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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, 2008

 

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

 

EQT CORPORATION

(Exact name of registrant as specified in its charter)

 

PENNSYLVANIA

25-0464690

(State or other jurisdiction of incorporation or organization)

(IRS Employer Identification No.)

 

 

225 North Shore Drive

 

Pittsburgh, Pennsylvania

15212

(Address of principal executive offices)

(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.   o

 

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, 2008:  $8,892,460,969

 

The number of shares of common stock outstanding
as of January 31, 2009:  130,860,463

 

DOCUMENTS INCORPORATED BY REFERENCE

 

The Company’s definitive proxy statement relating to the annual meeting of shareowners (to be held April 22, 2009) will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2008 and is incorporated by reference in Part III to the extent described therein.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

 

Glossary of Commonly Used Terms, Abbreviations and Measurements

3

 

 

 

 
PART I
 
 
 
 

Item 1

Business

7

Item 1A

Risk Factors

16

Item 1B

Unresolved Staff Comments

19

Item 2

Properties

19

Item 3

Legal Proceedings

22

Item 4

Submission of Matters to a Vote of Security Holders

22

 

Executive Officers of the Registrant

22

 

 

 

 
PART II
 
 
 
 

Item 5

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

24

Item 6

Selected Financial Data

26

Item 7

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

27

Item 7A

Quantitative and Qualitative Disclosures About Market Risk

52

Item 8

Financial Statements and Supplementary Data

55

Item 9

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

104

Item 9A

Controls and Procedures

104

Item 9B

Other Information

104

 

 

 

 

PART III

 

 

 

 

Item 10

Directors, Executive Officers and Corporate Governance

105

Item 11

Executive Compensation

105

Item 12

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

106

Item 13

Certain Relationships and Related Transactions and Director Independence

106

Item 14

Principal Accounting Fees and Services

106

 

 

 

 

PART IV

 

 

 

 

Item 15

Exhibits, Financial Statement Schedules

107

 

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

107

 

Index to Exhibits

109

 

Signatures

116

 

Certifications

 

 

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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.

 

British thermal unit — a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

 

CAP — 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.  The cost of the CAP is spread across non-CAP customers.

 

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.

 

daily sales volume — An operational estimate of the daily gas sales volume on a typical day (excluding curtailments).

 

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 a gathering pipeline.

 

frac spread — The price difference between equivalent energy content of natural gas and natural gas liquids.

 

futures contract An exchange-traded 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.

 

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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.

 

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 deposits when forward prices move adversely to a derivative holder’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.

 

NGL or Natural Gas Liquids, those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption, or other methods in gas processing plants.  Natural gas liquids include primarily propane, butane, ethane and isobutane.

 

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.

 

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working gas — The volume of natural gas in the storage reservoir that can be extracted during the normal operation of the storage facility.

 

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”

Dominion Dominion Resources, Inc.  When used in the context of a discussion relating to the 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

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

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. 132R-1 — Statement of Financial Accounting Standards No. 132 (revised 2003), “Employer’s Disclosures about Pensions and Other Postretirement Benefits”

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

 

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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)”

WV PSC — Public Service Commission of West Virginia

 

Measurements

Bbl    = barrel

Btu = one British thermal unit

BBtu  = billion British thermal units

Bcf    = billion cubic feet

Bcfe   = billion cubic feet of natural gas equivalents

Dth  =  million British thermal units

Mcf    = thousand cubic feet

Mcfe   = thousand cubic feet of natural gas equivalents

Mgal   = thousand gallons

MMBtu  = million British thermal units

MMcf   = million cubic feet

MMcfe  = million cubic feet of natural gas equivalents

 

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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,” “will,” “may” 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 and the rate case settlement.  These statements involve risks and uncertainties that could cause actual results to differ materially from projected results.  Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results.  The Company has based these forward-looking statements on current expectations and assumptions about future events.  While the company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control.  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 applies 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

 

EQT Corporation, formerly Equitable Resources, Inc., (EQT or the Company) is one of Appalachia’s largest exploration and production companies with over three trillion cubic feet of proved reserves at December 31, 2008.  The Company and its subsidiaries offer energy products (natural gas, NGLs and a limited amount of crude oil) and services to wholesale and retail customers in the United States.  The Company conducts its business through three business segments: EQT Production, EQT Midstream and Equitable Distribution.

 

The Company’s proved reserves grew 16% from 2007 to 3,110 Bcfe at December 31, 2008.  Over the past five years the Company’s proved reserves have grown 47% as a result of the Company’s drilling program and investment in drilling technology.

 

Proved Natural Gas and Oil
Reserves(MMcfe)

 

2008

 

2007

 

2006

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved Developed

 

1,894,516

 

1,758,641

 

1,725,585

 

1,673,038

 

1,631,409

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved Undeveloped

 

1,215,492

 

923,770

 

771,770

 

692,210

 

477,244

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Proved Reserves

 

3,110,008

 

2,682,411

 

2,497,355

 

2,365,248

 

2,108,653

 

 

The Company’s reserves are located entirely in the Appalachian Basin, a production area characterized by wells with long lives, low production costs, natural gas containing high energy content and close proximity to

 

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natural gas markets.  Many of the Company’s wells have been producing for decades, in some cases since the early 1900s.

 

The Company’s proved reserves have discounted future net cash flows before income taxes of $3,245 million ($2,012 million after tax) at December 31, 2008.  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 (unaudited) to the Company’s Consolidated Financial Statements for information regarding reserves, reserve activity, costs and the standard measure of discounted future cash flows.

 

While the natural gas exploration and production industry can be volatile as market prices fluctuate, management believes that the following factors position the Company to achieve solid relative returns for shareholders over time:

 

·

Over 3.3 million acres, much of which is held in fee or held by production;

·

3,110 Bcfe of proved reserves at December 31, 2008 making EQT one of the largest owners of reserves in the Appalachian Basin;

·

The Company’s Appalachian reserves are geographically situated between the high use natural gas markets in the Northeast and Midwestern United States;

·

EQT’s low cost structure, which makes the Company’s drilling efforts resilient to lower natural gas prices;

·

Extensive midstream infrastructure to deliver gas to markets, including over 10,000 miles of pipeline;

·

Innovation is encouraged as evidenced by the Company’s success in applying air to horizontal drilling techniques;

·

Best-in-state customer service at Equitable Distribution; and

·

58 year history of paying dividends to shareholders.

 

Production:  EQT’s strategy is to maximize value by profitably developing the Company’s extensive acreage position enabled by a low cost structure.  The Company is focused on continuing its significant organic reserve and production growth through its drilling program and believes that it is a technological leader in drilling in low pressure shale.  In particular, the use of air in horizontal drilling has proven to be a cost effective technology which the Company has efficiently deployed to various geological formations in the Appalachian mountain terrain and may be deployed to other Company assets in the Basin to maximize production.

 

In addition to horizontal air drilling, an activity in which the Company believes it is a technological leader, the Company’s drilling innovations include drilling re-entry wells where low pressured vertical shale wells were previously drilled, drilling multilateral and stacked multilateral horizontal wells and refracing existing vertical wells.

 

EQT Production’s drilling has been concentrated within the core areas of southwestern Virginia, southeastern Kentucky, West Virginia and Pennsylvania and in four major plays: Huron, coalbed methane, Berea and Marcellus.  In each of its plays, the Company drills low risk development wells into reservoirs that are known to be productive.

 

The Company has recently focused drilling in the Huron play, which includes the Lower Huron, Cleveland and Rhinestreet formations, and on the coalbed methane play.  EQT has approximately 2.2 million acres in the Huron play.  In 2008, the Company ramped up its development programs for the emerging Berea sandstone and Marcellus plays.  The Company has approximately 800,000 acres in the Berea play where it expects to drill 40 wells in 2009 and over 400,000 acres in the Marcellus play where it expects to drill 45 wells, including 20 horizontal wells, in 2009.

 

The Company believes that it will continue to increase production volumes and proved reserves based on the quality of the underlying asset base.  Drilling activities resulted in proved developed reserve additions of approximately 293 Bcfe in 2008.  Of the proved developed reserve additions, approximately 49 Bcfe related to proved undeveloped reserves that were transferred to proved developed reserves.  The Company’s 2008 extensions, discoveries and other additions of 585 Bcfe was 646% of 2008 production of 90.6 Bcfe.

 

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For the year ended December 31,

 

Gross Wells Drilled

 

2008

 

2007

 

2006

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

 

 

Horizontal:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Marcellus

 

7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Berea

 

24

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Huron

 

357

 

88

 

5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coalbed Methane

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Horizontal

 

389

 

88

 

5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Vertical:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Vertical Commingled

 

103

 

280

 

413

 

294

 

209

 

 

 

 

 

 

 

 

 

 

 

 

 

Marcellus

 

16

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Coal Bed Methane

 

160

 

266

 

237

 

161

 

105

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Wells Drilled

 

668

 

634

 

655

 

455

 

314

 

 

 

 

 

 

 

 

 

 

 

 

 

Infill Wells Included Above

 

25

 

36

 

16

 

 

 

 

The Company spent approximately $701 million on well development (primarily drilling) in 2008.  Sales volumes increased 12% in 2008 (adjusted for the 2007 sale of interests which provided sales of 1,966 MMcfe during 2007).

 

Capital spending for well development (primarily drilling) in 2009 is expected to be approximately $600 million to support the drilling of up to 675 gross wells, including 375 gross horizontal wells.  Sales volumes are expected to reach 96-97 Bcfe in 2009.  A substantial portion of the Company’s 2009 drilling efforts will be focused on drilling horizontal wells in the Huron play where midstream pipeline and processing capacity are largely in place.  Current capital market conditions were considered when the 2009 capital program was developed.  The Company currently anticipates that the capital spending plan will not require the Company to access capital markets through the end of 2010.  Even so, the Company anticipates natural gas sales volume growth of 15% in 2009.  If the capital markets become unconstrained, the Company believes it has a long-term sales volume growth potential of greater than 20% per year.

 

 

 

For the year ended December 31,

 

(MMcfe)

 

2008

 

2007

 

2006

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas and oil production

 

90,585

 

83,114

 

81,371

 

78,755

 

72,760

 

 

 

 

 

 

 

 

 

 

 

 

 

Company usage, line loss

 

(6,577

)

(6,035

)

(5,215

)

(4,897

)

(5,090

)

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas inventory usage, net

 

 

 

 

51

 

61

 

 

 

 

 

 

 

 

 

 

 

 

 

Total sales volumes

 

84,008

 

77,079

 

76,156

 

73,909

 

67,731

 

 

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Midstream:  EQT Midstream provides gathering, processing, transmission and storage services to EQT Production and independent third parties.  In 2008, EQT Midstream focused on building a long-term growth platform, highlighted by the construction of the Big Sandy Pipeline, the Kentucky Hydrocarbon processing plant and the Mayking corridor.  This infrastructure development facilitates the development of EQT Production’s growing reserve base in the Huron play and provides opportunities to sell capacity to third parties.  In 2009, EQT Midstream will focus on continuing to expand its gathering system through well connections to existing midstream infrastructure and thereby filling existing capacity.  Additionally, initial infrastructure expansion in the Marcellus play in southwestern Pennsylvania and northern West Virginia is slated for 2009.

