10-K 1 a08-2449_110k.htm 10-K

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10-K

 

x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

 

 

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007

 

 

 

 

 

 

 

or

 

 

 

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

(State or other jurisdiction of incorporation or organization)

 

25-0464690
(IRS Employer Identification No.)

 

 

 

225 North Shore Drive

Pittsburgh, Pennsylvania

(Address of principal executive offices)

 

15212
(Zip Code)

 

Registrant’s telephone number, including area code:  (412) 553-5700

 

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

 

Title of each class

 

Name of each exchange on which registered

Common Stock, no par value

 

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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

Large accelerated filer x

 

Accelerated filer o

 

 

 

 

 

Non-accelerated filer o

 

Smaller reporting company 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, 2007:  $5,952,581,076

 

The number of shares of common stock outstanding
as of January 31, 2008:  122,152,641

 

DOCUMENTS INCORPORATED BY REFERENCE

 

                The Company’s definitive proxy statement relating to the annual meeting of shareowners, to be held April 23, 2008, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2007, is incorporated by reference in Part III to the extent described therein.

 

 



 

TABLE OF CONTENTS

 

 

Glossary of Commonly Used Terms, Abbreviations, and Measurements

3

 

 

 

 
PART I
 
 
 
 

Item 1

Business

6

Item 1A

Risk Factors

12

Item 1B

Unresolved Staff Comments

14

Item 2

Properties

15

Item 3

Legal Proceedings

17

Item 4

Submission of Matters to a Vote of Security Holders

18

 

Executive Officers of the Registrant

19

 

 

 

 
PART II
 
 
 
 

Item 5

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

21

Item 6

Selected Financial Data

23

Item 7

Management’s Discussion and Analysis of Financial Condition and Results of Operations

24

Item 7A

Quantitative and Qualitative Disclosures About Market Risk

48

Item 8

Financial Statements and Supplementary Data

51

Item 9

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

99

Item 9A

Controls and Procedures

99

Item 9B

Other Information

99

 

 

 

 

PART III

 

 

 

 

Item 10

Directors, Executive Officers and Corporate Governance

100

Item 11

Executive Compensation

100

Item 12

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

101

Item 13

Certain Relationships and Related Transactions, and Director Independence

102

Item 14

Principal Accounting Fees and Services

102

 

 

 

 

PART IV

 

 

 

 

Item 15

Exhibits, Financial Statement Schedules

103

 

Index to Financial Statements Covered by Report of Independent Registered Public Accounting Firm

103

 

Index to Exhibits

105

 

Signatures

111

 

Certifications

 

 

 

2



 

 

Glossary of Commonly Used Terms, Abbreviations, and Measurements

 

Commonly Used Terms

 

AFUDC — Allowance for Funds Used During Construction, carrying costs for the construction of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives, including the cost of financing construction of assets subject to regulation; the capitalized amount for construction of regulated assets includes interest cost and a designated cost of equity for financing the construction of these regulated assets.

 

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.

 

CAP — The Customer Assistance Program, a payment plan for low-income residential gas customers that sets a fixed payment for natural gas usage based on a percentage of total household income.

 

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 area.

 

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 weather’s 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.

 

 

 

3



 

Glossary of Commonly Used Terms, Abbreviations, and Measurements

 

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 area 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.

 

margin call — A demand for additional or variation margin deposits when futures prices move adversely to a hedging party’s 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 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 owner’s share of oil or gas production typically 1/8, 1/6, or 1/4.

 

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”

Dominion - Dominion Resources, Inc.  When used in the context of discussion relating to the now terminated acquisition of Peoples and Hope, references to Dominion are as successor by merger to Consolidated Natural Gas Company, the original counterparty to the terminated acquisition agreement.

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

 

 

 

4



 

Glossary of Commonly Used Terms, Abbreviations, and Measurements

 

FIN 45 — FASB Interpretation No. 45, “Guarantor’s 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”

Hope - Hope Gas, Inc

IRC — Internal Revenue Code of 1986, as amended

IRS — Internal Revenue Service

NYMEX — New York Mercantile Exchange

OTC — Over the Counter

PA PUC — Pennsylvania Public Utility Commission

Peoples - The Peoples Natural Gas Company

SEC — Securities and Exchange Commission

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. 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. 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

 

 

5



 

Forward-Looking Statements
 

            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 Management’s 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 Company’s drilling and infrastructure programs, production and sales volumes, reserves, capital expenditures, financing requirements, hedging strategy, tax position, formation of three reporting segments and the move to a holding company structure.  A variety of factors could cause the Company’s actual results to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements.  The risks and uncertainties that may affect the operations, performance and results of the Company’s business and forward-looking statements include, but are not limited to, those set forth under Item 1A, “Risk Factors” and elsewhere in this Form 10-K.

 

            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.

 

PART I

 

Item 1.        Business
 

        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 activities, including production, gathering and processing, and distribution, transmission, storage and marketing.  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.

 

            The results of operations of the Company for the year ended December 31, 2007 are reported in this Form 10-K through two business segments: Equitable Supply and Equitable Utilities.  These reporting segments reflect the Company’s lines of business and are reported in the same manner the Company evaluated its operating performance through December 31, 2007.

 

            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 1,400 employees at the end of 2007, of which 292 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.  The labor agreement with the United Steelworkers (USW), Local 12050 will expire on September 25, 2008 and the labor agreement with USW, Local 8-512 will expire on October 15, 2008.  In October 2007, one USW bargaining unit, which had been operating without a contract since April 19, 2004, voted to decertify the USW as its collective bargaining representative.  As a result, these employees are no longer represented by a union.  The Company believes that its employee relations are generally good.

 

 

6



 

            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, or furnished to, the SEC.  The filings are also available at the SEC’s 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 Company’s annual reports to shareholders, press releases and recent analyst presentations are also available on the Company’s website.

 

        Business Segments

 

Equitable Supply

 

Equitable Supply’s 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 the gathering of gas produced by the Company and third parties and the processing of natural gas liquids.  Equitable Supply generated approximately 64% of the Company’s net operating revenues in 2007.

 

Production

 

Equitable Supply’s production business, operating through Equitable Production Company and several other affiliates (collectively referred to as “Equitable Production”), is one of the largest owners of proved natural gas reserves in the Appalachian Basin.  Equitable Production’s key operating assets include:

 

·                  1,016,960 gross (954,010 net) productive acres

 

·                  2,286,759 gross (2,145,175 net) undeveloped acres

 

·                  total proved reserves at December 31, 2007 of 2,682 Bcfe; 65% of which were proved developed

 

·                  12,889 gross (9,309 net) producing wells

 

            The Company’s proved reserves had discounted future net cash flows before income taxes of $3,989 million ($2,473 million after tax) at December 31, 2007.  This standardized measure of discounted future net cash flows is calculated using adjusted year-end prices in accordance with SFAS No. 69. See Note 24 to the Consolidated Financial Statements for more information.  These reserves are located entirely in the Appalachian Basin, which is characterized by wells with comparatively low rates of annual decline in production, long lives, low production costs and natural gas containing high energy content.  Many of the Company’s wells have been producing for decades, in some cases since the early 1900’s.  Management believes that virtually all of the Company’s wells are low risk development wells because they are drilled in areas and into reservoirs which are known to be productive.

 

            The Company is focused on continuing its significant organic reserve and production growth through its drilling program and believes that this plan will increase its proved reserves based on the quality of the underlying asset base.  From 2005 through 2007, Equitable has drilled 997 wells on locations not classified as proved in the reserves report, with less than 3 dry holes drilled.  The Company has announced a significant capital commitment plan to support its reserve growth.  Capital spending for well development (primarily drilling) is expected to increase to $619 million in 2008 from $298 million in 2007.  A substantial portion of the Company’s 2008 drilling efforts will be focused on drilling horizontal wells in shale formations in Kentucky and West Virginia.  The Company is targeting completion of between 250 and 300 horizontal wells in 2008 and expects an average cost per horizontal well of approximately $1.2 million, below its estimates when it began the horizontal drilling program in the latter part of 2006.  The Company expects average recovery results in the range of 0.75 Bcfe to 1.50 Bcfe per horizontal well.

 

The Company drilled 634 gross wells (456 net) in 2007 consisting of 88 horizontal shale wells, 266 coal bed methane wells and 280 other vertical wells.  Included in this total are 36 infill wells.  Drilling was concentrated within Equitable’s core areas of southwestern Virginia, southeastern Kentucky and southern West Virginia.

 

 

7



 

The Company’s drilling activity resulted in proved developed reserve additions of approximately 165 Bcfe in 2007.  Of the proved developed reserve additions, approximately 43 Bcfe related to proved undeveloped reserves that were transferred to proved developed reserves.  The company’s 2007 extensions, discoveries and other additions of 321.0 Bcfe exceeded the 2007 production of 83.1 Bcfe (a drill bit reserves replacement ratio of 386%).

 

            Equitable Supply’s production for 2007 increased to 83.1 Bcfe, yielding an average proved reserves-to-production ratio (average reserve life) of approximately 32.3 years at year-end 2007 when compared to the Company’s year-end proved reserves of 2,682 BcfeEquitable Supply’s fourth quarter 2007 average daily sales were 210 MMcfe per day.  Daily sales volumes are expected to reach 235 MMcfe by year-end 2008 with total production sales volumes expected to reach 80-81 Bcfe for the year.

 

            See Note 24 to the Company’s Consolidated Financial Statements for information on reserves, reserve activity, costs and the standard measure of discounted future cash flows.

