.67 |
|
Diluted |
|
$ |
0.60 |
|
$ |
0.47 |
|
$ |
0.37 |
|
$ |
0.65 |
|
Income (loss) from discontinued operations, net of tax |
|
|
|
|
|
|
|
|
|
||||
Basic |
|
$ |
0.01 |
|
$ |
0.05 |
|
$ |
0.01 |
|
$ |
(0.06 |
) |
Diluted |
|
$ |
0.01 |
|
$ |
0.05 |
|
$ |
0.01 |
|
$ |
(0.06 |
) |
Net income |
|
|
|
|
|
|
|
|
|
||||
Basic |
|
$ |
0.63 |
|
$ |
0.53 |
|
$ |
0.38 |
|
$ |
0.61 |
|
Diluted |
|
$ |
0.61 |
|
$ |
0.52 |
|
$ |
0.38 |
|
$ |
0.59 |
|
(a) The sum of the quarterly data in some cases may not equal the yearly total due to rounding.
(b) Amounts for the quarter ended December 31, 2005, include an adjustment of $10.6 million to operating revenues in the Companys Equitable Supply segment principally due to the Companys conclusion that the well-head sales price allocated to a third partys working interest gas in previous periods may have been lower than the Company was obligated to pay.
92
24. Natural Gas Producing Activities (Unaudited)
The supplementary information summarized below presents the results of natural gas and oil activities for the Equitable Supply segment in accordance with SFAS No. 69.
Production Costs
The following table presents the costs incurred relating to natural gas and oil production activities:
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
At December 31: |
|
|
|
|
|
|
|
|||
Capitalized costs |
|
$ |
1,752,222 |
|
$ |
1,551,677 |
|
$ |
1,396,899 |
|
Accumulated depreciation and depletion |
|
566,118 |
|
518,426 |
|
488,742 |
|
|||
Net capitalized costs |
|
$ |
1,186,104 |
|
$ |
1,033,251 |
|
$ |
908,157 |
|
Costs incurred: |
|
|
|
|
|
|
|
|||
Property acquisition: |
|
|
|
|
|
|
|
|||
Proved properties |
|
$ |
|
|
$ |
57,500 |
|
$ |
|
|
Unproved properties |
|
|
|
|
|
|
|
|||
Land and leasehold maintenance |
|
802 |
|
768 |
|
846 |
|
|||
Development (a) |
|
192,578 |
|
132,317 |
|
91,489 |
|
(a) Amounts include $57.2 million, $65.2 million and $49.7 million of costs incurred during 2006, 2005 and 2004, respectively, to develop the Companys proved undeveloped reserves. The Company estimates that its future total development costs will be comprised of a similar percentage of costs incurred to develop the Companys proved undeveloped reserves.
Results of Operations for Producing Activities
The following table presents the results of operations related to natural gas and oil production:
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
Revenues: |
|
|
|
|
|
|
|
|||
Affiliated |
|
$ |
14,879 |
|
$ |
11,856 |
|
$ |
10,599 |
|
Nonaffiliated |
|
362,747 |
|
378,434 |
|
305,387 |
|
|||
Production costs |
|
63,273 |
|
61,483 |
|
43,274 |
|
|||
Depreciation and depletion |
|
53,471 |
|
49,281 |
|
41,275 |
|
|||
Income tax expense |
|
99,135 |
|
106,220 |
|
87,946 |
|
|||
Results of operations from producing activities (excluding corporate overhead) |
|
$ |
161,747 |
|
$ |
173,306 |
|
$ |
143,491 |
|
93
Reserve Information
The information presented below represents estimates of proved natural gas and oil reserves prepared by Company engineers, which was reviewed by the independent consulting firm of Ryder Scott Company L.P. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred. All of the Companys proved reserves are in the United States.
|
|
2006 |
|
2005 |
|
2004 |
|
|
|
(Millions of Cubic Feet) |
|
||||
|
|
|
|
|
|
|
|
Natural Gas |
|
|
|
|
|
|
|
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
Beginning of year |
|
2,359,200 |
|
2,102,539 |
|
2,064,126 |
|
Revision of previous estimates |
|
(20,255 |
) |
288,590 |
|
56,392 |
|
Purchase of natural gas in place |
|
|
|
19,159 |
|
|
|
Sale of natural gas in place |
|
( 1,418 |
) |
( 57,700 |
) |
|
|
Extensions, discoveries and other additions (a) |
|
230,716 |
|
84,717 |
|
54,247 |
|
Production |
|
(80,698 |
) |
(78,105 |
) |
(72,226 |
) |
End of year |
|
2,487,545 |
|
2,359,200 |
|
2,102,539 |
|
Proved developed reserves: |
|
|
|
|
|
|
|
Beginning of year |
|
1,666,990 |
|
1,625,295 |
|
1,580,474 |
|
End of year |
|
1,715,775 |
|
1,666,990 |
|
1,625,295 |
|
|
|
2006 |
|
2005 |
|
2004 |
|
|
|
(Thousands of Bbls) |
|
||||
Oil |
|
|
|
|
|
|
|
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
Beginning of year |
|
1,008 |
|
1,019 |
|
550 |
|
Revision of previous estimates |
|
739 |
|
112 |
|
552 |
|
Purchase of oil in place |
|
|
|
38 |
|
|
|
Sale of oil in place |
|
|
|
(53 |
) |
|
|
Production |
|
(112 |
) |
(108 |
) |
(83 |
) |
End of year |
|
1,635 |
|
1,008 |
|
1,019 |
|
Proved developed reserves: |
|
|
|
|
|
|
|
Beginning of year |
|
1,008 |
|
1,019 |
|
550 |
|
End of year |
|
1,635 |
|
1,008 |
|
1,019 |
|
(a) Includes 59,374 MMcf, 29,995 MMcf and 17,246 MMcf of proved developed reserve extensions, discoveries and other additions during 2006, 2005 and 2004, respectively, which were not previously classified as proved undeveloped. The remaining balance represents additional proved undeveloped reserves.
94
Standard Measure of Discounted Future Cash Flow
Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.
Estimated future net cash flows from natural gas and oil reserves based on selling prices and costs at year-end price levels are as follows:
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
Future cash inflows (a) |
|
$ |
13,260,521 |
|
$ |
28,122,308 |
|
$ |
17,312,818 |
|
Future production costs |
|
(2,738,366 |
) |
(3,939,210 |
) |
(2,465,681 |
) |
|||
Future development costs |
|
(989,549 |
) |
(791,539 |
) |
(409,141 |
) |
|||
Future net cash flow before income taxes |
|
9,532,606 |
|
23,391,559 |
|
14,437,996 |
|
|||
10% annual discount for estimated timing of cash flows |
|
(6,539,463 |
) |
(15,789,506 |
) |
(9,736,734 |
) |
|||
Discounted future net cash flows before income taxes |
|
2,993,143 |
|
7,602,053 |
|
4,701,262 |
|
|||
Future income tax expenses, discounted at 10% annually |
|
(1,137,394 |
) |
(2,609,025 |
) |
(1,740,878 |
) |
|||
Standardized measure of discounted future net cash flows |
|
$ |
1,855,749 |
|
$ |
4,993,028 |
|
$ |
2,960,384 |
|
(a) The majority of the Companys production is sold through liquid trading points on interstate pipelines. Accordingly, the price of gas on these pipelines was determined using the year-end prices published in the December 29, 2006 edition of Platts Gas Daily (Columbia Gas Transmission Corp. 2006 year-end price was $5.625/Dth; Dominion Transmission, Inc. 2006 year-end price was $5.765/Dth).