 

As of December 31, 2008, EQT Midstream’s gathering system included approximately 10,450 miles of gathering lines located in western Pennsylvania, West Virginia, eastern Kentucky and southwestern Virginia.  The Company also has a gas processing facility, Kentucky Hydrocarbon, located in Langley, Kentucky.  Transmission and storage operations include approximately 970 miles of lines located throughout eastern Kentucky, north central West Virginia and southwestern Pennsylvania.  The transmission and storage system interconnects with five major interstate pipelines: Texas Eastern Transmission, Columbia Gas Transmission, National Fuel Gas Supply, Tennessee Gas Pipeline and Dominion Transmission.  EQT Midstream also 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 geographically clustered, with eight in northern West Virginia and six in southwestern Pennsylvania.  In addition, EQT Midstream, through Equitrans, L.P. (Equitrans, the Company’s interstate pipeline affiliate) and Equitable Energy, LLC (Equitable Energy, the Company’s gas marketing affiliate) leased 6.3 Bcf of contractual storage and 138,500 Dth per day of contractual pipeline capacity from third parties as of December 31, 2008.

 

In 2008, Equitable Energy executed a binding precedent agreement with Tennessee Gas Pipeline Company (TGP), a wholly owned subsidiary of El Paso Corporation, for a 15-year term that awarded the Company 300,000 Dth per day of capacity in TGP’s 300-Line expansion project.  When completed, this expansion project will consist of approximately 128 miles of 30-inch pipe loop and approximately 52,000 horsepower of additional compression facilities to be constructed in TGP’s existing pipeline corridor in Pennsylvania and New Jersey.  The awarded capacity will provide EQT access to consumer markets from the Gulf Coast to the Mid-Atlantic and the Northeast and will also provide back-haul capacity of 300,000 Dth per day to the Gulf Coast.

 

Capital expenditures for Midstream infrastructure were $594 million in 2008.  During 2008, the Company turned in line the Mayking Corridor project (Mayking), which consists of three compressor units and 38 miles of pipe; completed an expansion of the Kentucky Hydrocarbon facility, which increased its gas processing capacity from 70 MMcfe per day to 170 MMcfe per day; and turned in line the Big Sandy Pipeline, which connects the Kentucky Hydrocarbon processing plant to the Tennessee Gas Pipeline in Carter County, Kentucky, and currently provides up to 130,000 Dth per day of firm transportation service.  The Big Sandy Pipeline capacity is expandable with additional compression.

 

Capital expenditures on Midstream infrastructure projects in 2009 will be reduced to $360 million as a result of the shift in focus from completing major infrastructure projects to expanding the gathering system in areas with existing midstream infrastructure.  This will facilitate moving a greater volume of EQT Production’s gas to market.  If the capital markets become less constrained, EQT Midstream will consider increasing investment in corridor infrastructure projects to provide additional capacity needed to facilitate production growth.

 

Distribution:  Equitable Distribution’s business strategy is to earn a competitive return on its asset base through regulatory mechanisms and operational efficiency.  Equitable Distribution is focused on enhancing the value of its existing assets by establishing a reputation for excellent customer service, effectively managing its capital spending, improving the efficiency of its workforce through superior work management and continuing to leverage technology throughout its operations.  In 2008, Equitable Gas filed a base rate case in Pennsylvania to recover an increased return on assets placed in service since the previous rate case and to fully recover costs associated with the customer assistance programs.  Equitable Distribution expects to spend approximately $30 million on capital expenditures in 2009.

 

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Equitable Gas Company (Equitable Gas, EQT’s regulated natural gas distribution subsidiary) distributes and sells natural gas to local residential, commercial and industrial customers in southwestern Pennsylvania, West Virginia and eastern Kentucky.  Equitable Gas also operates a small gathering system in Pennsylvania and provides off-system sales activities.  The off-system sales activities include the purchase and delivery of gas to customers at mutually agreed-upon points on facilities not owned by the Company.

 

Equitable Gas has made great strides over recent years towards achieving its operational goals.  For instance, Equitable Gas pioneered the use of monthly automated meter readings throughout its Pennsylvania service territory which has improved monthly billings and customer satisfaction.  The customer call center has demonstrated significantly improved operating performance in responding to customer inquiries and has added self-service functionality.  On-time scheduled appointment performance has increased to its highest levels in recent years.  In a recent survey by the American Gas Association, Equitable Gas’s damage prevention program scored in the top quartile of gas utility companies nationwide.

 

Markets and Customers

 

Natural Gas Sales:  EQT Production’s produced natural gas is sold to marketers (including Equitable Energy), utilities and industrial customers located mainly in the Appalachian area.  For the year ended December 31, 2008, sales to one marketer accounted for approximately 13% of revenues for EQT Production.  No customers accounted for more than 10% of revenues in 2007 or 2006.  Natural gas is a commodity and therefore the Company receives market-based pricing.  The market price for natural gas can be volatile as evidenced by the high natural gas prices in early through mid 2008 followed by dramatic decreases later in the year.  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 Company hedges a portion of its forecasted natural gas production.  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.

 

Natural gas drilling activity in the Appalachian Basin increased during 2007 and the first half of 2008 as suppliers attempted to take advantage of higher natural gas prices and reacted to reported successes in the Marcellus play.  This increased drilling activity placed constraints on the availability of labor, equipment, pipeline transport and other resources in the Appalachian Basin, but also attracted higher quality rigs and additional service providers to the region and provided opportunities for expansion of natural gas gathering activities.  Lower sales prices for natural gas in the latter part of 2008 reduced drilling activity in the Appalachian Basin but did not have a significant impact on the availability or cost of resources.  EQT Production has qualified numerous vendors and service providers for key resources and is not dependent upon any single vendor or service provider to meet production or sales goals.

 

The increase in Appalachian Basin production intensified pressure on the already stretched capacity of existing gathering and midstream processing and transport systems in the Appalachian Basin.  As a result, the Company entered into third party firm contractual capacity arrangements amounting to 188,318 Dth per day as of December 31, 2008 and discounted sales arrangements approximating 9,500 Dth per day as of December 31, 2008 to obtain transportation capacity so that its gas continues to flow to market.

 

Natural Gas Gathering:  EQT Midstream derives gathering revenues from charges to customers for use of its gathering system in the Appalachian Basin.  The gathering system volumes are transported to three major interstate pipelines: Columbia Gas Transmission, East Tennessee Natural Gas Company and Dominion Transmission.  The gathering system also maintains interconnects with Equitrans.  Maintaining these interconnects provides the Company with access to geographically diverse markets.

 

Gathering system transportation volumes for 2008 totaled 145,031 BBtu, of which approximately 53% related to gathering for EQT Production, 28% related to third party volumes and 10% related to volumes for other affiliates of the Company.  The remainder related to volumes in which interests were sold by the Company but which the Company continued to operate for a fee.  Revenues from affiliates accounted for approximately 80% of 2008 gathering revenues.

 

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Natural Gas Processing:  The Company processes natural gas in order to extract heavier liquid hydrocarbons (propane, iso-butane, normal butane and natural gasoline) from the natural gas stream, primarily from EQT Production’s produced gas.  On a per energy unit basis, these liquid hydrocarbons can typically be sold at a price premium versus natural gas; the value of this premium is referred to as the frac spread.  As a result of market conditions, the Company experienced reduced frac spreads in the second half of 2008.

 

NGLs are recovered at EQT’s Kentucky Hydrocarbon facility and transported to a fractionation plant owned by a third party for separation into commercial components.  The third party markets these components and in exchange retains an agreed-upon percentage of NGLs delivered by the Company.  The Company also has contractual processing arrangements whereby the Company sells gas to a third party processor at a weighted average liquids component price.

 

While natural gas processing produces independent revenues, the Company’s primary reason for these activities is to comply with the product quality specifications of the pipelines on which the Company’s produced natural gas is transported and sold.  As a result, the Company typically engages in gas processing at locations where its produced gas would not satisfy the downstream interstate pipeline’s gas quality specifications.  Without sufficient processing, the Company’s natural gas production could be interrupted as a result of an inability to achieve required interstate pipeline specifications.  Thus, as the Company’s production continues to grow, its gas processing capacity must also grow.

 

Natural Gas Transmission and Storage:  Services offered by Equitable Energy include commodity procurement, sales, delivery, risk management, and other services.  These operations are executed using Company owned and operated or contracted transmission and underground storage facilities as well as other contractual capacity arrangements with major pipeline and storage service providers in the eastern United States.  Equitable Energy uses leased storage capacity and firm transportation capacity, including the Company’s Big Sandy Pipeline capacity, to take advantage of price differentials and arbitrage opportunities.  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.  As a result of declining natural gas prices, Equitable Energy experienced reduced storage and commercial margins in the second half of 2008.

 

Customers of EQT Midstream’s gas transportation, storage, risk management and related services are 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.  Equitable Energy’s commodity procurement, sales, delivery, risk management, and other services are offered to natural gas producers and energy consumers including large industrial, utility, commercial and institutional end-users.

 

Equitrans’ firm transportation contracts on its mainline system expire between 2009 and 2017, 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 or used by affiliates such that the capacity will remain fully subscribed.  In 2008, approximately 78% of transportation volumes and approximately 83% of transportation revenues were from affiliates.

 

Natural Gas Distribution: Equitable Distribution provides natural gas distribution services to approximately 275,800 customers, consisting of 257,200 residential customers and 18,600 commercial and industrial customers in 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 service areas have a rather static population and economy.

 

Customer conservation as a result of product efficiency and increased natural gas prices has reduced residential customer usage over time despite the increasing availability of natural gas based products.  The Company has not experienced a significant decrease in weather adjusted throughput or deterioration in customer collections due to the recent economic downturn.  If this downturn persists, Equitable Distribution may experience a reduction in commercial and industrial throughput as well as an increase in bad debt expense, which would reduce the return on its asset base.

 

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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).  The gas purchase contracts contain various pricing mechanisms, ranging from fixed prices to several different index-related prices.

 

Because most of its customers use natural gas for heating purposes, Equitable Gas’ revenues are seasonal, with approximately 71% of calendar year 2008 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.

 

Competition

 

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 producers compete in the acquisition of properties, the search for and development of reserves, the production and sale of natural gas and the securing of labor and equipment required to conduct operations.  Competitors include major oil and gas companies, other independent oil and gas companies and individual producers and operators.  Key competitors for new gathering and processing systems include independent gas gatherers and integrated Appalachian energy companies.  Natural gas marketing activities compete with numerous other companies offering the same services.  Some of these competitors are affiliates of companies with extensive pipeline systems that are used for transportation from producers to end-users.  The Company’s distribution operations face competition from other local distribution companies, alternative fuels and reduced usage among customers as a result of conservation.