 

            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 processing and transport systems.  As a result, the Company has entered into certain discounted sales arrangements to obtain transportation capacity, so 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 natural gas prices which continue to be higher than historical levels.  While increased activity can place constraints on availability of labor, equipment, pipeline transport and other resources in the Appalachian Basin, it also provides opportunities for expansion of natural gas gathering activities and potential to attract 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 Company’s hedging strategy and information regarding its derivative instruments is 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 operating through several subsidiaries of the Company derives its revenues from charges to customers for use of its gathering system in the Appalachian Basin.  As of December 31, 2007, the system included approximately 7,500 miles of gathering lines located throughout West Virginia, eastern Kentucky and southwestern Virginia.  Over 90% 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, L.P. (Equitrans), the Company’s interstate pipeline affiliate.  Maintaining these interconnects provides the Company with access to geographically diverse markets.

 

Gathering system sales volumes for 2007 totaled 94.2 Bcfe, of which approximately 65% related to the gathering of Equitable Production’s gas volumes, 24% 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 84% of Equitable Gathering’s 2007 revenues were from affiliates.  As a result of the gathering asset contribution to Nora Gathering, LLC in 2007 discussed in Note 4 to the Company’s Consolidated Financial Statements, operations related to the Nora area gathering activities are no longer included in Equitable Gathering’s operating results.  Equitable Gathering records its 50% equity interest in the earnings of Nora Gathering, LLC under the equity method of accounting.

 

 

8



 

Key competitors for new gathering systems include independent gas gatherers and integrated Appalachian energy companies.  See “Outlook” under Equitable Supply’s section of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for discussion of the Company’s strategy in regard to its midstream gathering operations.

 

Equitable Utilities

 

            Equitable Utilities’ operations comprise gathering, transportation, storage, distribution and marketing of natural gas.  Equitable Utilities has both regulated and nonregulated operations.  The regulated activities consist of the Company’s state-regulated distribution operations and federally-regulated pipeline and storage operations.  The nonregulated activities include the nonregulated pipeline operations, 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 Company’s net operating revenues in 2007.

 

        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 275,000 customers, consisting of 256,400 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, and contracts with affiliates are subject to comprehensive regulation by the PA PUC and the WV PSC and the issuance of securities is subject to regulation by the PA PUC.  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 Company’s 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 cost recovery programs.  Equitable Gas’ tariffs for commercial and industrial customers allow for negotiated rates in limited circumstances.  Regulators periodically audit the Company’s 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 2007 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.

 

            Pennsylvania law requires that local distribution companies develop and implement programs to assist low income customers with paying their gas bills. The costs of these programs are recovered through rates charged to other residential customers.  Equitable Gas has several such programs, including the CAP.  In October 2006, Equitable Gas submitted a request for PA PUC approval to increase funding to support the increasing costs of its CAP.  On September 27, 2007, the PA PUC issued an order approving an increase to Equitable’s surcharge, which is designed to offset the costs of the CAP.  The revised surcharge went into effect on October 2, 2007.  See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information.

 

            On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion’s natural gas distribution assets in Pennsylvania and in West Virginia for approximately $970 million, subject to adjustments, in a

 

 

9



 

cash transaction for the stock of Peoples and Hope.  In light of the continued delay in achieving the final legal approvals for this transaction, the Company and Dominion agreed to terminate the definitive agreement pursuant to a mutual termination agreement entered into on January 15, 2008.  See Item 3, “Legal Proceedings” for a description of proceedings initiated by the Federal Trade Commission for the purpose of challenging the proposed acquisition.

 

        Pipeline (Transportation and Storage) Operations

 

            Equitable Utilities’ interstate pipeline operations are carried out by 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 UGI Energy Services, Inc.  In 2007, approximately 66% of transportation volumes and approximately 77% of transportation revenues were from affiliates.  Equitrans’ rates are subject to regulation by the FERC.

 

            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 will be operated by Equitrans.  On October 16, 2007, the FERC granted Equitrans’ request for an extension of time until March 31, 2008 to complete construction of the Big Sandy Pipeline.  Capital expenditures incurred by the Company related to the Big Sandy Pipeline are included in the Equitable Supply business segment.

 

            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.  This settlement allows Equitrans to institute an annual surcharge for the tracking and recovery of all costs (operations, maintenance and return on invested capital) incurred on and after September 1, 2005, related to Equitrans’ Pipeline Safety Program under the Pipeline Safety Improvement Act of 2002.  Filings to modify the surcharge must be made on or before March 1st of each year for approval by the FERC.  On March 29, 2007, the Company received approval, subject to refund, to institute the surcharge, and on April 1, 2007, the Company commenced billing the surcharge.   On November 26, 2007, the FERC removed the refund condition and approved the surcharge effective April 1, 2007.  The Company anticipates that additional filings to modify the surcharge will continue to be made in future years to recover costs incurred in connection with its Pipeline Safety Program.

 

            Equitrans’ firm transportation contracts on its mainline system expire between 2009 and 2011 and the firm transportation contracts on its Big Sandy Pipeline expire in 2018.  The Company anticipates that the capacity associated with these expiring contracts will be remarketed such that the capacity will remain fully subscribed.

 

        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 energy trading and risk management activities for the Company.  The objective of these activities is to limit the Company’s exposure to shifts in market prices and to optimize the use of the Company’s assets.

 

        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.

 

10



 

Change in Segments

 

            In January 2008, the Company announced a change in organizational structure and several changes to executive management to better align the Company to execute its growth strategy for development and infrastructure expansion in the Appalachian Basin.  These changes resulted in changes to the Company’s reporting segments effective for fiscal year 2008.  The Company’s 2008 results will be reported through three business segments: Equitable Production, Equitable Midstream and Equitable Distribution.  Historical results will also be restated beginning in 2008 to reflect this new structure.  Under the new reporting structure, the Equitable Production segment will include the Company’s exploration for, and development and production of, natural gas and a limited amount of crude oil in the Appalachian Basin.  Equitable Midstream’s operations will include the natural gas gathering, processing, transportation, storage and marketing activities of the Company as well as sales of a limited amount of natural gas liquids.  Equitable Distribution’s operations will be comprised primarily of the state-regulated distribution activities of the Company.

 

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 2007, 2006 and 2005.

 

 

 

2007

 

2006

 

2005

 

Equitable Supply:

 

 

 

 

 

 

 

Natural gas equivalents sales

 

28

%

29

%

30

%

Equitable Utilities:

 

 

 

 

 

 

 

Marketed natural gas sales

 

26

%

20

%

27

%

Residential natural gas sales

 

23

%

24

%

26

%

 

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 Company’s assets and operations are located in the continental United States.

 

Environmental

 

See Note 20 to the Consolidated Financial Statements for information regarding environmental matters.

 

11



 

Item 1A.  Risk Factors
 

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 and future prospects.  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.  If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline.

 

            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 subject us to margin calls on our commodity price derivative contracts (hedging arrangements, including futures contracts, swap agreements and exchange traded instruments) which would potentially 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 may result in downward adjustments to the value of our estimated proved reserves and cause us to incur non-cash charges to earnings.  In addition, our reserves may be impacted by increases in our estimates of development costs or changes to our production assumptions which may change our production plans or may result in downward adjustments to our estimated proved reserves and cause us to 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.

 

            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 have announced plans to drill up to 750 wells in 2008, including a target of 250 to 300 horizontal wells.  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

 

12



 

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.  Additionally, a failure to effectively operate existing wells may cause production volumes to fall short of our projections.  Without continued successful development or acquisition activities, together with effective operation of existing wells, our reserves and revenues will decline as a result of our current reserves being depleted by production.

 

            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.  As we previously announced, $568 million of our 2008 capital commitment budget is planned for investment in midstream infrastructure, which we expect will include significant new investment in transportation infrastructure as well as our continuing investment in the Big Sandy Pipeline and the Langley hydrocarbon processing plant.  Investment in midstream infrastructure is intended to address a lack of capacity on, and access to, existing gathering and transportation pipelines as well as processing adjacent to and curtailments on such pipelines.  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 qualified contractors and  work force, as well as weather conditions, gas price volatility, government approvals, title problems, geology, compliance by third parties with their contractual obligations to us and other factors.  We also deliver to and are served by third party gas gathering, transportation, 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.

 

            Volatility in the capital markets or downgrades to our credit ratings could increase our costs of borrowing adversely affecting our business, results of operations and liquidity.

 

We rely on access to both short-term bank and money markets and longer-term capital markets as a source of liquidity for any capital requirements not satisfied by the cash flow from operations.  Market disruptions or any downgrade of our credit rating may increase the cost of borrowing or adversely affect our ability to raise capital through the issuance of debt or equity securities or other borrowing arrangements, which could have a material adverse effect on our business, results of operations and liquidity.  These disruptions could include an economic downturn, changes in capital market conditions generally and deterioration in the overall health of our industry.

 

We cannot be sure that our current ratings will remain in effect for any given period of time or that our rating will not be lowered or withdrawn entirely by a rating agency.  An increase in the level of our indebtedness in the future may result in a downgrade in the ratings that are assigned to our debt.  Any downgrade in our rating could result in an increase in our borrowing costs, which would diminish financial results.

 

            We are subject to risks associated with the operation of our wells, 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 for 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.

 

                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

 

13



 

recoveries) and/or expense deferrals.  Additionally, we may be required to provide additional assistance to low income residential customers to help pay their bills without the ability to recover some or all of the additional assistance in rates.

 

            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 various 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 Company’s exposure to market risks, including the risks associated with our use of derivative contracts to hedge commodity prices.

 

Item 1B.     Unresolved Staff Comments
 

            None.

 

14



 

Item 2.        Properties
 

Principal facilities are owned by the Company’s 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 Company’s properties are located on or under (1) public highways under franchises or permits from various governmental authorities, or (2) private properties owned in fee, held by lease, or occupied under perpetual easements or other rights acquired for the most part without warranty of underlying land titles.  The Company’s facilities are generally well maintained and, where necessary, are replaced or expanded to meet operating requirements.