Summary of changes in the standardized measure of discounted future net cash flows:
|
|
2006 |
|
2005 |
|
2004 |
|
|||
|
|
(Thousands) |
|
|||||||
Sales and transfers of natural gas and oil produced net |
|
$ |
(315,132 |
) |
$ |
(329,575 |
) |
$ |
(273,558 |
) |
Net changes in prices, production and development costs |
|
(5,710,391 |
) |
1,434,642 |
|
1,746,284 |
|
|||
Extensions, discoveries and improved recovery, less related costs |
|
276,804 |
|
272,419 |
|
121,051 |
|
|||
Development costs incurred |
|
110,023 |
|
76,694 |
|
68,688 |
|
|||
Purchase of minerals in place net |
|
|
|
62,341 |
|
|
|
|||
Sale of minerals in place net |
|
(4,560 |
) |
(129,466 |
) |
|
|
|||
Revisions of previous quantity estimates |
|
(18,977 |
) |
911,986 |
|
131,142 |
|
|||
Accretion of discount |
|
759,813 |
|
457,225 |
|
263,166 |
|
|||
Net change in income taxes |
|
1,471,631 |
|
(868,147 |
) |
(819,792 |
) |
|||
Other |
|
293,510 |
|
144,525 |
|
12,816 |
|
|||
Net increase |
|
(3,137,279 |
) |
2,032,644 |
|
1,249,797 |
|
|||
Beginning of year |
|
4,993,028 |
|
2,960,384 |
|
1,710,587 |
|
|||
End of year |
|
$ |
1,855,749 |
|
$ |
4,993,028 |
|
$ |
2,960,384 |
|
95
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of management, including the Companys Principal Executive Officer and Principal Financial Officers, an evaluation of the Companys disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act), was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officers concluded that the Companys disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Control over Financial Reporting
There were no changes in internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act that occurred during the fourth quarter of 2006 that have materially affected, or are reasonably likely to materially affect, the Companys internal control over financial reporting.
Managements Report on Internal Control over Financial Reporting
The management of Equitable is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)). Equitables internal control system is designed to provide reasonable assurance to the Companys management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.
Equitables management assessed the effectiveness of the Companys internal control over financial reporting as of December 31, 2006. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework . Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2006.
Managements assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, has been audited by Ernst & Young, LLP, the independent registered public accounting firm that also audited the Companys Consolidated Financial Statements. Ernst & Youngs attestation report on managements assessment of the Companys internal control over financial reporting appears in Part II, Item 8 of this Annual Report on Form 10-K and is incorporated by reference herein.
Through the certification of this Form 10-K, the Company has had co-principal financial officers, Philip P. Conti, the Vice President and Chief Financial Officer, and David L. Porges, the Executive Vice President, Finance and Administration. Effective January 31, 2006, Mr. Conti assumed responsibility for the accounting and financial reporting functions, and continued his responsibility for the treasury, business development, planning and risk management functions. Through the certification of this Form 10-K, Mr. Conti reported to Mr. Porges, who had oversight responsibility for finance, human resources, legal, information technology, and environmental and safety compliance. Mr. Conti and Mr. Porges collaborated with respect to the Companys financial reporting. Both co-principal financial officers assessed the effectiveness of the Companys internal control over financial reporting as of December 31, 2006 as described above and have made the certifications required by Item 601(b)(31) and (32) of Regulation S-K under the Exchange Act which are attached to this Form 10-K as Exhibits 31.2 and 31.3, and 32, respectively. Effective February 21, 2007, Equitable realigned its senior management organization. As a consequence of that reorganization, Mr. Conti, who will no longer report to Mr. Porges, will be the Companys sole principal financial officer on a going forward basis.
96
Not Applicable.
Item 10. Directors, Executive Officers and Corporate Governance
The following information is incorporated herein by reference from the Companys definitive proxy statement relating to the annual meeting of the shareholders to be held on April 11, 2007, which will be filed with the Commission within 120 days after the close of the Companys fiscal year ended December 31, 2006:
· Information required by Item 401 of Regulation S-K with respect to directors is incorporated herein by reference from the Companys definitive proxy statement;
· Information required by Item 405 of Regulation S-K with respect to compliance with Section 16(a) of the Exchange Act is incorporated by reference from the section captioned Stock Ownership and Performance Section 16(a) Beneficial Ownership Reporting Compliance in the Companys definitive proxy statement;
· Information required by Item 407(c)(3) of Regulation S-K with respect to disclosure of related person transactions is incorporated by reference from the section captioned Corporate Governance Certain Relationships and Related Transactions in the Companys definitive proxy statement.
· Information required by Item 407(d)(4) of Regulation S-K with respect to disclosure of the existence of the Companys standing Audit Committee and the identification of the members of the Audit Committee is incorporated by reference from the section captioned Meetings of the Board of Directors and Committee Membership-Audit Committee in the Companys definitive proxy statement.
· Information required by Item 407(d)(5) of Regulation S-K with respect to disclosure of audit committee financial expert is incorporated herein by reference from the section captioned Meetings of the Board of Directors and Committee Membership-Audit Committee in the Companys definitive proxy statement; and
Information required by Item 401 of Regulation S-K with respect to executive officers is included after Item 4 at the end of Part I of this Form 10-K under the heading Executive Officers of the Registrant (as of February 21, 2007), and is incorporated herein by reference.
The Company has adopted a code of ethics applicable to all directors and employees, including the principal executive officer, principal financial officers and principal accounting officer. The code of ethics is posted on the Companys website, http://www.eqt.com (under the Corporate Governance caption of the Investor Relations page) and a printed copy will be delivered to anyone who requests one by writing to the corporate secretary at Equitable Resources, Inc., c/o corporate secretary, 225 North Shore Drive, Pittsburgh, Pennsylvania 15212. The Company intends to satisfy the disclosure requirement regarding certain amendments to, or waivers from, provisions of its code of ethics by posting such information on the Companys website.
On December 6, 2006, the Board of Directors of the Company, upon recommendation of the Corporate Governance Committee, approved amendments to the By-Laws of the Company by adding a requirement that each director nominee deliver to the Company, prior to nomination, an irrevocable conditional resignation from the Board to be effective upon the receipt of more withhold votes than for votes in an uncontested election and the acceptance of such resignation by the Board. The determination of whether to accept a resignation will be made by the Board, without the participation of the resigning Director, after receiving a recommendation of the Corporate Governance Committee. The Board of Directors explanation of its decision shall be promptly disclosed on a Form 8-K. The new requirements are set forth in Section 3.10 of the By-Laws. The Directors also approved conforming changes to Section 3.07 of the Companys By-Laws.
97
By certification dated May 10, 2006, the Companys Chief Executive Officer certified to the New York Stock Exchange (NYSE) that he was not aware of any violation by the Company of NYSE corporate governance listing standards.