 

Regulation

 

EQT Production’s natural gas operations are subject to various federal, state, and local laws and regulations, including regulations related to the location of wells; drilling, stimulating and casing of wells; water withdrawal and disbursement for well stimulation purposes; well production; spill prevention plans; the use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations; surface usage and the reclamation of properties upon which wells or other facilities have been located; the calculation and disbursement of royalty payments and taxes; the plugging and abandoning of wells; and the gathering of production in certain circumstances.

 

EQT Production’s operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or field rule units; the number of wells that may be drilled in a unit; and the unitization or pooling of natural gas properties.  EQT Production’s operating states allow in certain circumstances the forced pooling or integration of tracts to facilitate exploration, while in other circumstances it is necessary to rely on voluntary pooling of lands and leases which may make it more difficult to develop natural gas properties.  In addition, state conservation laws generally limit the venting or flaring of natural gas.  The effect of these regulations is to limit the amounts of natural gas we produce from our wells and to limit the number of wells or the locations at which we drill.

 

EQT Midstream has both regulated and non-regulated operations.  The regulated activities consist of federally-regulated transmission and storage operations and certain state-regulated gathering operations.  The non-regulated activities include certain gathering and transportation operations, processing of NGLs and risk management activities.  Equitrans’ rates and operations are subject to regulation by the FERC.  The 2006 FERC rate case settlement allows Equitrans, among other things, 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.  The Company has continued to utilize the surcharge mechanism each year to recover costs incurred in connection with its Pipeline Safety Program.  Under the terms of the 2006 settlement, Equitrans may not seek new base transmission and storage rates prior to June 1, 2009 or new gathering base rates prior to November 1, 2010.  In 2008, the Big Sandy Pipeline was placed in service in eastern Kentucky.  Big Sandy’s initial rate agreements provide for a firm reservation charge of $19.77 per maximum daily quantity for a term of ten years.

 

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Equitable Gas’ distribution rates, terms of service and contracts with affiliates are subject to comprehensive regulation by the PA PUC and the WV PSC.  In addition, the issuance of securities by Equitable Gas is subject to regulation by the PA PUC.  The field line sales rates in Kentucky are subject to rate regulation by the Kentucky Public Service Commission.

 

Equitable Gas must usually seek the approval of one or more of its regulators prior to changing its rates.  Currently, Equitable Gas passes through to its regulated customers the cost of its purchased gas and transportation activities.  Equitable Gas is allowed to recover a return in addition to the costs of its transportation activities.  However, Equitable Gas’ regulators do not guarantee recovery and may require that certain costs of operation be recovered over an extended term.  Equitable Gas filed a base rate case in the second quarter of 2008 and reached a settlement in principal with the active parties to the proceeding in November 2008.  The settlement must be approved by the PA PUC to be effective.  On January 20, 2009, a PA PUC Administrative Law Judge recommended that the PA PUC approve of the rate case settlement.  The PA PUC is expected to act before March 31, 2009.

 

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.  On September 27, 2007, the PA PUC issued an order approving an increase to Equitable Gas’ CAP surcharge, which is designed to offset the higher costs of the CAP.  The revised surcharge went into effect on October 2, 2007.  If the rate case settlement is approved, Equitable Gas will increase the CAP surcharge from $0.58/mcf to $1.30/mcf and will receive an annual reconciliation of CAP costs to ensure complete recovery beginning in the first quarter of 2009.

 

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.

 

Employees

 

The Company and its subsidiaries had approximately 1,680 employees at the end of 2008.

 

Holding Company Reorganization

 

On June 30, 2008, the former Equitable Resources, Inc. (Old EQT) entered into and completed an Agreement and Plan of Merger (the Plan) under which Old EQT reorganized into a holding company structure such that a newly formed Pennsylvania corporation, also named Equitable Resources, Inc. (New EQT), became the publicly traded holding company of Old EQT and its subsidiaries.  The primary purpose of this reorganization (the Reorganization) was to separate Old EQT’s state-regulated distribution operations into a new subsidiary in order to better segregate its regulated and unregulated businesses and improve overall financing flexibility.  To effect the Reorganization, Old EQT formed New EQT, a wholly-owned subsidiary, and New EQT, in turn, formed EGC Merger Co., a Pennsylvania corporation owned solely by New EQT (MergerSub).  Under the Plan, MergerSub merged with and into Old EQT with Old EQT surviving (the Merger).  The Merger resulted in Old EQT becoming a direct, wholly-owned subsidiary of New EQT.  New EQT changed its name to EQT Corporation effective February 9, 2009.  Throughout this Annual Report, references to EQT, EQT Corporation and the Company refer collectively to New EQT and its consolidated subsidiaries.

 

Availability of Reports

 

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 the date 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.

 

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Discontinued Operations

 

The Company sold its NORESCO domestic business in 2005 and 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, in 2006. 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 2008, 2007 and 2006.

 

 

 

2008

 

2007

 

2006

 

EQT Production:

 

 

 

 

 

 

 

Natural gas equivalents sales

 

20

%

23

%

24

%

EQT Midstream:

 

 

 

 

 

 

 

Marketed natural gas sales

 

12

%

18

%

13

%

Equitable Distribution:

 

 

 

 

 

 

 

Residential natural gas sales

 

23

%

23

%

24

%

 

Financial Information About Segments

 

In January 2008, the Company announced a change in organizational structure 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 segment disclosures and discussions contained in this report have been reclassified to reflect all periods presented under the current organizational structure.

 

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.

 

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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, future rate of growth and liquidity.

 

Our revenue, profitability, future rate of growth and liquidity depend upon 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 and price controls.

 

Lower natural gas prices may result in decreases in the construction of new transportation capacity, decreased margin opportunities for our marketing and gathering services businesses and downward adjustments to the value of our estimated proved reserves which may cause us to incur non-cash charges to earnings. We are also exposed to the risk of non-performance by our hedge counterparties in the event that changes, positive or negative, in natural gas prices result in derivative contracts with a positive fair value. Finally, lower natural gas prices affect the amount of cash flow available for capital expenditures and our ability to borrow money and raise additional capital.

 

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 addition, to the extent we have hedged our current production at prices below the current market price, we are unable to benefit fully from an increase in the price of natural gas.

 

The global financial challenges may adversely affect our business and financial condition in ways that we currently cannot predict. Downgrades to our credit ratings could increase our costs of borrowing adversely affecting our business, results of operations and liquidity.

 

We rely upon access to both short-term bank and money markets and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by the cash flow from operations.  Continued challenges in the global financial system, including the capital markets, may adversely affect our business and our financial condition and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we desire, or need, to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. The economic situation could adversely affect the collectability of our trade receivables. Market conditions could cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection. The current economic situation could lead to reduced demand for natural gas which could have a negative impact on our revenues and our credit ratings.

 

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Any downgrade of our credit ratings 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 adversely affect our business, results of operations and liquidity. 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 ratings could result in an increase in our borrowing costs, which would diminish financial results.

 

Our need to comply with comprehensive, complex and sometimes unpredictable government regulations may increase our costs and limit our revenue growth, which may result in reduced earnings.

 

Significant portions of our gathering, transportation, storage and distribution businesses are subject to state and federal regulation including regulation of the rates which we may assess our customers. The agencies that regulate our rates may prohibit us from realizing a level of return which we believe is appropriate. These restrictions may take the form of imputed revenue credits, cost disallowances (including purchased gas cost recoveries) and/or expense deferrals. Additionally, we may be required to provide additional assistance to low income residential customers to help pay their bills 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. These laws and regulations currently include 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. New and modified laws and regulations could include regulations regarding carbon cap and trade, a carbon tax or other climate change matters and could cause the distribution business to expend capital not included in its budget to move and relocate lines in support of any federal stimulus package. Complying with existing and changing legal requirements could have a significant effect on our costs of operations and competitive position. The failure to comply with these requirements, even if as a result of factors beyond our control, 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 EQT Production, 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.

 

Strategic determinations regarding the allocation of capital and other resources in the current economic environment are challenging and our failure to appropriately allocate capital and resources among our businesses may adversely affect our financial condition and reduce our growth rate.

 

In developing our 2009 business plan, we considered allocating capital and other resources to various aspects of our businesses including well-development (primarily drilling), reserve acquisitions, exploratory activity, midstream infrastructure, distribution infrastructure, corporate items and other alternatives. We also considered our likely sources of capital. Notwithstanding the determinations made in the development of our 2009 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we don’t optimize our capital investment and capital raising opportunities and the use of our other resources, our financial condition and growth rate may be adversely affected.

 

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 upon our ability to develop additional gas reserves that are economically recoverable and to optimize 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 approximately 675 wells in 2009, including a target of 375 horizontal wells. Our drilling and subsequent maintenance of wells can involve significant

 

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risks, including those related to timing, cost overruns and operational efficiency, and these risks can be affected by the availability of capital, leases, rigs and a qualified work force, as well as weather conditions, gas price volatility, government approvals, title problems, geology and other factors. Drilling for natural gas can be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient revenues to return a profit. Additionally, a failure to effectively and efficiently 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 delivery of gas depends upon the availability of adequate transportation infrastructure. As previously announced, $360 million of our 2009 capital expenditures are planned for investment in midstream infrastructure. 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 and maintenance programs can involve significant risks, including those related to timing, cost overruns and operational efficiency, 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 adverse consequences to us.

 

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 injury and property damage or that such levels of insurance will be available in the future at economical prices.

 

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. Our decision to drill a prospect is subject to a number of factors which may alter our drilling schedule or our plans to drill at all. We may have difficulty drilling all of the wells before the lease term expires which could result in the loss of certain leasehold rights or we could drill wells in locations where we do not have the necessary infrastructure to deliver the gas to market. Successfully identifying production opportunities involves a high degree of business experience, knowledge and careful evaluation of potential opportunities, along with subjective judgments and assumptions which may prove to be incorrect. Our recent addition of exploration projects increases the risks inherent in our natural gas activities. Specifically, seismic data is subject to interpretation and may not accurately identify the presence of natural gas, which could adversely affect the results of our operations. Because we have a limited operating history in certain exploratory areas, our future operating results are difficult to forecast, and our failure to sustain high growth rates in the future could adversely affect the market price of our common stock.

 

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.

 

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Item 1B.            Unresolved Staff Comments
 
None.
 
Item 2.                     Properties

 

Principal facilities are owned by the Company’s business segments, or in the case of certain office locations and warehouse buildings, leased. A limited amount of equipment is also leased. The majority of the Company’s properties are located on or under (1) 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 or (2) public highways under franchises or permits from various governmental authorities. The Company’s facilities are generally well maintained and, where appropriate, are replaced or expanded to meet operating requirements.