 

Equitable Supply.  This segment’s 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 69% of which is considered undeveloped), which encompasses nearly all of the Company’s 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, 2007, the Company estimated its total proved reserves to be 2,682 Bcfe, including proved undeveloped reserves of 923 Bcfe.  No report has been filed with any federal authority or agency reflecting a 5% or more difference from the Company’s estimated total reserves.  Additional information relating to the Company’s 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:

 

 

 

2007

 

2006

 

2005

 

Natural Gas:

 

 

 

 

 

 

 

MMcf produced

 

82,401

 

80,698

 

78,105

 

Average well-head sales price per Mcfe sold (net of hedges)

 

$

4.89

 

$

4.79

 

$

5.13

 

Crude Oil:

 

 

 

 

 

 

 

Thousands of Bbls produced

 

119

 

112

 

108

 

Average sales price per Bbl

 

$

62.06

 

$

58.35

 

$

53.07

 

 

Average production cost, including severance taxes, of natural gas and crude oil during 2007, 2006 and 2005 was $0.749, $0.768 and $0.771 per Mcfe, respectively.

 

 

 

Natural Gas

 

Oil

 

Total productive wells at December 31, 2007:

 

 

 

 

 

Total gross productive wells

 

12,867

 

22

 

Total net productive wells

 

9,290

 

19

 

Total in-process wells at December 31, 2007:

 

 

 

 

 

Total gross productive wells

 

107

 

 

Total net productive wells

 

83

 

 

 

Total acreage at December 31, 2007:

 

 

 

Total gross productive acres

 

1,016,960

 

Total net productive acres

 

954,010

 

Total gross undeveloped acres

 

2,286,759

 

Total net undeveloped acres

 

2,145,175

 

 

 

15



 

Number of net productive and dry exploratory and development wells drilled:

 

 

 

2007

 

2006

 

2005

 

Exploratory wells:

 

 

 

 

 

 

 

Productive

 

 

 

 

Dry

 

 

 

 

Development wells:

 

 

 

 

 

 

 

Productive

 

455.8

 

455.0

 

344.2

 

Dry

 

0.5

 

1.0

 

1.0

 

 

            Selected data by state (at December 31, 2007 unless otherwise noted):

 

 

 

Kentucky

 

West
Virginia

 

Virginia

 

Pennsylvania

 

Ohio(a)

 

Total

 

Natural gas and oil production (MMcfe) — 2007

 

37,488

 

21,205

 

23,044

 

1,377

 

 

83,114

 

Natural gas and oil production (MMcfe) — 2006

 

35,699

 

20,534

 

23,723

 

1,415

 

 

81,371

 

Natural gas and oil production (MMcfe) — 2005

 

33,849

 

19,924

 

21,913

 

2,247

 

822

 

78,755

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net revenue interest (%)

 

84.7

%

63.8

%

52.4

%

88.6

%

 

68.0

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total gross productive wells (b)

 

4,968

 

4,696

 

2,538

 

687

 

 

12,889

 

Total net productive wells.

 

4,132

 

2,914

 

1,576

 

687

 

 

9,309

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total gross acreage

 

1,440,903

 

1,202,114

 

536,503

 

124,199

 

 

3,303,719

 

Total net acreage

 

1,374,619

 

1,085,761

 

514,674

 

124,131

 

 

3,099,185

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves (Bcfe)

 

926

 

498

 

307

 

28

 

 

1,759

 

Proved undeveloped reserves (Bcfe).

 

423

 

380

 

120

 

 

 

923

 

Proved developed and undeveloped reserves (Bcfe).

 

1,349

 

878

 

427

 

28

 

 

2,682

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross proved undeveloped drilling locations

 

1,270

 

1,285

 

856

 

 

 

3,411

 

Net proved undeveloped drilling locations

 

1,229

 

1,260

 

474

 

 

 

2,963

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Approximate miles of gathering line

 

3,400

 

2,600

 

1,500

 

 

 

7,500

 


(a)          Relates to certain non-core gas properties sold in May 2005.  See Note 4 to the Company’s Consolidated Financial Statements.

 

(b)         At December 31, 2007, the Company had approximately 116 multiple completion wells.

 

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 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 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 Pennsylvania are primarily in tight sand formations with depths ranging from 3,000 feet to 5,000 feet and average spacing of 40 acres.

 

16



 

The gathering operations own or operate approximately 7,500 miles of gathering line and 204 compressor units comprising 110 compressor stations with approximately 181,300 horse power of installed capacity, as well as other general property and equipment.

 

Substantially all of Equitable Supply’s 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 owns and leases office space in Pennsylvania, West Virginia, Virginia and Kentucky.

 

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.

 

The distribution operations consist of approximately 4,100 miles of pipe in Pennsylvania, West Virginia and Kentucky.  The interstate pipeline operations consist of approximately 3,200 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.  The addition of the Big Sandy Pipeline is expected to add 68 miles of transmission line and 9,000 horse power of installed capacity in Kentucky.  Equitrans has 14 natural gas storage reservoirs with approximately 496 MMcf per day of peak delivery capability and 63 Bcf of storage capacity of which 32 Bcf is working gas.  These storage reservoirs are clustered, with 8 in northern West Virginia and 6 in southwestern Pennsylvania.

 

Headquarters.  The corporate headquarters and other operations are located in leased office space in Pittsburgh, Pennsylvania.

 

Item 3.       Legal Proceedings

 

            Federal Trade Commission v. Equitable Resources, Inc. et al, Before Federal Trade Commission

 

            On March 14, 2007, the Federal Trade Commission (FTC) issued an administrative complaint challenging the Company’s proposed acquisition of Peoples from Dominion. Each of the Company, Dominion and Peoples were named as parties in the complaint.

 

            The complaint charged that the acquisition agreement violated Section 5 of the Federal Trade Commission Act, as amended, 15 U.S.C. § 45 (which prohibits unfair methods of competition in or affecting commerce), and that the acquisition, if consummated, would violate Section 7 of the Clayton Act, as amended, 15 U.S.C. § 18 (which prohibits conduct which substantially lessens competition and/or tends to create a monopoly in a relevant market), and Section 5 of the Federal Trade Commission Act. The relief sought by the FTC in the complaint included, among other things, (i) an order preventing the Company from acquiring Peoples, (ii) a prohibition against any transaction between the Company and Dominion that combines their operations in the relevant markets except as may be approved by the FTC, and (iii) any other relief appropriate to correct the anticompetitive effects of the transaction or to restore Peoples as a viable, independent competitor in the relevant market.

 

            On January 15, 2008, the Company and Dominion mutually agreed to terminate the definitive agreement pursuant to which the Company was to acquire Peoples and Hope and, based upon this termination, the administrative complaint was dismissed on January 31, 2008.

 

            Federal Trade Commission v. Equitable Resources, Inc. et al, United States Court of Appeals for the Third Circuit

 

            On April 13, 2007, the FTC filed a complaint in the U.S. District Court for the Western District of Pennsylvania seeking a preliminary injunction to enjoin the Company’s proposed acquisition of Peoples from Dominion. Each of the Company, Dominion and Peoples are named as defendants in the complaint. The relief sought by the FTC in the complaint was an injunction to maintain the status quo during the pendency of the administrative proceeding described above. On May 14, 2007, the District Court dismissed the FTC’s request for a

 

17



 

preliminary injunction on the basis that the state action immunity doctrine barred the FTC’s claim.  The FTC appealed the dismissal to the United States Court of Appeals for the Third Circuit. On June 1, 2007, the Third Circuit issued an order enjoining the transaction pending further order of the Third Circuit.  On February 4, 2008, the FTC filed a motion seeking to have the FTC’s appeal to the Third Circuit declared moot and the District Court opinion vacated in light of the termination of the acquisition agreement.  The Company has filed an opposition to the motion.

 

                Kay Company, LLC et al v. Equitable Production Company et al, U.S. District Court, Southern District of West Virginia

 

            On September 13, 2006, several royalty owners who have entered into leases with Equitable Production Company, a subsidiary of the Company, filed a gas royalty action in the Circuit Court of Roane County, West Virginia. The suit was served on July 31, 2006 and alleges that Equitable Production Company has failed to pay royalties on the fair value of the gas produced and marketed from the leases and has taken improper post-production deductions from the royalties paid. It seeks class certification, compensatory and punitive damages, an accounting, and other relief based on alleged breach of contract, breach of fiduciary duty and fraudulent concealment.  Equitable Production Company removed the suit to the U.S. District Court for the Southern District of West Virginia on August 7, 2006. The plaintiffs have filed an amended complaint naming the Company as an additional defendant.

 

            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 a case where a class of royalty owners in the state of West Virginia had filed a lawsuit claiming that the defendant 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 has appealed the verdict, this decision may ultimately impact other royalty interest rights in West Virginia. The Company is vigorously defending its case and believes that the claims and facts 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.

 

            In addition to the claims disclosed above, in the ordinary course of business, various other 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 other 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 other 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 Company’s security holders during the last quarter of its fiscal year ended December 31, 2007.

 

18



 

Executive Officers of the Registrant (as of February 22, 2008)

 

Name and Age

 

Current Title (Year Initially Elected an
Executive Officer)

 

Business Experience

John A. Bergonzi (55)

 

Vice President, Finance (2003)

 

Elected to present position July 2007; Vice President and Corporate Controller from January 2003 to June 2007; Corporate Controller and Assistant Treasurer from December 1995 to December 2002.

 

 

 

 

 

Theresa Z. Bone (44)

 

Vice President and Corporate
Controller (2007)

 

Elected to present position July 2007; Vice President and Controller of Equitable Utilities from December 2004 until July 2007; Vice President and Controller of Equitable Supply from May 2000 to December 2004.

 

 

 

 

 

Philip P. Conti (48)

 

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 (45)

 

Senior Vice President and
President, Midstream and
Distribution (2003)

 

Elected to present position in January 2008; Senior Vice President, and President, Equitable Utilities from February 2007 to December 2007; Vice President, and President, Equitable Utilities from February 2004 to February 2007; President, Equitable Gas Company from January 2003 to January 2004.