Item 11. Executive Compensation
Information required by Item 11 is incorporated herein by reference from the sections captioned Corporate Governance - Compensation Committee Interlocks and Insider Participation, Directors Compensation, Executive Compensation, and Report of the Compensation Committee in the Companys definitive proxy statement relating to the annual meeting of shareholders to be held on April 11, 2007, which will be filed with the Commission within 120 days after the close of the Companys fiscal year ended December 31, 2006.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by Item 403 of Regulation S-K with respect to stock ownership of significant shareholders, directors and executive officers is incorporated herein by reference to the sections captioned Stock Ownership and Performance - Significant Shareholders and Stock Ownership and Performance - Stock Ownership of Directors and Executive Officers in the Companys definitive proxy statement relating to the annual meeting of shareholders to be held on April 11, 2007, which will be filed with the Commission within 120 days after the close of the Companys fiscal year ended December 31, 2006.
98
The following table provides information as of December 31, 2006 with respect to shares of Equitable common stock that may be issued under the companys existing equity compensation plans, including the 1999 Long-Term Incentive Plan, the 1999 Non-Employee Directors Stock Incentive Plan, the Directors Deferred Compensation Plan, the 2005 Directors Deferred Compensation Plan and the Employee Stock Purchase Plan.
Plan Category |
|
Number Of
|
|
Weighted
|
|
Number Of
|
|
|
Equity Compensation Plans Approved by Shareholders (1) |
|
1,011,870 |
(3) |
$ |
13.88 |
(3) |
4,174,428 |
|
Equity Compensation Plans Not Approved by Shareholders (2) |
|
2,025,475 |
|
$ |
17.72 |
|
5,918,546 |
|
Total |
|
3,037,345 |
(3) |
$ |
16.44 |
(3) |
10,092,974 |
|
(1) Includes the 1999 Long-Term Incentive Plan, except for those shares issuable from treasury shares under the May 17, 2001 amendment to the plan, the 1999 Non-Employee Directors Stock Incentive Plan and the Employee Stock Purchase Plan.
(2) Includes 70,835 shares issuable under the Directors Deferred Compensation Plan in connection with a 1999 phantom stock grant payable in common stock of Equitable Resources, and shares issuable from treasury shares under the May 17, 2001 amendment to the 1999 Long-Term Incentive Plan, which was implemented without shareholder approval in compliance with the rules and regulations of the New York Stock Exchange and the Securities and Exchange Commission as then in effect. The 2005 Directors Deferred Compensation Plan and the Directors Deferred Compensation Plan are described below.
(3) Excludes purchase rights accruing under the Employee Stock Purchase Plan, which has a 2,000,000 share shareholder-approved maximum of which 1,712,862 shares remain available for issuance.
2005 Directors Deferred Compensation Plan
The 2005 Directors Deferred Compensation Plan was adopted by the Compensation Committee of the Board of Directors, effective January 1, 2005. The plan was amended on December 15, 2005 to allow the plan to continue into 2006 and thereafter. Neither the original adoption of the plan nor its amendment required approval by shareholders. The plan allows non-employee directors to defer all or a portion of their directors fees and retainer. Amounts deferred are payable upon retirement from the Board unless an early payment is authorized after the director suffers an unforeseeable financial emergency. In addition to deferred directors fees and retainers, the deferred stock units granted to directors on or after January 1, 2005 under the 1999 Non-Employee Directors Stock Incentive Plan are administered under this plan.
Directors Deferred Compensation Plan
The Directors Deferred Compensation Plan was suspended as of December 31, 2004. After December 31, 2004, the Directors Deferred Compensation Plan continues to operate for the sole purpose of administering vested amounts deferred under the plan on or prior to December 31, 2004. Deferred amounts are generally payable upon retirement from the Board, but may be payable earlier if an early payment is authorized after a director suffers an unforeseeable financial emergency. In addition to deferred directors fees and retainers and the one-time grant of
99
phantom shares in 1999, the deferred stock units granted to directors and vested prior to January 1, 2005 under the 1999 Non-Employee Directors Stock Incentive Plan are administered under this plan.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by Item 13 is incorporated herein by reference to the sections captioned Corporate Governance - Director Independence and Corporate Governance - Certain Relationships and Related Transactions in the Companys definitive proxy statement relating to the annual meeting of shareholders to be held on April 11, 2007, which will be filed with the Commission within 120 days after the close of the Companys fiscal year ended December 31, 2006.
Item 14. Principal Accounting Fees and Services
Information required by Item 14 is incorporated herein by reference to the section captioned Item No. 2 Ratification of Appointment of Independent Registered Public Accounting Firm in the Companys definitive proxy statement relating to the annual meeting of stockholders to be held on April 11, 2007, which will be filed with the Commission within 120 days after the close of the Companys fiscal year ended December 31, 2006.
100
Item 15. Exhibits, Financial Statement Schedules
(a) |
1. |
Financial Statements |
|
|
The financial statements listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K. |
|
|
|
|
2. |
Financial Statement Schedule |
|
|
The financial statement schedule listed in the accompanying index to financial statements and financial schedule is filed as part of this Annual Report on Form 10-K. |
|
|
|
|
3. |
Exhibits |
|
|
The exhibits listed on the accompanying index to exhibits (pages 103 through 108) are filed as part of this Annual Report on Form 10-K. |
EQUITABLE RESOURCES, INC.
INDEX TO FINANCIAL STATEMENTS COVERED
BY REPORT OF INDEPENDENT REGISTERED
Item 15 (a)
1. The following Consolidated Financial Statements of Equitable Resources, Inc. and Subsidiaries are included in Item 8:
All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.
101
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 2006
Column A |
|
Column B |
|
Column C |
|
Column D |
|
Column E |
|
|||||||
Description |
|
Balance at
|
|
Additions
|
|
Additions
|
|
Deductions
|
|
Balance at
|
|
|||||
|
|
(Thousands) |
|
|||||||||||||
2006 |
|
|
|
|
|
|
|
|
|
|
|
|||||
Accumulated provisions for doubtful accounts |
|
$ |
23,329 |
|
$ |
4,715 |
|
$ |
4,589 |
|
$ |
12,191 |
|
$ |
20,442 |
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|||||
Accumulated provisions for doubtful accounts |
|
$ |
29,836 |
|
$ |
8,273 |
|
$ |
5,176 |
|
$ |
19,956 |
|
$ |
23,329 |
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|||||
Accumulated provisions for doubtful accounts |
|
$ |
16,153 |
|
$ |
19,659 |
|
$ |
3,332 |
|
$ |
9,308 |
|
$ |
29,836 |
|
Note:
(a) Energy Assistance Program surcharge included in residential rates.
(b) Customer accounts written off, less recoveries.