 

EQT Production. EQT Production’s properties are located primarily in Kentucky, Pennsylvania, Virginia and West Virginia. This segment currently has approximately 3.4 million gross acres (approximately 68% of which are 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, 2008, the Company estimated its total proved reserves to be 3,110 Bcfe, consisting of proved developed producing reserves of 1,793 Bcfe, proved developed non-producing reserves of 102 Bcfe and proved undeveloped reserves of 1,215 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:

 

 

 

2008

 

2007

 

2006

 

Natural Gas:

 

 

 

 

 

 

 

MMcf produced

 

89,961

 

82,401

 

80,698

 

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

 

$

5.25

 

$

4.53

 

$

4.55

 

Crude Oil:

 

 

 

 

 

 

 

Thousands of Bbls produced

 

104

 

119

 

112

 

Average sales price per Bbl

 

$

74.45

 

$

62.06

 

$

58.35

 

NGLs:

 

 

 

 

 

 

 

Mgal sold

 

81,856

 

72,430

 

70,963

 

Average sales price per Mgal

 

$

1.24

 

$

1.07

 

$

0.95

 

 

Average per unit production cost, including severance taxes, of natural gas and crude oil during 2008, 2007 and 2006 was $0.871, $0.740 and $0.762 per Mcfe, respectively.

 

 

 

Natural Gas

 

Oil

 

Total productive wells at December 31, 2008:

 

 

 

 

 

Total gross productive wells

 

13,173

 

22

 

Total net productive wells

 

9,485

 

19

 

Total in-process wells at December 31, 2008:

 

 

 

 

 

Total gross in-process wells

 

141

 

 

Total net in-process wells

 

120

 

 

 

Total acreage at December 31, 2008:

 

 

 

Total gross productive acres

 

1,063,640

 

Total net productive acres

 

925,176

 

Total gross undeveloped acres

 

2,307,137

 

Total net undeveloped acres

 

2,006,909

 

 

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As of December 31, 2008, leases associated with 15,105 gross undeveloped acres expire in 2009 if they are not renewed; however, the Company has an active lease renewal program.

 

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

 

 

 

2008

 

2007

 

2006

 

Exploratory wells:

 

 

 

 

 

 

 

Productive

 

1.0

 

 

 

Dry

 

 

 

 

Development wells:

 

 

 

 

 

 

 

Productive

 

531.2

 

455.8

 

455.0

 

Dry

 

1.0

 

0.5

 

1.0

 

 

Selected data by state (at December 31, 2008 unless otherwise noted):

 

 

 

Kentucky

 

West
Virginia

 

Virginia

 

Pennsylvania

 

Ohio

 

Total

 

Natural gas and oil production (MMcfe) — 2008

 

42,798

 

23,054

 

23,192

 

1,541

 

 

90,585

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net revenue interest (%)

 

86.9

%

67.2

%

51.7

%

86.3

%

 

69.8

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total gross productive wells (a)

 

5,104

 

4,652

 

2,787

 

652

 

 

 

13,195

 

Total net productive wells

 

4,257

 

2,885

 

1,710

 

652

 

 

 

9,504

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total gross acreage

 

1,444,619

 

1,210,318

 

538,839

 

174,597

 

2,404

 

3,370,777

 

Total net acreage

 

1,379,149

 

1,030,285

 

348,206

 

172,041

 

2,404

 

2,932,085

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed producing reserves (Bcfe)

 

933

 

514

 

320

 

26

 

 

1,793

 

Proved developed non-producing reserves (Bcfe)

 

45

 

47

 

10

 

 

 

102

 

Proved undeveloped reserves (Bcfe)

 

628

 

457

 

122

 

8

 

 

1,215

 

Proved developed and undeveloped reserves (Bcfe)

 

1,606

 

1,018

 

452

 

34

 

 

3,110

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross proved undeveloped drilling locations

 

1,449

 

1,494

 

667

 

4

 

 

3,614

 

Net proved undeveloped drilling locations

 

1,421

 

1,494

 

437

 

4

 

 

3,356

 

 


(a)          At December 31, 2008, the Company had approximately 179 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 100 acres. Wells located in West Virginia are primarily in tight sands and shale formations

 

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Table of Contents

 

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. Horizontal wells in both northern and southern West Virginia are drilled on 100 acre spacing. Wells located in Virginia are primarily in coalbed methane formations with depths ranging from 2,000 feet to 3,000 feet and average spacing of 60 acres and in tight sands and shale formations at depths of 3,000 to 6,500 feet on 100 acre spacing. Wells located in Pennsylvania are primarily in shale formations with depths ranging from 7,000 feet to 8,000 feet and average spacing of 100 acres.

 

During 2008, the Company drilled its first exploratory vertical Utica well. As of December 31, 2008 the company has $6.9 million invested in this well, which has not been turned in line. The Company expects to drill a second Utica well in 2010 and will complete the two wells at the same time to gain cost efficiencies.

 

EQT Production owns and leases office space in Pennsylvania, West Virginia, Virginia and Kentucky.

 

EQT Midstream. EQT Midstream owns or operates approximately 10,450 miles of gathering line and 253 compressor units comprising 132 compressor stations with approximately 230,000 horsepower of installed capacity, as well as other general property and equipment.

 

Substantially all of the gathering operations’ sales volumes are delivered to several large interstate pipelines on which the Company leases capacity. These pipelines are subject to periodic curtailments for maintenance and repairs.

 

 

 

Kentucky

 

West
Virginia

 

Virginia

 

Pennsylvania

 

Total

 

Approximate miles of gathering line

 

3,700

 

4,800

 

1,650

 

300

 

10,450

 

 

The Midstream business also owns a hydrocarbon processing plant and gas compression facilities located in Langley, Kentucky.

 

EQT Midstream also owns and operates regulated underground storage and transmission facilities in Pennsylvania, West Virginia and Kentucky. These operations consist of approximately 970 miles of regulated transmission and storage lines with 36,000 horsepower of installed capacity and interconnections with five major interstate pipelines. The interstate pipeline system stretches throughout north central West Virginia and southwestern Pennsylvania. The completion of the Big Sandy Pipeline in 2008 added 68 miles of transmission line and 9,000 horsepower 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 geographically clustered, with eight in northern West Virginia and six in southwestern Pennsylvania.

 

EQT Midstream owns and leases office space in Pennsylvania, West Virginia, Virginia and Kentucky.

 

Equitable Distribution. This segment owns and operates natural gas distribution facilities as well as other general property and equipment in western Pennsylvania, West Virginia and Kentucky. The distribution operations consist of approximately 4,000 miles of pipe in Pennsylvania, West Virginia and Kentucky.

 

Headquarters. The corporate headquarters and other operations are located in leased office space in Pittsburgh, Pennsylvania. In 2008, the Company entered into an agreement with Liberty Avenue Holdings, LLC to lease office space in Pittsburgh, Pennsylvania for the Company’s new corporate headquarters which are expected to be completed in 2009.

 

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Table of Contents

 

Item 3.                     Legal Proceedings

 

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

 

Several West Virginia lessors claimed in a suit filed on July 31, 2006 that Equitable Production Company had underpaid royalties on gas produced and marketed from leases. The suit sought compensatory and punitive damages, an accounting, and other relief. The plaintiffs later amended their complaint to name Equitable Resources, Inc. as an additional defendant. While the Company believes that it paid the proper royalty, it established a reserve to cover any potential liability. The Company has settled the litigation. The settlement covers all of the Company’s lessors in West Virginia and is subject to court approval. The Company believes the reserve established for royalty matters is sufficient.

 

In addition to the claim 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, 2008.

 

Executive Officers of the Registrant (as of February 20, 2009)

 

Name and Age

 

Current Title (Year Initially Elected an
Executive Officer)

 

Business Experience

 

 

 

 

 

Theresa Z. Bone (45)

 

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 (49)

 

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 (46)

 

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 (44)

 

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.

 

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Table of Contents

 

Lewis B. Gardner (51)

 

Vice President and General Counsel (2008)

 

Elected to present position April 2008; Managing Director External Affairs and Labor Relations from January 2008 to March 2008; Senior Counsel - Director Employee and Labor Relations from March 2004 to December 2007;  Director Employee and Labor Relations from March 2003 to February 2004.

 

 

 

 

 

Murry S. Gerber (55)

 

Chairman and Chief Executive Officer (1998)

 

Elected to present position February 2007; Chairman, President and Chief Executive Officer from May 2000 to February 2007.

 

 

 

 

 

M. Elise Hyland (49)

 

Vice President and President, Equitable Gas (2008)

 

Elected to present position February 2008; President Equitable Gas from July 2007 to January 2008; 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.

 

 

 

 

 

Charlene Petrelli (48)

 

Vice President and Chief Human Resources Officer (2003)

 

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

 

 

 

 

 

David L. Porges (51)

 

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 (43)

 

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.

 

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.

 

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Table of Contents

 

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):

 

 

 

2008

 

2007

 

 

 

High

 

Low

 

Dividend

 

High

 

Low

 

Dividend

 

1st Quarter

 

$

65.05

 

$

47.16

 

$

0.22

 

$

50.50

 

$

39.26

 

$

0.22

 

2nd Quarter

 

76.14

 

58.94

 

0.22

 

53.70

 

47.96

 

0.22

 

3rd Quarter

 

71.33

 

33.62

 

0.22

 

54.42

 

44.57

 

0.22

 

4th Quarter

 

36.70

 

20.71

 

0.22

 

56.75

 

51.54

 

0.22

 

 

As of February 13, 2009, there were 3,660 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 certain business conditions, such as the Company’s lines of business, results of operations and financial condition and other factors. Based on currently foreseeable 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, 2008:

 

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 2008 (October 1 — October 31)

 

4,317

 

$

29.82

 

 

8,385,400

 

 

 

 

 

 

 

 

 

 

 

November 2008 (November 1 — November 30)

 

3,120

 

$

30.10

 

 

8,385,400

 

 

 

 

 

 

 

 

 

 

 

December 2008 (December 1 — December 31)

 

23,837

 

$

31.80

 

 

8,385,400

 

 

 

 

 

 

 

 

 

 

 

Total

 

31,274

 

 

 

 

 

 

 


(a)          Comprised solely of Company-directed purchases made by the Company’s 401(k) plans.

 

(b)         EQT’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.

 

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Table of Contents

 

Stock Performance Graph

 

The following graph compares the most recent five-year cumulative total return attained by shareholders on EQT Corporation’s common stock with the cumulative total returns of the S&P 500 index, and two customized peer groups of eleven companies (the “Old Self-Constructed Peer Group) and twenty companies (the “New Self-Constructed Peer Group”), respectively, whose individual companies are listed respectively in footnotes (1) and (2) below. An investment of $100 (with reinvestment of all dividends) is assumed to have been made at the close of business on December 31, 2003 in the Company’s common stock, in the S&P 500 index, and in each peer group. Relative performance is tracked through December 31, 2008.