 

 

 

 

 

Martin A. Fritz (43)

 

Vice President and President,
Midstream (2006)

 

Elected to current position January 2008; Vice President and Chief Administrative Officer from February 2007 to December 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 (54)

 

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.

 

 

 

 

 

M. Elise Hyland (48)

 

President, Equitable Gas (2008)

 

Elected to present position July 2007; Senior Vice President, Customer Operations Equitable Gas Company from March 2004 to June 2007; Vice President, Strategic Planning and Analysis Equitable Gas Company from January 2003 to February 2004.

 

 

 

 

 

Joseph E. O’Brien (55)

 

Senior Vice President (2001)

 

Elected to present position January 2008; Senior Vice President and President, Equitable Supply from February 2007 to January 2008; 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. O’Loughlin (61)

 

Senior Vice President, General
Counsel and Corporate Secretary
(1996)

 

Elected to present position January 2002.

 

 

 

 

 

Charlene Petrelli (47)

 

Vice President and Chief Human
Resources Officer (2003)

 

Elected to present position February 2007; Vice President, Human Resources from January 2003 to February 2007.

 

19



 

 

 

 

 

 

David L. Porges (50)

 

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.

 

 

 

 

 

Steven T. Schlotterbeck (42)

 

Vice President and President,
Production (2008)

 

Elected to present position January 2008; Executive Vice President, Exploration and Development, Equitable Production Company (EPC) from July 2007 to December 2007; Managing Director, Exploration and Production Planning and Development, EPC from January 2006 to June 2007; Senior Vice President, Production and Planning, EPC from August 2003 to December 2005; Vice President, Production Management, EPC from April 2002 to July 2003.


All executive officers have executed agreements with the Company and serve at the pleasure of the Company’s Board of Directors.  Officers are elected annually to serve during the ensuing year or until their successors are chosen and qualified.

 

 

20



 

PART II

 

Item 5.           Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

The Company’s 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):

 

 

 

2007

 

2006

 

 

 

High

 

Low

 

Dividend

 

High

 

Low

 

Dividend

 

1st Quarter

 

$

50.50

 

$

39.26

 

$

0.22

 

$

39.02

 

$

34.05

 

$

0.21

 

2nd Quarter

 

53.70

 

47.96

 

0.22

 

37.00

 

31.59

 

0.22

 

3rd Quarter

 

54.42

 

44.57

 

0.22

 

37.48

 

32.55

 

0.22

 

4th Quarter

 

56.75

 

51.54

 

0.22

 

44.48

 

34.83

 

0.22

 

 

As of February 12, 2008, there were 3,793 shareholders of record of the Company’s common stock.

 

The amount and timing of dividends is subject to the discretion of the Board of Directors and depends on business conditions, the Company’s 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 Company’s repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred in the three months ended December 31, 2007.

Period

 

Total
number of
shares (or
units)
purchased
(a)

 

Average
price
paid per
share (or
unit)

 

Total number of
shares (or units)
purchased as
part of publicly
announced
plans or
programs

 

Maximum number
(or approximate
dollar value) of
shares (or units) that
may yet be purchased
under the plans or
programs (b)

 

 

 

 

 

 

 

 

 

 

 

October 2007 (October  1 — October 31)

 

1,525

 

$

53.38

 

 

8,385,400

 

 

 

 

 

 

 

 

 

 

 

November 2007 (November 1 — November 30)

 

81,949

 

$

53.54

 

 

8,385,400

 

 

 

 

 

 

 

 

 

 

 

December 2007 (December 1 — December 31)

 

602,454

 

$

53.62

 

 

8,385,400

 

 

 

 

 

 

 

 

 

 

 

Total

 

685,928

 

 

 

 

 

 


(a)          Includes 682,765 shares delivered in exchange for the exercise of stock options to cover award cost and tax withholding and 3,163 shares for Company-directed purchases made by the Company’s 401(k) plans.

 

(b)         Equitable’s 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.

 

 

21



 

Stock Performance Graph

 

The following graph compares the most recent five-year cumulative total return attained by shareholders on 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, 2002 in the Company’s common stock, in the S & P 500 index, and in the peer group.  Relative performance is tracked through December 31, 2007.

 

 

 

 

2002

 

2003

 

2004

 

2005

 

2006

 

2007

 

EQUITABLE RESOURCES, INC.

 

100.00

 

125.54

 

182.70

 

226.67

 

264.09

 

342.95

 

SELF-CONSTRUCTED PEER GROUP (1)

 

100.00

 

124.44

 

155.16

 

189.72

 

224.36

 

249.62

 

S & P 500

 

100.00

 

128.68

 

142.69

 

149.70

 

173.34

 

182.87

 


(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 Corporation, ONEOK, Inc., Peoples Energy Corporation, Questar Corporation and Southwestern Energy Company.  This is the same peer group used for the company’s 2007 short-term incentive plans.  During 2007, Keyspan Corporation, Kinder Morgan, Inc. and Peoples Energy Corporation completed significant transactions which resulted in those companies merging out of existence or going private.  Those companies are included in the calculation from December 31, 2002 through December 31, 2006, at which time they are removed from the peer group calculation.  The company uses other peer groups for other purposes, including its executive performance incentive program under the 1999 Long-Term Incentive Plan.

 

See item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information relating to compensation plans under which the Company’s securities are authorized for issuance.

 

 

22



 

Item 6.    Selected Financial Data

 

 

 

As of and for the year ended December 31,

 

 

 

2007

 

2006

 

2005

 

2004(a)

 

2003(a)

 

 

 

(Thousands, except per share amounts)

 

Operating revenues

 

$

1,361,406

 

$

1,267,910

 

$

1,253,724

 

$

1,045,183

 

$

876,574

 

Income from continuing operations before cumulative effect of accounting change (b)

 

$

257,483

 

$

216,025

 

$

258,574

 

$

298,790

 

$

165,750

 

Income from continuing operations before cumulative effect of accounting change per share of common stock (c)

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

2.12

 

$

1.79

 

$

2.14

 

$

2.42

 

$

1.34

 

Diluted

 

$

2.10

 

$

1.77

 

$

2.09

 

$

2.37

 

$

1.31

 

Total assets (d)

 

$

3,936,971

 

$

3,282,255

 

$

3,342,285

 

$

3,205,346

 

$

2,948,073

 

Long-term debt (d)

 

$

753,500

 

$

763,500

 

$

766,500

 

$

626,500

 

$

647,000

 

Cash dividends declared per share of common stock (c)

 

$

0.880

 

$

0.870

 

$

0.820

 

$

0.720

 

$

0.485

 


(a)          Amounts for 2004 and 2003 have been reclassified to reflect the operating results of the NORESCO segment as discontinued operations.

(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.

(c)          All per share amounts have been adjusted for the two-for-one stock split effected on September 1, 2005.

(d)         Certain previously reported amounts have been reclassified to conform to the current year presentation.

 

See Item 1A, “Risk Factors,” Item 7, “Management’s 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 Company’s future financial condition.

 

23



 

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

 

Consolidated Results of Operations

 

Equitable’s consolidated income from continuing operations for 2007 was $257.5 million, or $2.10 per diluted share, compared with $216.0 million, or $1.77 per diluted share, for 2006, and $258.6 million, or $2.09 per diluted share, for 2005.

 

The $41.5 million increase in income from continuing operations from 2006 to 2007 resulted from several factors including the 2007 pre-tax gain of $126.1 million on the sale of assets in the Nora area and a $17.0 million increase in production revenues at Equitable Supply.  At Equitable Utilities, increases in marketing revenues due to favorable storage asset optimization opportunities that were captured at a time of unusually high commodity price volatility which settled in the first quarter of 2007, and increases in distribution revenues due to colder weather in Equitable Gas’s service territory contributed to the increase in income from continuing operations over 2006.

 

The increases in revenue between years were partially offset by a $46.2 million increase in incentive compensation expense, the $10.1 million write-off of deferred transaction costs related to the termination of the proposed acquisition of Peoples and Hope, and $9.7 million in higher depletion, depreciation and amortization, primarily at Equitable Supply.  In addition, higher labor costs and charges for certain legal reserves, settlements and related expenses partially offset the increases in income from continuing operations.

 

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 now terminated acquisition of Peoples and Hope.  The Company also recorded a reserve for certain legal disputes.  The impact of lower realized selling prices ($25.8 million) and warmer weather ($9.3 million) also contributed to the decrease between years.

 

These unfavorable effects on income from continuing operations between 2005 and 2006 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 Company’s 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 Company’s effective tax rate for its continuing operations for the year ended December 31, 2007, was 35.9% compared to 33.7% for the year ended December 31, 2006, and 37.2% for the year ended December 31, 2005.  The higher effective tax rate in 2007 is the result of several factors including a change in the West Virginia state tax law and a reduced 2006 rate resulting from the release of state valuation allowances related to state net operating loss carryovers.  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 Company’s consolidated results based on operating income, equity in earnings of nonconsolidated investments, and other income.  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 $65.3 million, $21.9 million and $48.0 million in 2007, 2006 and 2005, respectively, were not allocated to business segments.  The higher unallocated expenses in 2007 and 2005 compared to 2006 primarily relate to lower long-term incentive expenses in 2006.

 

The Company has reconciled each segment’s operating income, equity in earnings of nonconsolidated investments and other income to the Company’s consolidated operating income, equity in earnings of

 

24



 

nonconsolidated investments and other income totals in Note 2 to the Consolidated Financial Statements.  Additionally, these subtotals are reconciled to the Company’s consolidated net income in Note 2.  The Company has also reported the components of each segment’s operating income and various operational measures in the sections below, and where appropriate, has provided information describing how a measure was derived.  Equitable’s management believes that presentation of this information is useful to management and investors in assessing the financial condition, operations and trends of each of Equitable’s 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.

 

    As discussed in Item 1 above, the Company realigned its business segments in January 2008.