102
Exhibits |
|
Description |
|
Method of Filing |
2.01 |
|
Stock Purchase Agreement dated as of March 1, 2006 by and between Equitable Resources, Inc. and Consolidated Natural Gas Company. Schedules (or similar attachments) to the Stock Purchase Agreement are not filed. The Registrant will furnish supplementally a copy of any omitted schedule to the Commission upon request. |
|
Filed as Exhibit 2.1 to Form 8-K filed on March 3, 2006 |
3.01 |
|
Restated Articles of Incorporation (amended through July 18, 2005) |
|
Filed as Exhibit 3.01 to Form 8-K filed on July 18, 2005 |
3.02 |
|
By-Laws of Equitable Resources, Inc. (amended through February 21, 2007) |
|
Filed as Exhibit 3.1 to Form 8-K filed on February 23, 2007 |
4.01 (a) |
|
Indenture dated as of April 1, 1983 between the Company and Pittsburgh National Bank |
|
Filed as Exhibit 4.1 to Registration Statement on Form S-3 filed April 24, 1986 (Registration No. 2-80575) |
4.01 (b) |
|
Instrument appointing Bankers Trust Company as successor trustee to Pittsburgh National Bank |
|
Filed as Exhibit 4.01 (b) to Form 10-K for the year ended December 31, 1998 |
4.01 (c) |
|
Supplemental Indenture dated March 15, 1991 with Bankers Trust Company eliminating limitations on liens and additional funded debt |
|
Filed as Exhibit 4.01 (f) to Form 10-K for the year ended December 31, 1996 |
4.01 (d) |
|
Resolution adopted August 19, 1991 by the Ad Hoc Finance Committee of the Board of Directors of the Company Addenda Nos. 1 through 27, establishing the terms and provisions of the Series A Medium-Term Notes |
|
Filed as Exhibit 4.01 (g) to Form 10-K for the year ended December 31, 1996 |
4.01 (e) |
|
Resolutions adopted July 6, 1992 and February 19, 1993 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 through 8, establishing the terms and provisions of the Series B Medium-Term Notes |
|
Filed as Exhibit 4.01 (h) to Form 10-K for the year ended December 31, 1997 |
4.01 (f) |
|
Resolution adopted July 14, 1994 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 and 2, establishing the terms and provisions of the Series C Medium-Term Notes |
|
Filed as Exhibit 4.01 (i) to Form 10-K for the year ended December 31, 1995 |
4.02 (a) |
|
Indenture with The Bank of New York, as successor to Bank of Montreal Trust Company, a Trustee, dated as of July 1, 1996 |
|
Filed as Exhibit 4.01 (a) to Form S-4 Registration Statement (#333-103178) filed on February 13, 2003 |
4.02 (b) |
|
Resolution adopted January 18 and July 18, 1996 by the Board of Directors of the Company and Resolutions adopted July 18, 1996 by the Executive Committee of the Board of Directors of the Company, establishing the terms and provisions of the 7.75% Debentures issued July 29, 1996 |
|
Filed as Exhibit 4.01 (j) to Form 10-K for the year ended December 31, 1996 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).
103
INDEX TO EXHIBITS
Exhibits |
|
Description |
|
Method of Filing |
4.02 (c) |
|
Officers Declaration dated February 20, 2003 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000 |
|
Filed as Exhibit 4.01 (c) to Form S-4 Registration Statement (#333-104392) filed on April 8, 2003 |
4.02 (d) |
|
Officers Declaration dated November 7, 2002 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000 |
|
Filed as Exhibit 4.01 (c) to Form S-4/A Registration Statement (#333-103178) filed on March 12, 2003 |
4.02 (e) |
|
Officers Declaration dated September 27, 2005 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of $150,000,000 |
|
Filed as Exhibit 4.01 (b) to Form S-4 Registration Statement (#333-104392) filed on October 28, 2005 |
* 10.01 (a) |
|
1999 Equitable Resources, Inc. Long-Term Incentive Plan (amended and restated October 20, 2004) |
|
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2004 |
* 10.01 (b) |
|
2007 Form of Participant Award Agreement (Restricted Stock) under 1999 Equitable Resources, Inc. Long-Term Incentive Plan |
|
Filed herewith as Exhibit 10.01 (b) |
* 10.01 (c) |
|
Form of Participant Award Agreement (Restricted Stock) under 1999 Equitable Resources, Inc. Long-Term Incentive Plan |
|
Filed as Exhibit 10.05 to Form 10-K for the year ended December 31, 2004 |
* 10.01 (d) |
|
Form of Participant Award Agreement (Stock Option) under 1999 Equitable Resources, Inc. Long-Term Incentive Plan |
|
Filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2004 |
* 10.01 (e) |
|
Equitable Resources, Inc. 2002 Executive Performance Incentive Program (as amended and restated May 1, 2003 and April 13, 2004) |
|
Filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2004 |
* 10.01 (f) |
|
Form of Participant Award Agreement under the Equitable Resources, Inc. 2002 Executive Performance Incentive Program |
|
Filed as Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2004 |
* 10.01 (g) |
|
Equitable Resources, Inc. 2003 Executive Performance Incentive Program (as amended and restated April 13, 2004) |
|
Filed as Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2004 |
* 10.01 (h) |
|
Form of Participant Award Agreement under the Equitable Resources, Inc. 2003 Executive Performance Incentive Program |
|
Filed as Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2004 |
* 10.01 (i) |
|
Equitable Resources, Inc. 2005 Executive Performance Incentive Program |
|
Filed as Exhibit 10.01 to Form 8-K filed on March 1, 2005 |
* 10.01 (j) |
|
Form of Participant Award Agreement under the Equitable Resources, Inc. 2005 Executive Performance Incentive Program |
|
Filed as Exhibit 10.02 to Form 8-K filed on March 1, 2005 |
* 10.02 |
|
1994 Equitable Resources, Inc. Long-Term Incentive Plan |
|
Field as Exhibit 10.06 to Form 10-K for the year ended December 31, 1999 |
* 10.03 |
|
Equitable Resources, Inc. Breakthrough Long-Term Incentive Plan with certain executives of the Company (as amended) |
|
Filed as Exhibit 10.01 to Form 10-Q for the quarter ended September 30, 2000 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).