 

 

 

 

12/03

 

12/04

 

12/05

 

12/06

 

12/07

 

12/08

 

EQT CORPORATION

 

100.00

 

145.53

 

180.55

 

210.36

 

273.17

 

175.15

 

S & P 500

 

100.00

 

110.88

 

116.33

 

134.70

 

142.10

 

89.53

 

OLD SELF-CONSTRUCTED PEER GROUP (1)

 

100.00

 

139.57

 

170.65

 

207.10

 

152.46

 

108.28

 

NEW SELF-CONSTRUCTED PEER GROUP(2)

 

100.00

 

125.03

 

169.46

 

196.89

 

230.81

 

160.26

 

 


(1)          The Company’s old self-constructed peer group includes eleven companies, which are: 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. 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, 2003 through December 31, 2006, at which time they are removed from the peer group calculation.

(2)          The Company’s new self-constructed peer group includes twenty companies, which are: Atlas Energy Resources, LLC, Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, CNX Gas Corporation, El Paso Corporation, Enbridge Inc, Energen Corporation, MarkWest Energy Partners, L.P., MDU Resources Group, Inc., National Fuel Gas Company, ONEOK, Inc, Penn Virginia Corporation, Questar Corporation, Range Resources Corporation, Sempra Energy, Southern Union

 

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Table of Contents

 

Company, Southwestern Energy Company, Spectra Energy Corp., TransCanada Corp. and The Williams Companies, Inc. In future years, the Company generally will use this new self-constructed peer group because the businesses operated by this self-constructed peer group more closely reflect the businesses engaged in by the Company as it has evolved from a diversified utility to an integrated energy company increasingly focused on natural gas exploration, production and transportation. In addition, this peer group is the same as the peer group for the Company’s 2008 Executive Performance Incentive Program.

 

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.

 

Item 6.                     Selected Financial Data

 

 

 

As of and for the year ended December 31,

 

 

 

2008

 

2007

 

2006

 

2005

 

2004(a)

 

 

 

(Thousands, except per share amounts)

 

Operating revenues

 

$

1,576,488

 

$

1,361,406

 

$

1,267,910

 

$

1,253,724

 

$

1,045,183

 

Income from continuing operations

 

$

255,604

 

$

257,483

 

$

216,025

 

$

258,574

 

$

298,790

 

Income from continuing operations per share of common stock (b)

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

2.01

 

$

2.12

 

$

1.79

 

$

2.14

 

$

2.42

 

Diluted

 

$

2.00

 

$

2.10

 

$

1.77

 

$

2.09

 

$

2.37

 

Total assets

 

$

5,329,622

 

$

3,936,971

 

$

3,282,255

 

$

3,342,285

 

$

3,205,346

 

Long-term debt

 

$

1,249,200

 

$

753,500

 

$

763,500

 

$

766,500

 

$

626,500

 

Cash dividends declared per share of common stock (b)

 

$

0.880

 

$

0.880

 

$

0.870

 

$

0.820

 

$

0.720

 

 


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

(b)         All 2004 and 2005 per share amounts have been adjusted for the two-for-one stock split affected on September 1, 2005.

 

See Item 1A, “Risk Factors,” in the Company’s 2008 Form 10-K and 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.

 

26



Table of Contents

 

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

 

Consolidated Results of Operations

 

EQT’s consolidated income from continuing operations for 2008 was $255.6 million, $2.00 per diluted share, compared with $257.5 million, $2.10 per diluted share, for 2007 and $216.0 million, $1.77 per diluted share, for 2006.

 

The $1.9 million decrease in income from continuing operations from 2007 to 2008 reflects an increase in operating income of $153.1 million which was more than offset by the absence of a 2007 pre-tax gain of $126.1 million on the sale of assets in the Nora area, higher 2008 interest and income taxes and a 2008 other-than-temporary impairment loss on available for sale securities.

 

Operating income for 2008 was impacted by decreased incentive compensation expense, increased production revenues due to higher average well-head sales prices and significantly higher volumes, increased gathering and transmission revenues due to higher rates and volumes, and the absence of 2007 transaction costs associated with the terminated Peoples and Hope acquisition. The decreased incentive compensation expense was the result of the reversal of previously recorded expense on the Company’s 2005 Executive Performance Incentive Program partially offset by increases in short-term incentive compensation. These items were partially offset by increased depletion, depreciation and amortization, increased operating and administrative expenses and the impact of the May 2007 asset sales.

 

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. At Equitable Distribution, revenues increased primarily due to colder weather in Equitable Gas’s service territory. At EQT Midstream, an increase in transmission and storage revenues due to increased storage asset optimization transactions and utilization of contractual transmission capacity to increase its wholesale marketing activities and an increase in gathering and processing net operating revenues due to higher frac spreads for NGLs extracted in 2007 were partially offset by a decrease in revenues due to the 2006 favorable impact of the settlement of the Equitrans rate case. At EQT Production, revenues increased due to higher production sales volumes.

 

The increased revenue between 2006 and 2007 was 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 EQT Production. 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 effective tax rate for 2008 was 37.7% compared to 35.9% in 2007. The higher effective tax rate in 2008 is the result of several factors including the Company being in a net operating loss position for tax purposes in 2008 which results in the loss of certain deductions for 2008 and for prior years as a result of carrying losses back to receive a cash refund of taxes paid. In addition, state taxes increased due to limitations imposed on certain state tax losses generated in 2008 and the Company recorded a net increase to tax expense as a result of the completion of its IRS audit through the 2005 tax year, slightly offset by a beneficial change in the West Virginia state tax law. 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. 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.

 

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 expenses

 

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Table of Contents

 

(income) and administrative expenses totaling ($17.4) million, $65.3 million and $21.9 million in 2008, 2007 and 2006, respectively, were not allocated to business segments. The unallocated income in 2008 primarily relates to the reversal of previously recorded performance-related incentive expenses, while the unallocated expense in 2007 and 2006 relates to performance-related incentive expenses in those years.

 

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 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. EQT’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 EQT’s segments without being obscured by these items for the other segments or by the effects of corporate allocations. In addition, management uses these measures for budget planning purposes.

 

EQT Production

 

Overview

 

EQT’s strategy is to maximize value by profitably developing the Company’s extensive acreage position through organic growth enabled by a low cost structure. The Company is focused on continuing its significant organic reserve and production growth through its drilling program and believes that it is a technological leader in drilling in low pressure shale. In particular, the use of air in horizontal drilling has proven to be a cost effective technology which the Company has efficiently deployed to various geological formations in the Appalachian mountain terrain and which may be deployed to other Company assets in the Basin to maximize production.

 

The Company drilled 668 gross wells (533 net wells) in 2008, including 23 Marcellus wells (16 vertical and 7 horizontal), 24 horizontal Berea wells, and 357 horizontal wells targeting the Lower Huron. Proved reserves increased 428 Bcfe (16%) to 3,110 Bcfe during the year.

 

EQT Production’s revenues for 2008 increased approximately 26% compared to 2007 revenues. Gas sales volumes increased 12% from 2007, excluding volumes from properties sold during 2007, primarily as a result of increased production from the 2008 and 2007 drilling programs partially offset by the normal production decline in the Company’s producing wells. Well-head sales prices increased approximately 16%, as increased commodity market prices offset slightly lower hedge prices year-over-year.

 

Operating expenses at EQT Production include an $8.2 million increase in the Company’s exploration program. The increase in exploration expense is a result of the Company’s initiative to explore additional reserve opportunities in various exploration plays on its legacy acreage position with the purchase and interpretation of seismic data for unproved properties. Excluding exploration expenses, 2008 operating expenses increased 21% primarily due to higher depletion resulting from increased drilling investments, increased lease operating expenses due to increased production volumes and higher production taxes due to higher prices and volumes, partially offset by the absence of 2007 charges for legal reserves, settlements and related expenses.

 

28



Table of Contents

 

Results of Operations

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

%
change
2008 -
2007

 

2006

 

%
change
2007 -
2006

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATIONAL DATA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production:

 

 

 

 

 

 

 

 

 

 

 

Natural gas and oil production (MMcfe) (a)

 

90,585

 

83,114

 

9.0

 

81,371

 

2.1

 

Company usage, line loss (MMcfe)

 

(6,577

)

(6,035

)

9.0

 

(5,215

)

15.7

 

Total sales volumes (MMcfe)

 

84,008

 

77,079

 

9.0

 

76,156

 

1.2

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

5.32

 

$

4.59

 

15.9

 

$

4.60

 

(0.2

)

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

0.35

 

$

0.31

 

12.9

 

$

0.29

 

6.9

 

Production taxes ($/Mcfe)

 

$

0.52

 

$

0.43

 

20.9

 

$

0.47

 

(8.5

)

Production depletion ($/Mcfe)

 

$

0.81

 

$

0.70

 

15.7

 

$

0.62

 

12.9

 

 

 

 

 

 

 

 

 

 

 

 

 

Production depletion

 

$

73,362

 

$

58,264

 

25.9

 

$

50,330

 

15.8

 

Other depreciation, depletion and amortization (DD&A)

 

4,872

 

3,820

 

27.5

 

3,141

 

21.6

 

Total DD&A

 

$

78,234

 

$

62,084

 

26.0

 

$

53,471

 

16.1

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures (thousands) (b)

 

$

700,745

 

$

328,080

 

113.6

 

$

205,047

 

60.0

 

 

 

 

 

 

 

 

 

 

 

 

 

FINANCIAL DATA (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

$

457,144

 

$

364,396

 

25.5

 

$

359,526

 

1.4

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

LOE, excluding production taxes

 

31,719

 

25,361

 

25.1

 

23,818

 

6.5

 

Production taxes (c)

 

47,158

 

36,123

 

30.5

 

38,198

 

(5.4

)

Exploration expense

 

9,064

 

862

 

951.5

 

802

 

7.5

 

Selling, general and administrative (SG&A)

 

38,185

 

37,947

 

0.6

 

27,814

 

36.4

 

DD&A

 

78,234

 

62,084

 

26.0

 

53,471

 

16.1

 

Total operating expenses

 

204,360

 

162,377

 

25.9

 

144,103

 

12.7

 

Operating income

 

$

252,784

 

$

202,019

 

25.1

 

$

215,423

 

(6.2

)

 


(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 and Company usage, line loss.

 

(b)         2007 capital expenditures include $24.4 million for the acquisition of working interests in wells in the Roaring Fork area.

 

(c)          Production taxes include severance and production-related ad valorem and other property taxes.

 

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Table of Contents

 

Fiscal Year Ended December 31, 2008 vs. December 31, 2007

 

EQT Production’s operating income totaled $252.8 million for 2008 compared to $202.0 million for 2007, an increase of $50.8 million between years, primarily due to a higher average well-head sales price and increased gas sales volumes, partially offset by an increase in operating expenses.