 

Equitable Supply

 

Overview

 

Equitable Supply is focused on organic reserve and production growth through its drilling program.  The Company drilled 634 gross wells (456 net) wells in 2007, including 88 horizontal shale wells.  Proved reserves increased 165 Bcfe (7%) to 2,682 Bcfe during the year.

 

Equitable Supply’s revenues for 2007 increased 3% compared to 2006 revenues.  Despite a $0.37 decrease in the average NYMEX price in 2007, the average well-head sales price increased 3% as a result of a less unfavorable hedge impact compared to 2006 and favorable liquids prices.  Sales volumes increased more than 5% from 2006, excluding volumes from properties sold during 2007, primarily as a result of increased production from the 2007 and 2006 drilling programs partially offset by the normal production decline in the Company’s producing wells.

 

Operating expenses at Equitable Supply increased 9% primarily due to charges for legal reserves, settlements and related expenses, as well as higher depletion resulting from increased drilling investments as the Company continues to expand its development in the Appalachian Basin.

 

During 2007, the Equitable Supply segment sold to Pine Mountain Oil and Gas, Inc. (PMOG), a subsidiary of Range Resources Corporation (Range), a portion of the Company’s interests in certain gas properties in the Nora area totaling approximately 74 Bcf of proved reserves.  Also during 2007, the Equitable Supply segment contributed certain Nora area gathering facilities and pipelines to Nora Gathering, LLC, a newly formed entity that is equally owned by the Company and PMOG, in exchange for a 50% equity interest in the LLC and cash.  These transactions resulted in a net gain of $126.1 million.  See Note 4 to the Company’s Consolidated Financial Statements for further discussion of these transactions.  As a result of the gathering asset contribution, gathered volumes, gathering revenues and gathering-related expenses related to the Nora area gathering activities are no longer included in Equitable Supply’s operating results.  However, Equitable Supply records its 50% equity interest in the earnings of Nora Gathering, LLC in equity in earnings of nonconsolidated investments.

 

The Company is working to obtain the third party consents required to complete the transaction on a portion of the property not included in the 2007 closing.  A final closing covering the remainder of the gas properties and related remaining gathering assets included in the above transactions would reduce the Company’s proved reserves by a maximum of approximately 9 Bcf.

 

During the third quarter of 2007, the Equitable Supply segment purchased an additional working interest of approximately 13.5% in certain gas properties in the Roaring Fork area totaling approximately 12.3 Bcf of proved reserves and certain gathering assets from the minority interest holders.  See Note 5 to the Company’s Consolidated Financial Statements for further discussion of this transaction.

 

25



 

Results of Operations

 

 

 

Years Ended December 31,

 

 

 

2007

 

2006

 

%
change
2007 -
2006

 

2005

 

%
change
2006 -
2005

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATIONAL DATA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production:

 

 

 

 

 

 

 

 

 

 

 

Natural gas and oil production (MMcfe) (a)

 

83,114

 

81,371

 

2.1

 

78,755

 

3.3

 

Company usage, line loss (MMcfe)

 

(6,035

)

(5,215

)

15.7

 

(4,897

)

6.5

 

Natural gas inventory usage, net (MMcfe)

 

 

 

 

51

 

(100.0

)

Total sales volumes (MMcfe)

 

77,079

 

76,156

 

1.2

 

73,909

 

3.0

 

 

 

 

 

 

 

 

 

 

 

 

 

Average (well-head) sales price ($/Mcfe)

 

$

4.98

 

$

4.83

 

3.1

 

$

5.17

 

(6.6

)

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses (LOE), excluding production taxes ($/Mcfe)

 

$

0.31

 

$

0.29

 

6.9

 

$

0.28

 

3.6

 

Production taxes ($/Mcfe)

 

$

0.44

 

$

0.48

 

(8.3

)

$

0.49

 

(2.0

)

Production depletion ($/Mcfe)

 

$

0.70

 

$

0.62

 

12.9

 

$

0.59

 

5.1

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering:

 

 

 

 

 

 

 

 

 

 

 

Gathered volumes (MMcfe)

 

94,210

 

108,592

 

(13.2

)

121,044

 

(10.3

)

Average gathering fee ($/Mcfe)

 

$

1.14

 

$

1.02

 

11.8

 

$

0.82

 

24.4

 

Gathering and compression expense ($/Mcfe)

 

$

0.49

 

$

0.42

 

16.7

 

$

0.31

 

35.5

 

Gathering and compression depreciation ($/Mcfe)

 

$

0.17

 

$

0.14

 

21.4

 

$

0.12

 

16.7

 

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Production operating income

 

$

231,417

 

$

231,849

 

(0.2

)

$

260,931

 

(11.1

)

Gathering operating income

 

32,128

 

37,315

 

(13.9

)

32,650

 

14.3

 

Total operating income

 

$

263,545

 

$

269,164

 

(2.1

)

$

293,581

 

(8.3

)

 

 

 

 

 

 

 

 

 

 

 

 

Production depletion

 

$

58,264

 

$

50,330

 

15.8

 

$

46,750

 

7.7

 

Gathering and compression depreciation

 

15,693

 

15,411

 

1.8

 

14,312

 

7.7

 

Other DD&A

 

5,903

 

4,759

 

24.0

 

3,835

 

24.1

 

Total DD&A

 

$

79,860

 

$

70,500

 

13.3

 

$

64,897

 

8.6

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures (thousands) (b)

 

$

715,722

 

$

335,948

 

113.0

 

$

264,095

 

27.2

 

 

26



 

 

 

Years Ended December 31,

 

 

 

2007

 

2006

 

%
change
2007 -
2006

 

2005

 

%
change
2006 -
2005

 

 

 

 

 

 

 

 

 

 

 

 

 

FINANCIAL DATA (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production revenues

 

$

394,583

 

$

377,626

 

4.5

 

$

390,290

 

(3.2

)

Gathering revenues (c)

 

107,092

 

110,945

 

(3.5

)

98,901

 

12.2

 

Total operating revenues

 

501,675

 

488,571

 

2.7

 

489,191

 

(0.1

)

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

LOE, excluding production taxes

 

25,361

 

23,818

 

6.5

 

22,427

 

6.2

 

Production taxes (d)

 

36,912

 

38,653

 

(4.5

)

38,288

 

1.0

 

Exploration expense

 

862

 

802

 

7.5

 

768

 

4.4

 

Gathering and compression (O&M)

 

45,844

 

45,860

 

 

38,101

 

20.4

 

SG&A

 

49,291

 

39,774

 

23.9

 

30,610

 

29.9

 

Impairment charges

 

 

 

 

519

 

(100.0

)

DD&A

 

79,860

 

70,500

 

13.3

 

64,897

 

8.6

 

Total operating expenses

 

238,130

 

219,407

 

8.5

 

195,610

 

12.2

 

Operating income

 

$

263,545

 

$

269,164

 

(2.1

)

$

293,581

 

(8.3

)

 

 

 

 

 

 

 

 

 

 

 

 

Equity in earnings of nonconsolidated investments

 

$

2,949

 

$

129

 

2,186

 

$

493

 

(73.8

)

Other income

 

$

6,467

 

$

800

 

708

 

$

 

 

 


(a)          Natural gas and oil production represents the Company’s 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.

 

(b)         2007 capital expenditures include $28.1 for the acquisition of working interests in wells in the Roaring Fork area and 2005 capital expenditures include $57.5 million for the acquisition of the limited partnership interest in Eastern Seven Partners, L.P. (ESP).

 

(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, 2007 vs. December 31, 2006

 

Equitable Supply’s operating income totaled $263.5 million for 2007 compared to $269.2 million for 2006, a decrease of approximately $5.6 million between years.  Gathering operating income decreased $5.2 million due to a decrease in gathered volumes, partially offset by an increase in the average gathering fee.  Production operating income decreased $0.4 million primarily due to an increase in production operating expenses, partially offset by an increase in average well-head sales price and increased sales volumes.

 

Total operating revenues were $501.7 million for 2007 compared to $488.6 million for 2006.  The $13.1 million increase in total operating revenues was primarily due to a 3% increase in the average well-head sales price and a 1% increase in production total sales volumes, partially offset by a 4% decrease in gathering revenues.  The $0.15 per Mcfe increase in the average well-head sales price was mainly attributable to a higher percentage of

 

27



 

unhedged gas sales, a higher realized hedge price and a higher liquids price.  The 1% increase in production total sales volumes was primarily the result of the 2007 and 2006 drilling programs, partially offset by the normal production decline in the Company’s wells and the 2007 sale to PMOG of interests which provided sales of 3,044 MMcfe during 2006.  The 4% decrease in gathering revenues was attributable to a 13% decline in gathered volumes, partially offset by a 12% increase in the average gathering fee.  The decrease in gathered volumes is primarily the result of a reduction in volumes gathered for Company production due to the contribution of gathering facilities and pipelines to Nora Gathering, LLC, partially offset by increased Company production.  The increase in average gathering fee is reflective of the Company’s commitment to ensuring that this fee is sufficient to cover increasing operating costs.

 

Operating expenses totaled $238.1 million for 2007 compared to $219.4 million for 2006.  The $18.7 million increase in operating expenses was due to increases of $9.5 million in SG&A, $9.4 million in DD&A and $1.5 million in LOE, excluding production taxes, partially offset by a decrease of $1.7 million in production taxes.  The increase in SG&A was primarily due to increased legal reserves, settlements and related expenses in 2007 compared to the reduction of certain liability reserves in 2006, partially offset by a 2006 increase to the reserve established for uncollectible accounts. The increase in DD&A was primarily due to increased depletion expense resulting from both increases in the unit rate ($6.9 million) and volume ($1.0 million), as well as increased depreciation on a higher asset base ($1.5 million). The $0.08 increase in the depletion rate is primarily attributable to the increased investment in oil and gas producing properties. The increase in LOE, excluding production taxes, was attributable to personnel costs, environmental costs and liability insurance costs.  The decrease in production taxes was primarily due to a decrease in severance taxes arising out of the sale of assets in the Nora area.  Gathering and compression expense remained flat year over year as increased expense in 2007 for the Company’s remaining gathering facilities was mostly offset by decreased expenses relating to the gathering asset contribution to Nora Gathering LLC and a $3.3 million pension and other postretirement benefits charge for an early retirement program in the fourth quarter of 2006.  The increased gathering and compression expense at the remaining facilities was primarily due to increased electricity charges on newly installed electric compressors, increased field line and compressor maintenance related to the Company’s infrastructure investments, increased field labor and related employment costs and increased compliance costs.  The per unit gathering and compression rate increased as the per unit rate for the Nora area properties contributed in 2007 was significantly lower than the rate for the Company’s remaining properties.