104
INDEX TO EXHIBITS
Exhibits |
|
Description |
|
Method of Filing |
* 10.04(a) |
|
1999 Equitable Resources, Inc. Non-Employee Directors Stock Incentive Plan (as amended May 26, 1999) |
|
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 1999 |
* 10.04(b) |
|
Form of Participant Award Agreement (Stock Option) under 1999 Equitable Resources, Inc. Non-Employee Directors Stock Incentive Plan |
|
Filed herewith as Exhibit 10.04(b) |
* 10.04(c) |
|
Form of Participant Award Agreement (Phantom Units Award) under 1999 Equitable Resources, Inc. Non-Employee Directors Stock Incentive Plan |
|
Filed herewith as Exhibit 10.04(c) |
* 10.05 |
|
Equitable Resources, Inc. Executive Short-Term Incentive Plan |
|
Filed as Exhibit 10.1 to Form 8-K filed on April 18, 2006 |
* 10.06 |
|
Equitable Resources, Inc. 2004 Short-Term Incentive Plan |
|
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2004 |
* 10.07 |
|
Equitable Resources, Inc. 2005 Short-Term Incentive Plan |
|
Filed as Exhibit 10.1 to Form 8-K filed on December 6, 2004 |
* 10.08 |
|
Equitable Resources, Inc. 2006 Payroll Deduction and Contribution Program |
|
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2006 |
* 10.09 |
|
Equitable Resources, Inc. Directors Deferred Compensation Plan (as amended and restated May 15, 2003) |
|
Filed as Exhibit 10.10 to Form 10-Q for the quarter ended June 30, 2003 |
* 10.10 |
|
Equitable Resources, Inc. 2005 Directors Deferred Compensation Plan (as amended and restated December 15, 2005) |
|
Filed as Exhibit 10.08 to Form 10-K for the year ended December 31, 2005 |
* 10.11 |
|
Equitable Resources, Inc. Employee Deferred Compensation Plan (amended and restated effective December 3, 2003) |
|
Filed as Exhibit 10.12 to Form 10-K for the year ended December 31, 2003 |
* 10.12 |
|
Equitable Resources, Inc. 2005 Employee Deferred Compensation Plan |
|
Filed as Exhibit 10.1 to Form 8-K filed on December 28, 2004 |
* 10.13 (a) |
|
Employment Agreement dated as of May 4, 1998 with Murry S. Gerber |
|
Filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 1998 |
* 10.13 (b) |
|
Amendment No. 1 to Employment Agreement with Murry S. Gerber |
|
Filed as Exhibit 10.09 (b) to Form 10-K for the year ended December 31, 1999 |
* 10.13 (c) |
|
Amendment No. 2 to Employment Agreement with Murry S. Gerber |
|
Filed as Exhibit 10.09 (c) to Form 10-Q for the quarter ended September 30, 2002 |
* 10.13 (d) |
|
Amendment No. 3 to Employment Agreement with Murry S. Gerber |
|
Filed as Exhibit 10.13 (d) to Form 10-K for the year ended December 31, 2003 |
* 10.13 (e) |
|
Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Murry S. Gerber |
|
Filed as Exhibit 10.10 to Form 10-Q for the quarter ended September 30, 2002 |
* 10.13 (f) |
|
Supplemental Executive Retirement Agreement dated as of May 4, 1998 with Murry S. Gerber |
|
Filed as Exhibit 10.4 to Form 10-Q for the quarter ended June 30, 1998 |
* 10.13 (g) |
|
Satisfaction Agreement In Respect of Supplemental Executive Retirement Agreement dated as of February 22, 2006 with Murry S. Gerber |
|
Filed as Exhibit 10.11(g) to Form 10-K for the year ended December 31, 2005 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).
105
INDEX TO EXHIBITS
Exhibits |
|
Description |
|
Method of Filing |
* 10.13 (h) |
|
Amended and Restated Post-Termination Confidentiality and Non-Competition Agreement dated December 1, 1999 with Murry S. Gerber |
|
Filed as Exhibit 10.12 to Form 10-K for the year ended December 31, 1999 |
* 10.14 (a) |
|
Employment Agreement dated as of July 1, 1998 with David L. Porges |
|
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 1998 |
* 10.14 (b) |
|
Amendment No. 1 to Employment Agreement with David L. Porges |
|
Filed as Exhibit 10.13 (b) to Form 10-K for the year ended December 31, 1999 |
* 10.14 (c) |
|
Amendment No. 2 to Employment Agreement with David L. Porges |
|
Filed as Exhibit 10.13 (c) to Form 10-Q for the quarter ended September 30, 2002 |
* 10.14 (d) |
|
Amendment No. 3 to Employment Agreement with David L. Porges |
|
Filed as Exhibit 10.14 (d) to Form 10-K for the year ended December 31, 2003 |
* 10.14 (e) |
|
Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and David L. Porges |
|
Filed as Exhibit 10.14 to Form 10-Q for the quarter ended September 30, 2002 |
* 10.14(f) |
|
Amended and Restated Post-Termination Confidentiality and Non-Competition Agreement dated December 1, 1999 with David L. Porges |
|
Filed as Exhibit 10.15 to Form 10-K for the year ended December 31, 1999 |
* 10.15 (a) |
|
Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Philip P. Conti |
|
Filed as Exhibit 10.26 to Form 10-Q for the quarter ended September 30, 2002 |
* 10.15 (b) |
|
Amendment No. 1 to Change of Control Agreement dated December 29, 2006, by and between Equitable Resources, Inc. and Philip P. Conti |
|
Filed herewith as Exhibit 10.15 (b) |
* 10.15 (c) |
|
Noncompete Agreement dated October 30, 2000 by and between Equitable Resources, Inc. and Philip P. Conti |
|
Filed as Exhibit 10.27 (b) to Form 10-K for the year ended December 31, 2004 |
* 10.16 (a) |
|
Change of Control Agreement dated December 1, 1999 by and between Equitable Resources, Inc. and Randall L. Crawford |
|
Filed as Exhibit 10.18(b) to Form 10-K for the year ended December 31, 2003 |
* 10.16 (b) |
|
Noncompete Agreement dated December 1, 1999 by and between Equitable Resources, Inc. and Randall L. Crawford |
|
Filed as Exhibit 10.17 (b) to Form 10-K for the year ended December 31, 2005 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).
106
INDEX TO EXHIBITS
Exhibits |
|
Description |
|
Method of Filing |
* 10.17 (a) |
|
Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Joseph E. OBrien |
|
Filed as Exhibit 10.31 to Form 10-Q for the quarter ended September 30, 2002 |
* 10.17 (b) |
|
Noncompete Agreement dated January 30, 2001 by and between Equitable Resources, Inc. and Joseph E. OBrien |
|
Filed as Exhibit 10.32 to Form 10-K for the year ended December 31, 2000 |
* 10.18 (a) |
|
Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Johanna G. OLoughlin |
|
Filed as Exhibit 10.18 to Form 10-Q for the quarter ended September 30, 2002 |
* 10.18 (b) |
|
Noncompete Agreement dated December 1, 1999 by and between Equitable Resources, Inc. and Johanna G. OLoughlin |
|
Filed as Exhibit 10.19 to Form 10-K for the year ended December 31, 1999 |
* 10.19 (a) |
|
Agreement dated May 24, 1996 with Phyllis A. Domm for deferred payment of 1996 director fees beginning May 24, 1996 |
|
Filed as Exhibit 10.14 (a) to Form 10-K for the year ended December 31, 1996 |
* 10.19 (b) |
|
Agreement dated November 27, 1996 with Phyllis A. Domm for deferred payment of 1997 director fees |
|
Filed as Exhibit 10.14 (b) to Form 10-K for the year ended December 31, 1996 |
* 10.19 (c) |
|
Agreement dated November 30, 1997 with Phyllis A. Domm for deferred payment of 1998 director fees |
|
Filed as Exhibit 10.14 (c) to Form 10-K for the year ended December 31, 1997 |
* 10.19 (d) |
|
Agreement dated December 5, 1998 with Phyllis A. Domm for deferred payment of 1999 director fees |
|
Filed as Exhibit 10.20 (d) to Form 10-K for the year ended December 31, 1998 |
* 10.20 |
|
Form of Indemnification Agreement between Equitable Resources, Inc. and all executive officers and outside directors |
|
Filed as Exhibit 10.41 to Form 10-K for the year ended December 31, 2002 |
* 10.21 |
|
Directors Compensation |
|
Filed herewith as Exhibit 10.21 |
10.22 |
|
Revolving Credit Agreement, dated as of October 27, 2006, among the Company, Bank of America, N.A., as Administrative Agent, Swing Line Lender and a Letter of Credit Issuer, JPMorgan Chase Bank, N.A., as Syndication Agent and a Letter of Credit Issuer, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Houston Agency, Citibank, N.A., and PNC Bank, National Association, as Co-Documentation Agents, and other lender parties thereto. |
|
Filed as Exhibit 10.1 to Form 8-K filed on October 27, 2006 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).