 

Total operating revenues were $457.1 million for 2008 compared to $364.4 million for 2007. The $92.7 million increase in operating revenues was due to higher realized prices and increased sales volumes. The average well-head sales price increase by $0.73 per Mcfe, primarily as a result of an increase in NYMEX natural gas prices and a higher percentage of unhedged gas sales, partially offset by a lower realized hedge price. Additionally, sales volumes increased 12% excluding the 2007 sale of interests which provided sales of 1,966 MMcfe during 2007, as a result of the 2008 and 2007 drilling programs net of the normal production decline in the Company’s wells.

 

Operating expenses totaled $204.4 million for 2008 compared to $162.4 million for 2007. The $42.0 million increase in operating expenses was a result of increases of $16.2 million in DD&A, $11.0 million in production taxes, $6.4 million in LOE, and $0.2 million in SG&A. In addition, the 2008 period includes an $8.2 million increase in exploration expense due to the purchase and interpretation of seismic data in support of the Company’s examination of emerging plays. The increase in DD&A was primarily due to increased depletion expense resulting from both increases in the unit rate ($9.9 million) and volume ($5.0 million). The $0.11 increase in the depletion rate is primarily attributable to the increased investment in oil and gas producing properties. The increase in production taxes was primarily due to a $9.8 million increase in severance taxes and a $1.2 million increase in property taxes. The increase in severance taxes (a production tax imposed on the value of gas extracted) was primarily due to higher gas commodity prices and higher sales volumes in the various taxing jurisdictions that impose such taxes. 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 increase in LOE was attributable to personnel costs, the 2008 program to test the re-fracturing of existing wells, salt water and waste disposal, environmental costs and road and location maintenance. The increase in SG&A was primarily due to higher overhead costs associated with the growth of the Company partially offset by lower charges for certain legal disputes in 2008 compared to 2007.

 

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

 

EQT Production’s operating income totaled $202.0 million for 2007 compared to $215.4 million for 2006, a decrease of $13.4 million between years, primarily due to an increase in operating expenses, partially offset by increased sales volumes.

 

Total operating revenues were $364.4 million for 2007 compared to $359.5 million for 2006. The $4.9 million increase in operating revenues was primarily due to a 1% increase in total sales volumes as a result of the 2007 and 2006 drilling programs net of the normal production decline in the Company’s wells and was partially offset by the 2007 sale of interests which provided sales of 3,044 MMcfe during 2006. In addition, the average well-head sales price decreased $0.01 per Mcfe primarily due to a decrease in NYMEX natural gas prices, partially offset by a higher percentage of unhedged gas sales and a higher realized hedge price.

 

Operating expenses totaled $162.4 million for 2007 compared to $144.1 million for 2006. The $18.3 million increase in operating expenses was due to increases of $10.1 million in SG&A, $8.6 million in DD&A and $1.5 million in LOE, excluding production taxes, partially offset by a decrease of $2.1 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 2006 increases 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). 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.

 

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Table of Contents

 

See the “Capital Resources and Liquidity” section for discussion of EQT Production’s capital expenditures during 2008, 2007 and 2006.

 

Outlook

 

EQT Production’s business strategy is focused on organic growth of the Company’s natural gas reserves and sales volumes. Key elements of EQT Production’s strategy include:

 

·                  Expanding reserves and production through horizontal drilling in Kentucky and West Virginia. The Company is committed to expanding its reserves and production through horizontal drilling, exploiting additional reserve potential through key emerging development plays and expanding its infrastructure in the Appalachian Basin. 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 2009 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 2009, the Company will examine the potential for exploitation of gas reserves in new geological formations and through different technologies. Plans include the drilling of horizontal Berea and Marcellus wells and testing the Devonian shale in Virginia. In addition, the Company intends to obtain proprietary seismic data in order to evaluate future deep drilling opportunities in certain emerging plays.

 

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Table of Contents

 

EQT Midstream

 

Overview

 

EQT Midstream provides gathering, processing, transmission and storage services to EQT Production and independent third parties. In 2008, EQT Midstream focused on building a long-term growth platform, highlighted by the construction of the Big Sandy Pipeline, the Kentucky Hydrocarbon processing plant and the Mayking corridor. This infrastructure development facilitates the development of EQT Production’s growing reserve base in the Huron play and provides opportunities to sell capacity to third parties. In 2009, EQT Midstream will focus on continuing to expand its gathering system through well connections to existing midstream infrastructure and thereby filling existing capacity. Additionally, initial infrastructure expansion in the Marcellus play in southwestern Pennsylvania and northern West Virginia is slated for 2009.

 

EQT Midstream achieved a number of operational milestones in 2008. In the second half of the year, EQT Midstream completed construction on the expansion of the Kentucky hydrocarbon processing plant and gas compression facilities (Kentucky Hydrocarbon) and turned in line the Mayking Corridor project (Mayking). Kentucky Hydrocarbon has the capacity to process 170 MMcfe of natural gas per day. Mayking consists of three compressor units and 38 miles of pipe. In the second quarter, the Big Sandy Pipeline, a 68-mile pipeline that connects Kentucky Hydrocarbon to the Tennessee Gas Pipeline and currently provides up to 130,000 Dth per day of firm transportation service, came on-line. The combination of Kentucky Hydrocarbon, Mayking and the Big Sandy Pipeline provide the platform for significant sales growth starting in the fourth quarter of 2008 and beyond and will help to mitigate curtailments and increase the flexibility and reliability of the Company’s gathering systems in transporting gas to market.

 

Also in 2008, Equitable Energy executed a binding precedent agreement with TGP for a 15-year term that, along with other contractual provisions, awarded the Company 300,000 Dth per day of capacity in TGP’s 300-Line expansion project. When completed, this expansion project will consist of approximately 128 miles of 30-inch pipe loop and approximately 52,000 horsepower of additional compression facilities to be constructed in TGP’s existing pipeline corridor in Pennsylvania and New Jersey. The awarded capacity will provide Equitable Energy access to consumer markets along the TGP long-line transmission system from the Gulf Coast to the Mid-Atlantic and the Northeast United States.

 

EQT Midstream’s net operating revenues increased by 16% from 2007 to 2008. This increase was primarily due to increases in the average gathering fee, higher processing net revenues and transmission revenues from the Big Sandy Pipeline. Increases in net operating revenues were more than offset by an increase in operating expenses which included $10.7 million for the settlement of certain pension and post-retirement benefits including related severance and legal fees.

 

During May 2007, the EQT Midstream 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 Pine Mountain Oil and Gas, Inc. (PMOG), in exchange for a 50% equity interest in the LLC and cash. See Note 5 to the Company’s Consolidated Financial Statements for further discussion of this transaction. 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 EQT Midstream’s operating results beginning in the second quarter of 2007. However, EQT Midstream records its 50% equity interest in the earnings of Nora Gathering, LLC in equity in earnings of nonconsolidated investments. Also in 2007, EQT purchased certain gathering assets in the Roaring Fork area from the minority interest holders. See Note 6 to the Company’s Consolidated Financial Statements for further discussion of this transaction.

 

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Table of Contents

 

Results of Operations

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

%
change
2008 -
2007

 

2006

 

%
change
2007 -
2006

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATIONAL DATA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering and processing:

 

 

 

 

 

 

 

 

 

 

 

Gathered volumes (BBtu)

 

145,031

 

143,338

 

1.2

 

157,248

 

(8.8

)

Average gathering fee ($/MMBtu)

 

$

0.98

 

$

0.84

 

16.7

 

$

0.79

 

6.3

 

Gathering and compression expense ($/MMBtu) (b)

 

$

0.37

 

$

0.35

 

5.7

 

$

0.28

 

25.0

 

NGLs sold (Mgal) (a)

 

81,856

 

72,430

 

13.0

 

70,963

 

2.1

 

Average NGL sales price($/gal)

 

$

1.24

 

$

1.07

 

15.9

 

$

0.95

 

12.6

 

 

 

 

 

 

 

 

 

 

 

 

 

Transmission pipeline throughput (BBtu):

 

76,270

 

53,514

 

42.5

 

53,151

 

0.7

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating revenues (thousands):

 

 

 

 

 

 

 

 

 

 

 

Gathering and processing

 

$

175,641

 

$

149,590

 

17.4

 

$

140,312

 

6.6

 

Transmission and storage

 

127,699

 

112,325

 

13.7

 

113,080

 

(0.7

)

Total net operating revenues

 

$

303,340

 

$

261,915

 

15.8

 

$

253,392

 

3.4

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating income (thousands):

 

 

 

 

 

 

 

 

 

 

 

Gathering and processing

 

$

58,575

 

$

65,003

 

(9.9

)

$

57,047

 

13.9

 

Transmission and storage

 

76,197

 

75,429

 

1.0

 

80,130

 

(5.9

)

Total net operating income

 

$

134,772

 

$

140,432

 

(4.0

)

$

137,177

 

2.4

 

 

 

 

 

 

 

 

 

 

 

 

 

DD&A (thousands):

 

 

 

 

 

 

 

 

 

 

 

Gathering and processing

 

$

25,575

 

$

19,230

 

33.0

 

$

18,287

 

5.2

 

Transmission and storage

 

9,227

 

7,103

 

29.9

 

7,535

 

(5.7

)

Total DD&A

 

$

34,802

 

$

26,333

 

32.2

 

$

25,822

 

2.0

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures (thousands)

 

$

593,564

 

$

433,719

 

36.9

 

$

146,512

 

196.0

 

 


(a)          NGLs sold includes NGLs recovered at the Company’s processing plant and transported to a fractionation plant owned by a third party for separation into commercial components, net of volumes retained, as well as equivalent volumes sold at liquid component prices under the Company’s contractual processing arrangements with third parties.

(b)         The calculation of gathering and compression expense ($/MMBtu) for 2008 and 2006 excludes a $9.5 million charge and a $3.3 million charge, respectively, for pension and other post-retirement benefits.

 

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Table of Contents

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

%
change
2008 -
2007

 

2006

 

%
change
2007 -
2006

 

 

 

 

 

 

 

 

 

 

 

 

 

FINANCIAL DATA (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

$

681,475

 

$

591,608

 

15.2

 

$

554,071

 

6.8

 

Purchased gas costs

 

378,135

 

329,693

 

14.7

 

300,679

 

9.6

 

Net operating revenues

 

303,340

 

261,915

 

15.8

 

253,392

 

3.4

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

Operating and maintenance (O&M)

 

84,558

 

66,155

 

27.8

 

63,811

 

3.7

 

SG&A

 

49,208

 

28,995

 

69.7

 

27,609

 

5.0

 

Impairment charges

 

 

 

 

(1,027

)

(100.0

)

Depreciation and amortization

 

34,802

 

26,333

 

32.2

 

25,822

 

2.0

 

Total operating expenses

 

168,568

 

121,483

 

38.8

 

116,215

 

4.5

 

Operating income

 

$

134,772

 

$

140,432

 

(4.0

)

$

137,177

 

2.4

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income, net

 

$

5,678

 

$

7,253

 

(21.7

)

$

1,149

 

531.2

 

Equity in earnings of nonconsolidated investments

 

$

5,053

 

$

2,648

 

90.8

 

$

 

100.0

 

 

Fiscal Year Ended December 31, 2008 vs. December 31, 2007

 

EQT Midstream’s operating income totaled $134.8 million for 2008 compared to $140.4 million for 2007, a decrease of $5.6 million between years. An increase in net operating revenues was more than offset by increased operating expenses, including a $10.7 million settlement charge for pension and post-retirement benefits including related severance and legal fees, and $5.2 million bad debt expense as a result of the Lehman Brothers bankruptcy. Excluding these items, operating income increased 7%.