 

Equity in earnings of nonconsolidated investments totaled $2.9 million for 2007 compared to equity earnings of $0.1 million for 2006.  The $2.8 million increase was primarily due to equity earnings of $2.6 million recorded in 2007 for Equitable Supply’s investment in Nora Gathering, LLC.

 

Other income represents AFUDC-Equity for the construction of the FERC-regulated Big Sandy Pipeline.  The $5.7 million increase from 2006 to 2007 is the result of increased capital spending for this infrastructure project.

 

Fiscal Year Ended December 31, 2006  vs. December 31, 2005

 

Equitable Supply’s 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 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 negative price adjustment and increased prices on hedged volumes.  The 2005 price adjustment was principally due to the Company’s conclusion that the well-head sales price allocated to a third party’s 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 Company’s wells.  The 12% increase in

 

28



 

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 Company’s 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 this transfer, 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, excluding production taxes, and $0.4 million in production taxes.  The increase in SG&A was the result of reserves established in connection with certain legal disputes and bad debt expenses.  The increase in gathering and compression was primarily due to the $3.3 million pension and other postretirement benefits charges, 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, excluding production taxes, 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 Company’s 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 Company’s relocation of its corporate headquarters and other operations to its new consolidated office space.

 

See “Capital Resources and Liquidity” section for discussion of Equitable Supply’s capital expenditures during 2007, 2006 and 2005.

 

Outlook

 

Equitable Supply’s business strategy is focused on organic growth of the Company’s natural gas reserves.  The most significant challenge facing the Company and other producers in the Appalachian Basin is the availability of the pipeline infrastructure required to transport produced natural gas from the well to market.  As the Company continues to expand the development of its reserves, primarily through horizontal drilling, the need for such infrastructure is increasingly important.  Key elements of Equitable Supply’s strategy include:

 

·                  Expanding reserves and production through horizontal drilling in Kentucky and West Virginia.  The Company’s capital commitments budget for 2008 includes $536 million for well development.  Through this capital program the Company will seek to maximize the value of its existing asset base by developing its large acreage position, which the Company believes holds significant production and reserve growth potential.  A substantial portion of the Company’s 2008 drilling efforts will be focused on drilling horizontal wells in shale formations in Kentucky and West Virginia.

 

·                  Exploiting additional reserve potential through key emerging development plays.  In 2008, the Company will examine the potential for exploitation of gas reserves in new geological formations and through different technologies.  Plans include re-entry wells in the Devonian shale, testing the Devonian shale in Virginia, and high and low pressure Marcellus shale wells.  In addition, the Company will obtain proprietary seismic data in order to evaluate deep drilling opportunities for 2009.  Approximately 15% of wells drilled in 2008 are expected to be located in these emerging development plays in the Appalachian Basin.

 

29



 

·                  Investing in midstream transportation, gathering and processing in the Appalachian Basin.  The Company’s investment in midstream infrastructure is focused on its transportation, gathering and processing capacity including completion of the Big Sandy Pipeline and the Langley processing facility.  Infrastructure investment will help mitigate curtailments and increase the flexibility and reliability of the Company’s gathering systems in transporting gas to market.  The Company has adopted a “pipe-driven” business model whereby production growth will occur in conjunction with the completion of a series of pipeline and compression projects known as “corridors.”  A corridor will represent a large area of acreage typically inclusive of a thousand or more well sites that requires investment in new pipeline and compression.   Each corridor will radiate out from a central processing facility, such as the Company’s Langley facility, which will then connect to larger pipes, such as the Big Sandy Pipeline, that transport gas to interstate markets.

 

Equitable Utilities

 

Overview

 

Equitable Utilities’ net operating revenues increased 4% from 2006 to 2007.  This increase was primarily due to favorable storage asset optimization at energy marketing and colder weather in Equitable Gas’s service territory in 2007, partially offset by a reduction in the pipeline operations net revenues due to a favorable adjustment in 2006 for the settlement of the Equitrans rate case.  The marketing business is primarily driven by the optimization of the Company’s 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 wider for transactions settled in 2007 than they were for contracts which settled in 2006.  Increases in net operating revenues were offset by increases in total operating expenses in 2007 of $22.0 million, or 15%, primarily due to the write-off of Peoples and Hope acquisition-related costs that were previously deferred, higher corporate allocations, and increased compensation expense.

 

The weather in Equitable Gas’ service territory in 2007 was 7% colder than 2006 but 9% warmer than the 30-year National Oceanic and Atmospheric Administration (NOAA) average for the Company’s service territory.  The weather in 2006 was 15% warmer than the 30-year average.

 

Pennsylvania law requires that local distribution companies develop and implement programs to assist low income customers with paying their gas bills.  The costs of these programs are recovered through rates charged to other residential customers. Equitable Gas has several such programs including the CAP.  In October 2006, Equitable Gas submitted a request for PA PUC approval to increase funding to support the increasing costs of its CAP.  On September 27, 2007, the PA PUC issued an order approving an increase to Equitable’s surcharge, which is designed to offset the costs of CAP.  The revised surcharge went into effect on October 2, 2007.

 

On April 5, 2006, Equitrans entered into a settlement with the FERC that allows Equitrans to institute an annual surcharge for the tracking and recovery of all costs (operations, maintenance and return on invested capital) incurred on and after September 1, 2005, related to Equitrans’ Pipeline Safety Program under the Pipeline Safety Improvement Act of 2002.  Filings to modify the surcharge must be made on or before March 1st of each year for approval by the FERC.  On March 29, 2007, the Company received approval, subject to refund, to institute the surcharge, and on April 1, 2007, the Company commenced billing the surcharge.  On November 26, 2007, the FERC removed the refund condition and approved the surcharge effective April 1, 2007.  As a result of the FERC order, in 2007 Equitrans recognized $1.2 million in deferred revenue as well as $0.7 million in pipeline integrity and safety maintenance costs that were deferred pending receipt of the final FERC order.  The Company anticipates that additional filings to modify the surcharge will continue to be made in future years to recover costs incurred in connection with its Pipeline Safety Program.

 

On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion’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 Peoples and Hope.  In light of the continued delay in achieving the final legal approvals for this transaction, the Company and Dominion agreed to terminate the definitive agreement

 

30



 

pursuant to a mutual termination agreement entered into on January 15, 2008.  As a result, in the fourth quarter of 2007, the Company recognized a charge of $10.1 million for acquisition costs that were previously deferred. Proceedings were initiated by the Federal Trade Commission for the purpose of challenging the Company’s proposed acquisition of Peoples.  See Item 3, “Legal Proceedings” for a description of these proceedings.

 

Results of Operations

 

 

 

Years Ended December 31,

 

 

 

2007

 

2006

 

%
change
2007 -
2006

 

2005

 

%
change
2006 -
2005

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATIONAL DATA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Heating degree days (30 year average = 5,829)

 

5,332

 

4,976

 

7.2

 

5,543

 

(10.2

)

 

 

 

 

 

 

 

 

 

 

 

 

Residential sales and transportation volume (MMcf)

 

23,494

 

21,014

 

11.8

 

24,680

 

(14.9

)

Commercial and industrial volume (MMcf)

 

25,971

 

23,841

 

8.9

 

25,368

 

(6.0

)

Total throughput (MMcf) — Distribution Operations

 

49,465

 

44,855

 

10.3

 

50,048

 

(10.4

)

 

 

 

 

 

 

 

 

 

 

 

 

Net operating revenues (thousands):

 

 

 

 

 

 

 

 

 

 

 

Distribution Operations (regulated):

 

 

 

 

 

 

 

 

 

 

 

Residential

 

$

99,050

 

$

92,497

 

7.1

 

$

102,457

 

(9.7

)

Commercial & industrial

 

42,558

 

42,519

 

0.1

 

46,857

 

(9.3

)

Other

 

8,192

 

8,319

 

(1.5

)

7,544

 

10.3

 

Total Distribution Operations

 

149,800

 

143,335

 

4.5

 

156,858

 

(8.6

)

Pipeline Operations (regulated)

 

67,517

 

72,586

 

(7.0

)

53,767

 

35.0

 

Energy Marketing

 

67,948

 

59,089

 

15.0

 

42,739

 

38.3

 

Total net operating revenues

 

$

285,265

 

$

275,010

 

3.7

 

$

253,364

 

8.5

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating income (thousands):

 

 

 

 

 

 

 

 

 

 

 

Distribution Operations (regulated)

 

$

24,071

 

$

34,807

 

(30.8

)

$

40,322

 

(13.7

)

Pipeline Operations (regulated)

 

26,153

 

33,240

 

(21.3

)

17,345

 

91.6

 

Energy Marketing

 

63,223

 

57,162

 

10.6

 

40,587

 

40.8

 

Total operating income

 

$

113,447

 

$

125,209

 

(9.4

)

$

98,254

 

27.4

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization (DD&A) (thousands):

 

 

 

 

 

 

 

 

 

 

 

Distribution Operations

 

$

20,021

 

$

19,938

 

0.4

 

$

19,483

 

2.3

 

Pipeline Operations

 

8,510

 

8,737

 

(2.6

)

8,317

 

5.0

 

Energy Marketing

 

47

 

56

 

(16.1

)