107
INDEX TO EXHIBITS
Exhibits |
|
Description |
|
Method of Filing |
21 |
|
Schedule of Subsidiaries |
|
Filed herewith as Exhibit 21 |
23.01 |
|
Consent of Independent Registered Public Accounting Firm |
|
Filed herewith as Exhibit 23.01 |
23.02 |
|
Consent of Independent Petroleum Engineers |
|
Filed herewith as Exhibit 23.02 |
31.1 |
|
Rule 13(a)-14(a) Certification of Principal Executive Officer |
|
Filed herewith as Exhibit 31.1 |
31.2 |
|
Rule 13(a)-14(a) Certification of Co-Principal Financial Officer |
|
Filed herewith as Exhibit 31.2 |
31.3 |
|
Rule 13(a)-14(a) Certification of Co-Principal Financial Officer |
|
Filed herewith as Exhibit 31.3 |
32 |
|
Section 1350 Certification of Principal Executive Officer and Co-Principal Financial Officers |
|
Filed herewith as Exhibit 32 |
The Company agrees to furnish to the Commission, upon request, copies of instruments with respect to long-term debt, which have not previously been filed.
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).
108
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.
|
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EQUITABLE RESOURCES, INC. |
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By: |
/s/ MURRY S. GERBER |
|
|
Murry S. Gerber |
|
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Chairman and Chief Executive Officer |
|
|
February 21, 2007 |
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.
/s/ Murry S. Gerber |
|
Chairman and |
|
February 21, 2007 |
Murry S. Gerber |
|
Chief Executive Officer |
|
|
(Principal Executive Officer) |
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/s/ David L. Porges |
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Vice Chairman, President and |
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February 21, 2007 |
David L. Porges |
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Chief Operating Officer |
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(Co-Principal Financial Officer) |
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/s/ Philip P. Conti |
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Senior Vice President and |
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February 21, 2007 |
Philip P. Conti |
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Chief Financial Officer |
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(Co-Principal Financial Officer) |
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/s/ John A. Bergonzi |
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Vice President and |
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February 21, 2007 |
John A. Bergonzi |
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Corporate Controller |
|
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(Principal Accounting Officer) |
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/s/ Vicky A. Bailey |
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Director |
|
February 21, 2007 |
Vicky A. Bailey |
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/s/ Phyllis A. Domm |
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Director |
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February 21, 2007 |
Phyllis A. Domm |
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/s/ Barbara S. Jeremiah |
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Director |
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February 21, 2007 |
Barbara S. Jeremiah |
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/s/ Thomas A. McConomy |
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Director |
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February 21, 2007 |
Thomas A. McConomy |
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/s/ George L. Miles, Jr . |
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Director |
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February 21, 2007 |
George L. Miles, Jr. |
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/s/ James E. Rohr |
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Director |
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February 21, 2007 |
James E. Rohr |
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/s/ David S. Shapira |
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Director |
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February 21, 2007 |
David S. Shapira |
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/s/ Lee T. Todd, Jr . |
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Director |
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February 21, 2007 |
Lee T. Todd, Jr. |
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/s/ James W. Whalen |
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Director |
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February 21, 2007 |
James W. Whalen |
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109
Exhibit 10.01(b)
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|
PARTICIPANT AWARD AGREEMENT |
[Date]
[Name]
[Address]
[City, State and Zip Code]
Dear [Name] :
Pursuant to the terms and conditions of the Companys 1999 Long-Term Incentive Plan (the Plan), the Compensation Committee of the Board of Directors of Equitable Resources, Inc. granted you a Restricted Stock Award (the Award) for shares of the Companys common stock as outlined below.
Shares Granted:
Grant Date:
Vesting Schedule:
The employee shall be entitled to vote the restricted shares, and dividends issued with respect to such shares shall be invested in additional shares of common stock and added to the original shares, subject to the same restrictions as the shares originally awarded.
In the event of a change of control as defined in the Plan, all shares, including reinvested dividend shares, will immediately vest without restriction. In the event of termination of employment for any reason prior to [day prior to 100% vesting], including retirement, all unvested restricted shares, including reinvested dividend shares, shall be forfeited, except that, if termination is involuntary and without fault on the part of the employee (including termination resulting from death or disability as defined in Sec. 409A(a)(2)(C) of the Internal Revenue Code), the shares will vest as follows (including a proportional amount of reinvested dividend shares):
Termination Date |
|
Percent Vested |
[prior to first anniversary of grant] |
|
|
[prior to second anniversary of grant] |
|
|
[prior to third anniversary of grant] |
|
|
The employee may satisfy tax withholding obligations with respect to his award by directing the company to (i) withhold that number of shares that would otherwise be issued upon vesting to satisfy the minimum required statutory tax withholding obligations, and (ii) accept delivery of previously owned shares to satisfy such tax withholding obligations; provided, that if such withholding is in excess of the minimum statutory rate, such shares must have been held by the employee for at least six months.
|
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Johanna G. OLoughlin |
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For the Compensation Committee |
By my signature below, I hereby acknowledge receipt of this Award granted on the date shown above, which has been issued to me under the terms and conditions of the Plan. I further acknowledge receipt of the copy of the Plan and agree to conform to all of the terms and conditions of the Award and the Plan.
Signature: |
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Date: |
|
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Exhibit 10.04(b)
|
|
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|
PARTICIPANT AWARD AGREEMENT
[ ]:
[Insert Recipient Name]
Dear [ ]:
Pursuant to the terms and conditions of the Companys 1999 Non-Employee Directors Stock Incentive Plan (the Plan), the Compensation Committee of the Board of Directors of Equitable Resources, Inc. granted you a Non-Qualified Stock Option (the Option) to purchase shares of the Companys common stock as outlined below.
Option Granted:
Grant Date:
Option Price per Share:
Expiration Date:
Vesting Schedule:
Upon termination of service as a Director of Equitable Resources, Inc. for any reason, including death, all unvested options shall immediately vest; all vested options shall be exercisable for a period of 90 days following such termination, except that in the event of death of a Director, his or her estate shall have one year to exercise any vested options.
One Reload Right as described in the plan has been awarded for each option awarded under the 1999 Plan.
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For the Compensation Committee |
By my signature below, I hereby acknowledge receipt of this Option granted on the date shown above, which has been issued to me under the terms and conditions of the Plan. I further acknowledge receipt of the copy of the Plan and agree to conform to all of the terms and conditions of the Option and the Plan.