 

Total net operating revenues were $303.3 million for 2008 compared to $261.9 million for 2007. The $41.4 million increase in total net operating revenues was due to a $26.0 million increase in gathering and processing net operating revenues and a $15.4 million increase in transmission and storage net operating revenues. The increase in gathering and processing net operating revenues was due to a 17% increase in the average gathering fee, increased NGLs sold, increased commodity prices for propane and other NGLs and a small increase in gathered volumes. The increase in the average gathering fee is reflective of the Company’s commitment to ensuring that this fee is sufficient to cover costs associated with infrastructure expansion. The volume of NGLs sold increased in 2008 as a result of the Company’s infrastructure investments. Gathered volumes increased 1% due to the increase in 2008 Company production and third party volumes which were partially offset by the elimination in 2008 of volumes gathered on assets contributed to Nora Gathering, LLC. The increase in transmission and storage net operating revenues was due to new transmission revenues from the Big Sandy Pipeline, which came on-line in the second quarter of 2008 and increased third party marketing that utilized Big Sandy Pipeline capacity.

 

Total operating revenues increased by $89.9 million, or 15%, primarily as a result of higher sales prices on increased commercial activity related to contractual transmission and storage assets, an increase in processing volumes and commodity prices, higher gathering rates and new transmission revenues from the Big Sandy Pipeline. Total purchased gas costs increased due to the higher gas costs on increased commercial activity related to contractual transmission and storage assets as well as higher gas costs related to processing activities.

 

Operating expenses totaled $168.6 million for 2008 compared to $121.5 million for 2007. The $47.1 million increase in operating expenses was due to increases of $20.2 million in SG&A, $18.4 million in O&M, and $8.5

 

34



Table of Contents

 

million in DD&A. The increase in SG&A was primarily due to labor and services to support the growth in the Midstream business, a $5.2 million reserve against Lehman Brothers receivables, and $1.2 million for legal and actuarial services associated with the pension and other post-retirement charge, partially offset by decreased SG&A for the gathering assets contributed to Nora Gathering, LLC. The increase in O&M resulted mainly from the $9.5 million pension and other post-retirement charge as well as increased electricity charges, compressor maintenance, labor and non-income taxes for the gathering and processing business due to new compressors and processing facilities, partially offset by the expenses associated with gathering asset contributed to Nora Gathering, LLC. The increase in DD&A was primarily due to the increased investment in infrastructure during 2008, partially offset by decreased depreciation relating to the gathering asset contribution to Nora Gathering, LLC.

 

Other income represents allowance for equity funds used during construction. The $1.6 million decrease from 2007 to 2008 was primarily caused by a full year of AFUDC on Big Sandy recorded in 2007, as compared to only a partial year in 2008 as Big Sandy was placed on-line in the second quarter of 2008.

 

Equity in earnings of nonconsolidated investments totaled $5.1 million for 2008 compared to $2.6 million for 2007. This increase is related to equity earnings recorded for EQT Midstream’s investment in Nora Gathering, LLC, which was formed in May 2007.

 

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

 

EQT Midstream’s operating income totaled $140.4 million for 2007 compared to $137.2 million for 2006, an increase of $3.2 million between years. An increase in net operating revenues was largely offset by increased operating expenses.

 

Total net operating revenues were $261.9 million for 2007 compared to $253.4 million for 2006. The $8.5 million increase in total net operating revenues was due primarily to increases in gathering and processing net operating revenues, partially offset by a decrease in transmission and storage net operating revenues. The $9.3 million increase in gathering and processing net operating revenues was due to higher sales prices for the NGL products sold in 2007 as compared to 2006, a 2% increase in NGL volumes sold and a 6% increase in the average gathering fee, partially offset by a 9% decline in gathered volumes. Commodity market prices for propane and other NGLs increased significantly in 2007 compared to 2006. The increase in average gathering fee is reflective of the Company’s commitment to ensuring that this fee is sufficient to cover costs associated with infrastructure expansion. The decrease in gathered volumes is primarily the result of a reduction in volumes gathered for EQT Production due to the contribution of gathering facilities and pipelines to Nora Gathering, LLC, partially offset by increased Company production. The $0.8 million decrease in transmission and storage net operating revenues was primarily due to the positive effect of the Equitrans rate case settlement of $7.0 million recorded in 2006, partially offset by storage asset optimization realized in 2007 as the Company used contractual storage capacity to capture unusually high summer-to-winter price spreads, Equitrans’ Pipeline Safety surcharge that was formally approved by the FERC in November 2007 and increased firm transportation rates year over year. The storage price spreads were captured at a time of high volatility and the transactions settled in 2007.

 

Operating expenses totaled $121.5 million for 2007 compared to $116.2 million for 2006. The $5.3 million increase in operating expenses was due to increases of $2.4 million in O&M and $1.4 million in SG&A, $1.0 million in impairment charge reversals recorded in 2006 and an increase of $0.5 million in DD&A. The increase in O&M was due to increased expense in 2007 for the Company’s gathering and transmission facilities primarily due to increased electricity charges on newly installed electric compressors, increased field line and compressor maintenance, increased field labor and related employment costs, increased compliance and maintenance costs and increased fleet-related costs, as well as the recognition of $0.7 million of pipeline safety costs that were deferred pending the FERC order on the Equitrans Pipeline Safety surcharge. Partially offsetting these increases in O&M were a decrease in O&M expenses relating to the gathering asset contribution to Nora Gathering, LLC and a decrease due to a 2006 pension and other post-retirement benefits charge of $3.3 million for an early retirement program relating to the gathering and processing business. The increase in SG&A is primarily due to higher labor costs including higher incentive compensation costs, partially offset by decreased SG&A for the gathering assets contributed to Nora Gathering, LLC. The increase in DD&A was primarily due to the increased investment in gathering infrastructure during 2007 partially offset by decreased depreciation relating to the gathering asset contribution to Nora Gathering, LLC.

 

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Table of Contents

 

Other income represents AFUDC-Equity and the $6.2 million increase from 2006 to 2007 was primarily the result of increased capital spending for the Big Sandy Pipeline as well as spending on pipeline safety and integrity projects.

 

Equity in earnings of nonconsolidated investments totaled $2.6 million for 2007 and related to equity earnings recorded for EQT Midstream’s investment in Nora Gathering, LLC.

 

See the “Capital Resources and Liquidity” section for discussion of EQT Midstream’s capital expenditures during 2008, 2007 and 2006.

 

Outlook

 

EQT Midstream is focused on building a long-term growth platform to facilitate the development of EQT Production’s growing reserve base. In 2009, under current capital market conditions, EQT Midstream will fill existing capacity by building smaller gathering lines in Kentucky, West Virginia and Pennsylvania to tie in wells. This will facilitate the delivery of gas from wells drilled by EQT Production in 2009 and will provide additional capacity to help mitigate curtailments, increase the flexibility and reliability of the Company’s gathering systems in transporting gas to market and provide additional capacity for growth. EQT Midstream will also make the initial infrastructure expansion in the Company’s Marcellus play in southwestern Pennsylvania and northern West Virginia. In addition, processing upgrades to the Kentucky Hydrocarbon plant are planned. If the capital markets become less constrained, EQT Midstream will consider increasing investment in corridor infrastructure projects to provide additional capacity needed to facilitate production growth.

 

36



Table of Contents

 

Equitable Distribution

 

Overview

 

Equitable Distribution’s business strategy is to earn a competitive return on its asset base through regulatory mechanisms and operational efficiency. Equitable Distribution is focused on enhancing the value of its existing assets by establishing a reputation for excellent customer service, effectively managing its capital spending, improving the efficiency of its workforce through superior work management and continuing to leverage technology throughout its operations.

 

In 2008, Equitable Gas filed a base rate case in Pennsylvania to recover an increased return on assets placed in service since the previous rate case and to fully recover costs associated with the CAP. In November 2008, Equitable Gas reached a settlement with the active parties that would result in a projected revenue increase of approximately $38 million annually compared to the requested increase of $51.9 million. The settlement must be approved by the PA PUC to be effective. On January 20, 2009, a PA PUC Administrative Law Judge recommended approval of the rate case settlement by the PA PUC. The PA PUC approval is expected before March 31, 2009.

 

If approved, this settlement will result in the first delivery rate increase for Equitable Gas in more than a decade. Since 1997, Equitable Gas has invested more than $360 million to upgrade its pipeline infrastructure, improve the efficiency of its operations and enhance the quality of its customer service.  As a result of these investments, the company now ranks among the highest in Pennsylvania in gas utility call center service levels and has achieved documented improvements in on-time scheduled appointment performance and safety.

 

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. On September 27, 2007, the PA PUC issued an order approving an increase to Equitable Gas’s CAP surcharge, which is designed to offset the costs of the CAP. The revised surcharge went into effect on October 2, 2007. If the rate case settlement is approved, Equitable Gas will increase the CAP surcharge from $0.58 per mcf to $1.30 per mcf and will receive an annual reconciliation of CAP costs to ensure complete recovery beginning in the first quarter of 2009.

 

Equitable Distribution’s net operating revenues increased 6% from 2007 to 2008 primarily due to the increase in surcharges collected to support CAP and colder weather in Equitable Gas’ service territory in 2008. The weather in Equitable Gas’ service territory in 2008 was 5% colder than 2007, but was still 4% warmer than the 30-year National Oceanic and Atmospheric Administration (NOAA) average for the Company’s service territory. The weather in 2007 was 9% warmer than the 30-year average. Total operating expenses decreased 12% from 2007, primarily due to the absence of transaction and transition planning costs related to the terminated Peoples and Hope acquisition incurred in 2007, partially offset by a 2008 increase in CAP expenses. These increased CAP costs were recovered through an increase in collected CAP surcharge.

 

On March 1, 2006, the Company entered into an 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 legal approvals for this transaction, the Company and Dominion agreed to terminate the agreement 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.