74

 

(24.3

)

Total DD&A

 

$

28,578

 

$

28,731

 

(0.5

)

$

27,874

 

3.1

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures (thousands)

 

$

87,761

 

$

64,332

 

36.4

 

$

61,005

 

5.5

 

 

31



 

 

 

Years Ended December 31,

 

 

 

2007

 

2006

 

%
change
2007 -
2006

 

2005

 

%
change
2006 -
2005

 

 

 

 

 

 

 

 

 

 

 

 

 

FINANCIAL DATA (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distribution revenues (regulated)

 

$

455,506

 

$

445,168

 

2.3

 

$

469,102

 

(5.1

)

Pipeline revenues (regulated)

 

68,547

 

74,010

 

(7.4

)

57,534

 

28.6

 

Marketing revenues

 

445,153

 

380,149

 

17.1

 

365,625

 

4.0

 

Less: intrasegment revenues

 

(52,385

)

(56,163

)

(6.7

)

(45,804

)

22.6

 

Total operating revenues

 

916,821

 

843,164

 

8.7

 

846,457

 

(0.4

)

 

 

 

 

 

 

 

 

 

 

 

 

Purchased gas costs

 

631,556

 

568,154

 

11.2

 

593,093

 

(4.2

)

Net operating revenues

 

285,265

 

275,010

 

3.7

 

253,364

 

8.5

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

Operating and maintenance (O & M)

 

61,135

 

58,186

 

5.1

 

57,315

 

1.5

 

Selling, general and administrative (SG&A)

 

82,105

 

65,280

 

25.8

 

66,080

 

(1.2

)

Impairment charges

 

 

(2,396

)

(100.0

)

3,841

 

(162.4

)

DD&A

 

28,578

 

28,731

 

(0.5

)

27,874

 

3.1

 

Total operating expenses

 

171,818

 

149,801

 

14.7

 

155,110

 

(3.4

)

Operating income

 

$

113,447

 

$

125,209

 

(9.4

)

$

98,254

 

27.4

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income

 

$

1,178

 

$

642

 

83.5

 

$

344

 

86.6

 

 

Fiscal Year Ended December 31, 2007 vs. December 31, 2006

 

Equitable Utilities’ operating income totaled $113.4 million for 2007 compared to $125.2 million for 2006.  An increase in net operating revenues was more than offset by increased operating expenses. Increased operating expenses were primarily related to the fourth quarter of 2007 write-off of deferred acquisition costs that resulted from the termination of the agreement to acquire Peoples and Hope.  The 2007 operating income was also lower due to the following 2006 favorable non-recurring items: settlement of the Equitrans rate case for the pipeline operations and a gain from the partial reversal of a 2005 impairment charge in connection with the Company’s office consolidation.

 

Net operating revenues were $285.3 million for 2007 compared to $275.0 million for 2006.  The $10.3 million increase in net operating revenues was primarily due to increased energy marketing net operating revenues and increased distribution residential net operating revenues, partially offset by a reduction in pipeline net operating revenues.  The $8.9 million increase in marketing net operating revenues was a result of storage asset optimization realized as the energy marketing operations used contractual storage capacity to capture unusually high summer-to-winter price spreads.  These price spreads were captured at a time of high volatility and the transactions settled in 2007.  Distribution net operating revenues increased by $6.5 million as a result of weather that was 7% colder than the prior year resulting in a 2,480 MMcf increase in residential sales and transportation volumes from 2006 to 2007.  Commercial and industrial volumes increased 2,130 MMcf from 2006 to 2007 primarily due to an increase in usage by one industrial customer.  These high volume industrial sales have very low margins and did not significantly impact total net operating revenues.  The pipeline net operating revenues declined by $5.1 million in 2007, primarily attributable to a one-time positive effect of the Equitrans rate case settlement of $7.0 million in 2006.  This reduction in net operating revenues was partially offset by Equitrans’ Pipeline Safety surcharge that was formally approved by the FERC in November 2007 and increased firm transportation activities year over year.

 

32



 

Operating expenses totaled $171.8 million for 2007 compared to $149.8 million for 2006.  Operating expenses for 2007 included a $10.1 million write-off of costs previously deferred related to the now terminated agreement to acquire Peoples and Hope, while 2006 included a one-time benefit of $2.4 million from the partial reversal of the 2005 impairment charge.  Other increases in SG&A expense included higher corporate overhead allocations, higher incentive compensation costs, increased labor costs including information technology enhancements and costs associated with a customer experience study of the Equitable Gas customers.  These increases were partially offset by a reduction in bad debt expense as a result of the continued organizational focus on collections and a reduction in delinquent accounts receivable and net write-offs.  O&M expense increased $2.9 million as a result of increased maintenance activities and fleet-related costs at the distribution and pipeline operations.  The 2007 pipeline O&M expense also included the recognition of $0.9 million of pipeline safety costs that were deferred pending the FERC order on the Equitrans Pipeline Safety surcharge.

 

Other income represents AFUDC-Equity and the increase over 2006 is primarily a result of increased capital spending on pipeline safety and integrity projects.

 

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 Company’s office consolidation and a gain in 2006 as a result of the partial reversal of the 2005 office impairment charge.  These improvements were partially offset by the impact of transition planning costs incurred for the now terminated agreement to acquire Peoples and Hope and a reduction in distribution net operating revenues 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’ 2004 and 2005 FERC rate case and the implementation of new rates and contracts in connection with that settlement.  The settlement’s approval, which occurred in April 2006, improved net operating revenues by $7.0 million related to years 2005 and prior; in addition, new contract rates and billing determinants in the settlement resulted in a $6.1 million increase.  The transfer of certain gathering assets from Equitable Supply resulted in the remaining $5.7 million increase.  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 a 3,666 MMcf decrease in residential sales and transportation volumes resulting from 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 office impairment in connection with the Company’s relocation into its new, consolidated office space.  Operating expenses for 2006 include $12.3 million of transition planning costs incurred for the now terminated agreement to acquire Peoples and Hope; 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 in connection with the FERC rate case settlement; and the reversal of $2.4 million of the 2005 office impairment charge.  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.

 

33



 

See “Capital Resources and Liquidity” section for discussion of Equitable Utilities’ capital expenditures during 2007, 2006 and 2005.

 

Outlook

 

Equitable Utilities’ business strategy is focused on efficiently and effectively operating the Company’s assets to optimize its return.  Key elements of Equitable Utilities’ strategy include:

 

·                  Enhancing the value of the regulated utility operations.  Equitable Utilities will seek to enhance the value of its existing distribution assets by establishing a reputation for excellent customer service; effectively managing its capital spending; improving the efficiency of its work force through superior work management; and continuing to leverage technology throughout its operations.  Equitable Utilities is currently evaluating a base rate case filing for the Pennsylvania distribution business in order to improve returns through regulatory arrangements that fairly balance the interests of customers and shareholders.

 

·                  Growth and expansion of storage, gathering and commercial operations.  Equitable Utilities plans to continue to provide disciplined incremental earnings growth through its storage, gathering and commercial operations, including expanding these assets where there are additional opportunities to provide economical storage services in the Company’s operating regions.

 

·                  Expansion of market footprint.  As Equitable grows its Appalachian production base, the Company is exploring opportunities to expand its market footprint in the Northeast and Mid-Atlantic gas sales markets.  To this end, the Company has previously announced its intent to participate with Tennessee Gas Pipeline in the development of the Northeast Passage Project.  In addition, the Company continues discussions with other interstate pipelines in the growing Mid-Atlantic and Southeast markets.

 

Other Income Statement Items

 

 

 

Years Ended December 31,

 

 

 

2007

 

2006

 

2005

 

 

 

(Thousands)

 

Gain on sale of assets, net

 

$

126,088

 

$

 

$

 

Gain on sale of available-for-sale securities, net

 

1,042

 

 

110,280

 

Other income

 

7,645

 

1,442

 

1,539

 

Income from discontinued operations

 

 

4,261

 

1,481

 

 

During 2007, the Equitable Supply segment sold to Pine Mountain Oil and Gas, Inc. (PMOG) a portion of the Company’s interests in certain gas properties in the Nora area totaling approximately 74 Bcf of proved reserves. Also during 2007, the Equitable Supply segment contributed certain Nora area gathering facilities and pipelines to Nora Gathering, LLC in exchange for a 50% equity interest in Nora Gathering, LLC and cash. These transactions resulted in a net gain of $126.1 million. See Note 4 to the Company’s Consolidated Financial Statements for further discussion of these transactions.

 

As discussed in Note 9 to the Company’s Consolidated Financial Statements, in 2007 the Company reviewed its investment portfolio (including its investment allocation) and sold equity funds with a cost basis of $6.3 million for total proceeds of $7.3 million, resulting in the Company recognizing a gain of $1.0 million.  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.

 

In 2007 and 2006, other income primarily relates to the equity portion of AFUDC.  Prior to 2007, the amount of AFUDC — Equity was not significant and was included as an offset to interest expense in the Statements of Consolidated Income.  As a result of the significance of the carrying costs related to the Big Sandy Pipeline and other regulated projects, AFUDC — Equity has been reclassified to other income in the Statements of Consolidated Income for all periods presented.  Other income in 2005 includes pre-tax dividend income of $1.2 million relating to the Kerr-McGee shares held by the Company in that year.

 

34



 

The Company’s NORESCO business is classified as discontinued operations due to the sale of the NORESCO domestic business in 2005 and sale of the Company’s remaining international investment in early 2006.  Income from discontinued operations for 2006 included a tax benefit of $3.2 million due to a reduced tax liability on the sale of the domestic business and after-tax income of $1.1 million resulting from the Company’s reassessment of its remaining obligations for costs incurred related to the sale of the domestic business. Income from discontinued operations for 2005 included the reversal of approximately $7.8 million of reserves (after tax) established in 2004, due to improved business conditions in the related international markets, as well as a $6.4 million tax benefit from the reorganization of the Company’s international assets in 2005.  These 2005 income items 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 of the domestic NORESCO business.