Signature: |
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Date: |
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Exhibit 10.04(c)
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225 North Shore Drive, 6 th Floor Pittsburgh, PA 15212-5861
|
[ ]
«Title» «FirstName» «LastName»
«Company»
«Address1»
«Address2»
«address3»
«City», «State » «PostalCode»
Re: 2005 Directors Deferred Compensation Plan 2006 Phantom Units Award
Dear «title 2»:
As you are aware, on [ ] you were awarded [ ] phantom units of Equitable Resources, Inc.s common stock, the value of which is determined by reference to the Companys common stock, and has been credited to your account under the 2005 Directors Deferred Compensation Plan (the Deferred Compensation Plan). Each stock unit will be credited quarterly with dividends in the form of additional stock units, such additional stock units to be payable on the same terms as the original award. The deferred stock units are awarded in substitution for the 500-share automatic stock option grant provided for under §6.02 of the 1999 Non-Employee Directors Stock Incentive Plan.
The stock units will be paid out in cash in accordance with the 2005 Directors Deferred Compensation Plan on the earlier of the Directors death or retirement from the Board. A copy of the Plan is enclosed for your reference.
If you have any questions, please call me at [ ].
Very truly yours,
Exhibit 10.15(b)
ADDENDUM NO. 1 TO CHANGE OF CONTROL AGREEMENT
This Addendum No. 1 to Change of Control Agreement (Addendum No. 1), dated as of December 29, 2006, amends that certain Change of Control Agreement (Change of Control Agreement) dated as of the 1 st day of September 2002, by and between Equitable Resources, Inc., a Pennsylvania corporation (the Company), and Phillip P. Conti, an individual (the Employee).
WITNESSETH:
WHEREAS, in connection with Employees employment by the Company, the parties entered into the Change of Control Agreement; and
WHEREAS, the Company and Employee desire to amend and supplement the Change of Control Agreement in certain respects set forth below;
NOW THEREFORE, in consideration of the premises and mutual covenants contained herein, and intending to be legally bound hereby, the parties hereto agree as follows:
1. Section 3(a) of the Change of Control Agreement is deleted in its entirety and replaced with the following paragraph:
2. Section 3(e) of the Change in Control Agreement is amended and supplemented by the addition of the following paragraph to be inserted as Section 3(e)(viii):
(viii) Notwithstanding anything herein to the contrary, a termination of employment by the Employee for any reason during the 30-day period commencing on the one (1) year anniversary of a Change of Control shall constitute Good Reason for purposes of this Agreement, provided, however, that for purposes of this subsection (viii), a merger, consolidation, reorganization, share exchange, or similar transaction involving the Company (including a triangular merger), as referred to in
2
Section 2(d) hereof, shall not constitute a Change of Control if: (i) Continuing Directors constitute at least two-third (2/3) of the board of directors of the Company and, if applicable, the Parent Company after the consummation of such transaction and (ii) all or substantially all of the persons who were the beneficial owners of the outstanding common stock and outstanding voting securities of the Company immediately prior to the transaction beneficially own, directly or indirectly, more than 50% of the outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors of the corporation resulting from such transaction (including a Parent Company) in substantially the same proportion as their ownership of the common stock and other voting securities of the Company immediately prior to the consummation of the transaction.
ATTEST: |
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EQUITABLE RESOURCES, INC. |
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/s/ JEAN MARKS |
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/s/ CHARLENE PETRELLI |
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Assistant Corporate Secretary |
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By: Charlene Petrelli |
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Title: Vice President, Human Resources |
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Address: |
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225 North Shore Drive |
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Pittsburgh, PA 15219 |
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WITNESS: |
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/s/ DAVID J. SMITH |
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/s/ PHILIP P. CONTI |
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Director of Compensation and Benefits |
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Name: Philip P. Conti |
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Address: |
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2134 Grandeur Drive |
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Gibsonia, Pa. 15044 |
3
Exhibit 10.21
DIRECTORS COMPENSATION
The Corporate Governance Committee of the Board of Directors discharges the Boards responsibilities relating to compensation of directors. Compensation of directors is reviewed by the Corporate Governance Committee annually at its April meeting and is approved by the Board. No compensation is paid to employee directors for their service as directors.
The Corporate Governance Committee has engaged Towers, Perrin, Forster & Crosby, Inc. (Towers Perrin), an external human resources consulting firm, to conduct an annual review of the total compensation for outside directors. Specifically, retainer fees, meeting fees, stock-based long-term incentives and insurance were evaluated using, as the competitive benchmark, levels of total compensation paid to directors of 30 energy companies (including the 29 companies constituting the Long Term Incentive Peer Group), 20 general industry companies of comparable revenue and equity capitalization size and 14 companies located in the companys geographic area or of other relevance. Set forth below is the 2006 compensation of the companys non-employee directors.
· An annual cash retainer of $30,000 is paid on a quarterly basis. The level of retainer was increased in 2006 from $24,000 to be competitive with market peers.
· The cash meeting fee is $1,500 for each Board and committee meeting attended in person. If a director participates in a meeting by telephone, the meeting fee is $750. An additional $500 is paid to each committee chair ($1,500 for the Audit Committee Chair) for each meeting of his or her committee that the chair attends.
· In 2003, the company began granting to each director stock units that vested upon award and that are payable on a deferred basis under the directors deferred compensation plans. In 2006, a grant of 2,000 deferred stock units was awarded to each non-employee director. The deferred stock units are awarded by the Board annually at the April Board meeting upon the recommendation of the Corporate Governance Committee. Each deferred stock unit is equal in value to one share of company common stock, but does not have voting rights. Dividends are credited quarterly in the form of additional stock units. The value of the stock units will be paid in cash on the earlier of the directors death or termination of service as a director.
· The non-employee directors are subject to stock ownership guidelines which require them to hold shares (or share equivalents, including deferred stock units) with a value equal to at least two times the annual cash retainer. Under the guidelines, directors have up to two years to acquire a sufficient number of shares (or share equivalents, including deferred stock units) to meet this requirement. All of the companys non-employee directors meet this share ownership requirement.
· The company has a deferred compensation plan for non-employee directors. In addition to the automatic deferral of stock units awarded, non-employee directors may elect to defer up to 100% of their annual retainer and fees into the 2005 Directors Deferred Compensation Plan and receive an investment return on the deferred funds as if the funds were invested in company stock or permitted mutual funds. Prior to the deferral, plan participants must irrevocably elect to receive the deferred funds either in a lump sum or in equal installments. Distributions commence no earlier than 30 days following termination of service as a director. The directors deferred compensation accounts are unsecured obligations of the company. Ms. Jeremiah and Mr. Miles deferred fees under the plan in 2006, and they and other directors have participated in prior years. The pre-existing Directors Deferred Compensation Plan continues to operate for the sole purpose of administering amounts vested under the plan on or prior to December 31, 2004.
A- 1
Other
· To further the companys support for charitable giving, all directors are eligible to participate in the Matching Gifts Program of the Equitable Resources Foundation, Inc. (the Equitable Foundation) on the same terms as company employees. Under this program, the Equitable Foundation will match gifts of at least $100 made by the director to eligible charities, up to an aggregate total of $10,000 in any calendar year.
· Non-employee directors who joined the Board prior to May 25, 1999 may designate a civic, charitable or educational organization as beneficiary of a $500,000 gift funded by a life insurance policy purchased by Equitable Resources. The directors do not receive any financial benefit from this program because the charitable deductions accrue solely to the company.
· The company reimburses directors for their travel and related expenses in connection with attending Board meetings and Board-related activities. The company also provides non-employee directors with $20,000 of life insurance and $250,000 of travel accident insurance while traveling on business for the company.
A- 2
Exhibit 21
Subsidiaries of Registrant
Legal Name |
|
Domicile |
Equitable Resources, Inc. |
|
USA, Pennsylvania |
Appalachian Drilling LLC |
|
USA, Delaware |
Eastern Seven Partners, LP |
|
USA, Delaware |
Eastern Series 1997 Trust |
|
USA, Delaware |
Eastern Four, LLC |
|
USA, Delaware |
EPC Investments, Inc. |
|
USA, Delaware |
ERI International |
|
Cayman Islands |
EQT Capital Corporation |
|
USA, Delaware |
EQT Holdings Company, LLC |
|
USA, Delaware |
EQT Holdings Management Company, LLC |
|
USA, Delaware |
EQT International Holdings Corporation |
|
USA, Delaware |
EQT Investments, LLC |
|
USA, Delaware |
EQT Investments Holdings, LLC |
|
USA, Delaware |
EQT IP Ventures, LLC |
|
USA, Delaware |
Equitable Energy Holdings Corporation |
|
USA, Delaware |
Equitable Energy, LLC |
|
USA, Delaware |
Equitable Gathering, Inc. |
|
USA, Pennsylvania |
Equitable Gathering, LLC |
|
USA, Delaware |
Equitable Gathering Equity, LLC |
|
USA, Delaware |
Equitable Homeworks, LLC |
|
USA, Pennsylvania |
Equitable Production Company |
|
USA, Pennsylvania |
Equitable Production Services, LP |
|
USA, Delaware |
Equitable Resources Insurance Company, Ltd. |
|
Cayman Islands |
Equitable Utilities Investments, Inc. |
|
USA, Delaware |
Equitrans, LP |
|
USA, Pennsylvania |
ERI Group LDC |
|
Cayman Islands |
ERI Holdings |
|
Cayman Islands |
ET Blue Grass Clearing, LLC |
|
USA, Delaware |
ET Blue Grass Company |
|
USA, Delaware |
Kentucky West Virginia Gas Company, LLC |
|
USA, Delaware |
Exhibit 23.01
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the following Registration Statements:
· Registration Statement No. 33-52151 on Form S-8 pertaining to the 1994 Equitable Resources, Inc. Long-Term Incentive Plan;
· Registration Statement No. 33-53703 on Form S-3 pertaining to the registration of $100,000,000 Medium-Term Notes, Series C of Equitable Resources, Inc.;
· Post-effective Amendment No. 1 to Registration Statement No. 33-00252 on Form S-8 pertaining to the Equitable Resources, Inc. Employee Savings Plan;
· Registration Statement No. 333-01879 on Form S-8 pertaining to the Equitable Resources, Inc. Employee Stock Purchase Plan;
· Registration Statement No. 333-22529 on Form S-8 pertaining to the Equitable Resources, Inc. Employee Savings and Protection Plan;
· Registration Statement No. 333-06839 on Form S-3 pertaining to the registration of $168,000,000 of 7.75% debt securities of Equitable Resources, Inc.;
· Registration Statement No. 333-82189 on Form S-8 pertaining to the 1999 Equitable Resources, Inc. Long-Term Incentive Plan;
· Registration Statement No. 333-82193 on Form S-8 pertaining to the 1999 Equitable Resources, Inc. Non-Employee Directors Stock Incentive Plan;
· Registration Statement No. 333-32410 on Form S-8 pertaining to the Equitable Resources, Inc. Deferred Compensation Plan and the Equitable Resources, Inc. Directors Deferred Compensation Plan;
· Registration Statement No. 333-70822 on Form S-8 pertaining to the 1999 Equitable Resources, Inc. Long-Term Incentive Plan;
· Registration Statement No. 333-122382 on Form S-8 pertaining to the 2005 Equitable Resources, Inc. Employee Deferred Compensation Plan and the 2005 Equitable Resources, Inc. Directors Deferred Compensation Plan; and
· Registration Statement No. 333-129286 on Form S-4 pertaining to the registration of $150,000,000 of 5% Notes due 2015 of Equitable Resources, Inc.;
of our reports dated February 19, 2007, with respect to the consolidated financial statements and schedule of Equitable Resources, Inc., Equitable Resources, Inc. managements assessment of the effectiveness of internal control over financial reporting, and the effectiveness of internal control over financial reporting of Equitable Resources, Inc., included in this Annual Report (Form 10-K) for the year ended December 31, 2006.
/s/ Ernst & Young LLP |
|
Pittsburgh, Pennsylvania |
|
February 19, 2007 |
Exhibit 23.02
CONSENT
As independent petroleum and natural gas consultants, we hereby consent to the reference of our name in the Annual Report on Form 10-K, for the year ended December 31, 2006 of Equitable Resources, Inc, and to the incorporation of our name by reference into Equitable Resources, Inc.s effective registration statements under the Securities Act of 1933, as amended. We have no interest of a substantial or material nature in Equitable Resources, Inc., or in any affiliate. We have not been employed on a contingent basis, and we are not connected with Equitable Resources, Inc., or any affiliate as a promoter, underwriter, voting trustee, director, officer, employee, or affiliate.
|
/s/ Ryder Scott Company, L.P. |
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RYDER SCOTT COMPANY, L.P. |
Houston, Texas
February 16, 2007
Exhibit 31.1
CERTIFICATION
I, Murry S. Gerber, certify that:
1. I have reviewed this Annual Report on Form 10-K of Equitable Resources, Inc.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c. Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditor and the audit committee of the registrants board of directors (or persons performing the equivalent functions);
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting.
Date: February 23, 2007
|
/s/ Murry S. Gerber |
|
Murry S. Gerber |
|
Chairman
|
Exhibit 31.2
CERTIFICATION
I, David L. Porges, certify that:
1. I have reviewed this Annual Report on Form 10-K of Equitable Resources, Inc.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c. Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditor and the audit committee of the registrants board of directors (or persons performing the equivalent functions);
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting.
Date: February 23, 2007
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/s/ David L. Porges |
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David L. Porges |
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Vice Chairman, President and
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Exhibit 31.3
CERTIFICATION
I, Philip P. Conti, certify that:
1. I have reviewed this Annual Report on Form 10-K of Equitable Resources, Inc.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c. Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditor and the audit committee of the registrants board of directors (or persons performing the equivalent functions);
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting.
Date: February 23, 2007
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/s/ Philip P. Conti |
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Philip P. Conti |
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Senior Vice President and Chief Financial Officer |
Exhibit 32
CERTIFICATION
In connection with the Annual Report of Equitable Resources, Inc. (the Company) on Form 10-K for the period ended December 31, 2006, as filed with the Securities and Exchange Commission on the date hereof (the Report), the undersigned certify pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
/s/ Murry S. Gerber |
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February 23, 2007 |
Murry S. Gerber, Chairman |
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and Chief Executive Officer |
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/s/ David L. Porges |
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February 23, 2007 |
David L. Porges, Vice Chairman, |
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President and Chief Operating Officer |
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/s/ Philip P. Conti |
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February 23, 2007 |
Philip P. Conti, Senior Vice President and
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A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Equitable Resources, Inc. and will be retained by Equitable Resources, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.