 

Interest Expense

 

 

 

2007

 

2006

 

2005

 

 

 

 

 

 

 

 

 

Interest expense

 

$

47,669

 

$

48,494

 

$

44,781

 

 

Interest expense decreased by $0.8 million from 2006 to 2007 primarily as a result of the repayment of long-term debt.  A 1.2% increase in the average annual short-term interest rate was more than offset by an overall reduction in weighted average net short-term debt outstanding, in part due to the proceeds from the sale of properties during the year.

 

Interest expense increased by $3.7 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.

 

Average annual interest rates on the Company’s short-term debt were 5.8%, 4.6% and 3.5% for 2007, 2006 and 2005, respectively.

 

Capital Resources and Liquidity

 

Operating Activities

 

Cash flows provided by operating activities totaled $426.7 million for 2007 as compared to $617.8 million for 2006, a net decrease of $191.1 million in cash flows provided by operating activities between years.  The decrease in cash flows provided by operating activities was attributable to the following:

 

·                  a $5.9 million increase in cash required for margin deposits on the Company’s natural gas hedge agreements in 2007 compared to a $317.8 million decrease in cash required for margin deposits in 2006.  The decrease in 2006 was primarily due to significantly higher than normal gas prices in 2005 which resulted in increased deposit remittances in that year;

 

·                  a decrease in accounts receivable of $2.5 million in 2007 compared to a decrease in accounts receivable of $63.5 million in 2006.  The decrease in 2006 was primarily due to decreased natural gas prices during 2006 as compared to significant increases in prices in 2005;

 

partially offset by:

 

·                  an increase in other current liabilities of $99.4 million in 2007 compared to a decrease of $31.9 million in 2006, primarily related to long-term incentive compensation plans and the timing of payments;

 

·                  an increase in accounts payable of $65.9 million in 2007 compared to a decrease of $29.3 million in 2006.  The increase in accounts payable in 2007 was primarily the result of increased capital spending, while the decrease in 2006 was primarily due to decreased natural gas prices during 2006.

 

35



 

Cash flows provided by operating activities totaled $617.8 million for 2006 as compared to $312.3 million of cash flows used in operating activities for 2005, a net increase of $930.1 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 Company’s 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 Company’s 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 higher natural gas prices on volumes stored in 2005 compared to 2006;

 

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 $31.9 million 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.

 

Investing Activities

 

Cash flows used in investing activities totaled $590.1 million for 2007 as compared to $406.3 million for 2006, a net increase of $183.8 million in cash flows used in investing activities between years.  The increase in cash flows used in investing activities was attributable to the following:

 

·                  an increase in capital expenditures to $776.7 million in 2007 from $403.1 million in 2006.  See discussion of capital expenditures below;

 

·                  an increase of $28.1 million in 2007 from the Company’s purchase of an additional working interest of approximately 13.5% in the Roaring Fork area in Virginia;

 

partially offset by:

 

·                  proceeds received in the second quarter of 2007 from the sale and contribution of assets.  See Note 4 to the Company’s Consolidated Financial Statements.

 

Cash flows used in investing activities totaled $406.3 million for 2006 as compared to $348.1 million of cash flows provided by investing activities for 2005, a net increase of $754.4 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;

 

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·                  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 $403.1 million in 2006 from $275.5 million in 2005.  See discussion of capital expenditures below;

 

·                  proceeds of $80.0 million from the sale of the domestic operations of the Company’s NORESCO business segment in 2005;

 

partially offset by:

 

·                  the Company’s acquisition of the 99% limited partnership interest in ESP for $57.5 million in 2005.

 

Capital Commitments and Expenditures

 

The Company forecasts approximately $1.2 billion of capital commitments for 2008.  This forecast includes $536 million for well development, $568 million for midstream infrastructure at Equitable Supply, $80 million for midstream projects at Equitable Utilities and $37 million for distribution infrastructure projects.  Over 50% of the capital commitments in 2008 are for drilling and infrastructure in Kentucky.  A portion of these capital commitments is not expected to impact cash flow until 2009 and beyond.

 

Capital Expenditures

 

 

 

2008 Forecast

 

2007 Actual

 

2006 Actual

 

2005 Actual

 

Well development (primarily drilling)

 

$

619 million

 

$

298 million

 

$

200 million

 

$

131 million

 

Equitable Supply infrastructure

 

$

490 million

 

$

390 million

 

$

136 million

 

$

75 million

 

Equitable Utilities

 

$

107 million

 

$

88 million

 

$

64 million

 

$

61 million

 

Acquisitions and other

 

$

5 million

 

$

29 million

**

$

3 million

 

$

66 million

***

Total

 

$

1,221 million

*

$

805 million

 

$

403 million

 

$

333 million

 

 


* The forecasted 2008 capital expenditures include 2007 capital commitments totaling $422 million, including $234 million for Equitable Supply infrastructure, $155 million for well development, and $33 million for Equitable Utilities.

 

** Includes $28.1 million related to the Company’s purchase of an additional working interest of approximately 13.5% in the Roaring Fork area in Virginia and certain gathering assets from a minority interest holder.  See Note 5 to the Company’s Consolidated Financial Statements.

 

*** Includes $57.5 million for the acquisition of the 99% limited partnership interest in Eastern Seven Partners, L.P.  See Note 5 to the Company’s Consolidated Financial Statements.

 

Capital expenditures for well development and Equitable Supply infrastructure increased in 2007 as compared to 2006 primarily due to an increased drilling and development program in 2007, capital expended for construction of the Big Sandy Pipeline, upgrades to the Langley plant and other throughput optimization projects.  Capital expenditures for well development and Equitable Supply infrastructure increased in 2006 as compared to 2005 primarily due to an increased drilling and development program in 2006, capital expended for construction of the Big Sandy Pipeline and other throughput optimization projects.

 

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Capital expenditures for Equitable Utilities increased in 2007 as compared to 2006 primarily due to increased transmission pipeline replacement associated with pipeline integrity under The Pipeline Safety Improvement Act of 2002 and increased gathering infrastructure expenditures.  These same projects caused capital expenditures for Equitable Utilities to increase in 2006 as compared to 2005.

 

The Company’s forecasted 2008 capital expenditures represent a significant increase over capital expenditures in 2007.  The $619 million targeted for well development in 2008 represents a $321 million increase over 2007 which is driven by expected increased drilling activity of up to 750 wells in 2008 compared to 634 wells in 2007.  The ultimate number of wells drilled will depend on the mix of horizontal shale wells, vertical conventional wells in sandstone and shale, and coal bed methane wells.  The Company plans to drill between 250 and 300 horizontal wells in 2008, with the intent to drill more if efficiency improvements experienced in 2007 continue.  The $490 million forecast for 2008 Equitable Supply infrastructure includes incremental Appalachian midstream infrastructure to move new gas volumes to market, including approximately 60,000 horsepower of compression and approximately 400 miles of gathering lines.  The $107 million forecasted for Equitable Utilities includes $70 million for midstream projects and $37 million for distribution infrastructure projects.  The midstream projects include amounts for gathering growth and infrastructure improvements.  The distribution infrastructure projects primarily include transmission pipeline replacement.

 

The Company expects to finance its capital expenditures with cash generated from operations, short-term debt and capital market transactions completed during 2008.  See discussion in the “Financing Activities” section below regarding the financing capacity of the Company.

 

For federal income tax purposes the Company typically deducts as intangible drilling costs (IDC) approximately 70% of its vertical drilling costs and 75% of its horizontal drilling costs in the year incurred.  The Company expects that the IDC deduction resulting from its increased drilling program coupled with accelerated tax depreciation for expansion of the gathering infrastructure will most likely put the Company into an overall federal tax net operating loss position in 2008 which is likely to continue as long as expansion in Appalachia continues.  The result of this change is that the Company expects minimal cash taxes for the foreseeable future.

 

Financing Activities

 

Cash flows provided by financing activities totaled $245.1 million for 2007 as compared to $286.5 million of cash flows used in financing activities for 2006, a net increase of $531.6 million in cash flows provided by financing activities between years.  The increase in cash flows provided by financing activities was attributable largely to the following:

 

·                  a $314.0 million increase in amounts borrowed under short-term loans in 2007 compared to a $229.3 million decrease in short-term borrowings in 2006.  The increase in short-term borrowings in 2007 was for the purposes of funding capital expenditures and working capital requirements;

 

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:

 

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·                  no repurchases of shares of the Company’s outstanding common stock under the Company’s share repurchase program during 2006 in anticipation of the now terminated agreement to acquire Peoples and Hope, compared to repurchases of $122.3 million of common stock in 2005.

 

The Company is committed to maintaining a cost effective capital structure and intends to finance future cash requirements, including the portion of the 2008 capital expenditure forecast not financed by cash flows from operations, using capital market transactions

 

Short-term Borrowings

 

Cash required for operations is affected primarily by the seasonal nature of the Company’s natural gas distribution operations and the volatility of oil and natural gas commodity prices.  The Company’s $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 Company’s commercial paper program.  Historically, short-term borrowings have been used mainly to support working capital and capital expenditure requirements during the summer months and were generally repaid as natural gas was sold during the heating season.

 

Due to the volatility in the short-term debt markets during the second half of 2007, the Company determined that its lowest cost of short term borrowings would be obtained by borrowing directly under its $1.5 billion revolving credit facility.  The Company will continue to evaluate whether the commercial paper markets or direct loans under the revolving credit facility offer the lowest cost of short-term debt capital, and will obtain short-term funding to meet its liquidity needs from either source as needed.  As of December 31, 2007, the Company had outstanding short-term loans under the revolving credit facility of $450.0 million and no commercial paper balances.  Interest rates on short-term borrowings averaged 5.8% during 2007.

 

The Company’s short-term borrowings generally have original maturities of three months or less.

 

Security Ratings