 

37



Table of Contents

 

Results of Operations

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

%
change
2008 -
2007

 

2006

 

%
change
2007 -
2006

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATIONAL DATA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

5,622

 

5,332

 

5.4

 

4,976

 

7.2

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential sales and transportation volume (MMcf)

 

23,824

 

23,494

 

1.4

 

21,014

 

11.8

 

Commercial and industrial volume (MMcf)

 

27,503

 

25,971

 

5.9

 

23,841

 

8.9

 

Total throughput (MMcf) — Distribution

 

51,327

 

49,465

 

3.8

 

44,855

 

10.3

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating revenues (thousands):

 

 

 

 

 

 

 

 

 

 

 

Residential

 

$

105,059

 

$

99,050

 

6.1

 

$

92,497

 

7.1

 

Commercial & industrial

 

46,394

 

42,558

 

9.0

 

42,519

 

0.1

 

Off-system and energy services

 

19,415

 

19,021

 

2.1

 

15,647

 

21.6

 

Total net operating revenues

 

170,868

 

$

160,629

 

6.4

 

$

150,663

 

6.6

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures (thousands)

 

$

45,770

 

$

41,684

 

9.8

 

$

48,721

 

(14.4

)

 

 

 

 

 

 

 

 

 

 

 

 

FINANCIAL DATA (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

$

698,385

 

$

624,744

 

11.8

 

$

586,194

 

6.6

 

Purchased gas costs

 

527,517

 

464,115

 

13.7

 

435,531

 

6.6

 

Net operating revenues

 

170,868

 

160,629

 

6.4

 

150,663

 

6.6

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

O & M

 

44,161

 

41,613

 

6.1

 

40,690

 

2.3

 

SG&A

 

44,793

 

64,454

 

(30.5

)

49,631

 

29.9

 

Impairment charges

 

 

 

 

(1,369

)

(100.0

)

DD&A

 

22,055

 

20,021

 

10.2

 

19,938

 

0.4

 

Total operating expenses

 

111,009

 

126,088

 

(12.0

)

108,890

 

15.8

 

Operating income

 

$

59,859

 

$

34,541

 

73.3

 

$

41,773

 

(17.3

)

 

Fiscal Year Ended December 31, 2008 vs. December 31, 2007

 

Equitable Distribution’s operating income totaled $59.9 million for 2008 compared to $34.5 million for 2007. The $25.4 million increase in operating income is primarily due to increased CAP surcharge revenues, colder weather and lower SG&A expenses due to the absence in 2008 of costs associated with the now terminated Peoples and Hope acquisition.

 

Net operating revenues were $170.9 million for 2008 compared to $160.6 million for 2007. The $10.3 million increase in net operating revenues was primarily a result of increased CAP surcharge revenues. The CAP surcharge increased from $0.30 per mcf to $0.58 per mcf in the fourth quarter of 2007. Additionally, 2008 weather was 5% colder than the prior year. Commercial and industrial revenues increased due to an increase in performance-based revenues as well as increased volumes of 1,532 MMcf from 2007 to 2008 primarily due to an increase in usage by one industrial customer. Off-system and energy services net operating revenues increased due to increased gathering revenue as a result of increased volumes and rates, partially offset by lower volumes and margins in asset

 

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optimization activities. Additionally, an increase in the commodity component of residential tariff rates resulted in an increase in both total operating revenues and purchased gas costs.

 

Operating expenses totaled $111.0 million for 2008 compared to $126.1 million for 2007. This $15.1 million decrease was primarily due to the impact of $21.0 million in 2007 costs related to the now terminated Peoples and Hope acquisition, a $2.5 million decrease in incentive compensation expenses and a $1.8 million reduction in insurance reserves due to increased safety measures.  Partially offsetting these decreases were a $5.5 million increase in customer assistance expenses resulting from a significant increase in customer participation in the CAP and a $2.6 million increase in operating expenses primarily related to increased leak repair and maintenance activities for gathering operations, service line maintenance and line location requests and higher gas prices. Additionally, there was a $2.1 million increase in depreciation due to an adjustment in asset estimated useful lives resulting from the PA PUC-mandated asset service life study as well as increased capital expenditures.

 

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

 

Equitable Distribution’s operating income totaled $34.5 million for 2007 compared to $41.8 million for 2006.  An increase in net operating revenues was more than offset by increased operating expenses 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.

 

Net operating revenues were $160.6 million for 2007 compared to $150.7 million for 2006.  The $9.9 million increase in net operating revenues was primarily 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.

 

Operating expenses totaled $126.1 million for 2007 compared to $108.9 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 $1.4 million from the partial reversal of a 2005 impairment charge in connection with the Company’s office consolidation.  Other increases in operating expenses included higher corporate overhead allocations, increased labor costs including information technology enhancements and costs associated with a customer experience study of 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, which resulted in reductions in delinquent accounts receivable and net write-offs.

 

Outlook

 

As described above, Equitable Gas reached a settlement of its Pennsylvania rate case that, if approved, will result in a projected revenue increase of approximately $38 million annually. The new rates are expected to go into place no later than March 31, 2009, with the first full year impact realized in 2010 results.  The rate increase will allow Equitable Distribution to earn an improved return on its asset base. Under the terms of the rate case settlement, Equitable Gas will also reduce exposure to the cost of PUC mandated customer assistance programs through a reconcilable surcharge.

 

Customer conservation, which has occurred over time as a result of product efficiency and higher natural gas prices, has reduced residential customer usage over time. The Company has not, however, experienced a significant decrease in weather adjusted throughput or deterioration in customer collections in 2008 compared to recent levels. If the current economic downturn persists, Equitable Distribution may experience a reduction in commercial and industrial throughput as well as an increase in bad debt expense, which would reduce the return on its asset base.

 

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Table of Contents

 

Other Income Statement Items

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

 

 

(Thousands)

 

 

 

Other-than-temporary-impairment on available-for-sale securities

 

$

(7,835

)

$

 

$

 

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

 

 

1,042

 

 

Other income

 

6,233

 

7,645

 

1,442

 

Gain on sale of assets, net

 

 

126,088

 

 

Income from discontinued operations

 

 

 

4,261

 

 

During 2007, the EQT Production segment sold to 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 EQT Midstream 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 5 to the Company’s Consolidated Financial Statements for further discussion of these transactions.

 

As discussed in Note 10 to the Company’s Consolidated Financial Statements, the Company’s available-for-sale investments consist of equity and bond funds intended to fund plugging and abandonment and other liabilities for which the Company self-insures. At December 31, 2008, these investments had a fair market value which was $7.8 million below cost. The Company analyzed the decline in these investments based on the extent and duration of the impairment, the nature of the underlying assets and the Company’s intent and ability to hold the investments. Although the Company holds these investments to fund long-term liabilities, based on the extent and duration of the impairment, combined with current market conditions, the Company concluded that the decline was other-than-temporary. As such, the Company recognized a $7.8 million impairment in earnings in 2008.

 

Also discussed in Note 10 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.

 

In 2008, 2007 and 2006, other income primarily relates to the equity portion of AFUDC. Prior to 2007, the equity portion of AFUDC 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. AFUDC increased substantially in 2007 as a result of the substantial investment in the Big Sandy Pipeline then under construction. Construction was completed in the second quarter 2008, reducing AFUDC in the current year.

 

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.

 

Interest Expense

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

 

 

 

 

 

 

 

 

Interest expense

 

$

58,394

 

$

47,669

 

$

48,494

 

 

Interest expense increased by $10.7 million from 2007 to 2008 primarily due to the Company’s investment in drilling and midstream infrastructure during 2007 and 2008. This investment was partially funded by the issuance of $500 million of 6.5% notes in March 2008. The interest expense associated with these notes was partially offset by a 2.3% decrease in the average short-term interest rate during 2008.

 

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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 weighted 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.

 

Weighted average annual interest rates on the Company’s short-term debt were 3.5%, 5.8% and 4.6% for 2008, 2007 and 2006, respectively.

 

Capital Resources and Liquidity

 

Overview

 

The Company’s primary sources of cash during 2008 were proceeds from a public offering of the Company’s common stock and from a public offering of Senior Notes and cash flows from operating activities. The Company used the cash primarily to fund its capital program and to repay short-term notes.

 

Operating Activities

 

Cash flows provided by operating activities totaled $509.2 million for 2008 as compared to $426.7 million for 2007, a net increase of $82.5 million in cash flows provided by operating activities between years. The increase in cash flows provided by operating activities was primarily attributable to a net cash refund related to income taxes of $14.0 million in 2008 compared to a net cash payment of $63.4 million in 2007. 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 IDC deduction resulting from its drilling program coupled with accelerated tax depreciation for expansion of the gathering infrastructure put the Company into an overall federal tax net operating loss position in 2008. This tax position is likely to continue so long as expansion in Appalachia continues. As such, the Company expects minimal federal cash taxes for the foreseeable future.

 

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 incentive compensation plans and the timing of related 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.

 

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Table of Contents

 

Investing Activities

 

Cash flows used in investing activities totaled $1,376.0 million for 2008 as compared to $590.1 million for 2007, a net increase of $785.9 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 $1,344.0 million in 2008 from $776.7 million in 2007. See discussion of capital expenditures below;

 

·                  capital contributions of $29.0 million to Nora Gathering, LLC in 2008 for use in midstream infrastructure projects;

 

·                  the absence in 2008 of proceeds of $217.0 million received in 2007 from the sale and contribution of assets. See Note 5 to the Company’s Consolidated Financial Statements.

 

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;

 

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

 

partially offset by:

 

·                  proceeds of $217.0 million received in 2007 from the sale and contribution of assets. See Note 5 to the Company’s Consolidated Financial Statements.

 

Capital Expenditures

 

 

 

2009 Forecast

 

2008 Actual

 

2007 Actual

 

2006 Actual

 

Well development
(primarily drilling)

 

$

600

 million

 

$

701

 million

 

$

328

 million*

 

$

205

 million

 

Midstream infrastructure

 

$

360

 million

 

$

594

 million

 

$

434

 million*

 

$

146

 million

 

Distribution infrastructure and other corporate items

 

$

40

 million

 

$

49

 million

 

$

43

 million

 

$

52

 million

 

Total

 

$

1,000

 million

 

$

1,344

 million

 

$

805

 million

 

$

403

 million

 

 


*                                         Includes $24.4 million and $3.7 million, in the well development and Midstream infrastructure categories, respectively, for the acquisition of additional working interest and related gathering assets in the Roaring Fork area. See Note 6 to the Company’s Consolidated Financial Statements.

 

The Company is committed to profitably expanding its reserves and production through horizontal drilling, exploiting additional reserve potential through key emerging development plays and expanding its infrastructure in the Appalachian Basin. However, in light of the current capital market conditions, the Company has developed a plan to reduce capital spending significantly for 2009 as compared to 2008 and anticipates that this capital spending plan will not require the Company to access capital markets through the end of 2010. This plan will be funded by the Company’s cash flow from operating activities as well as a portion of the Company’s $1.5 billion revolving credit facility. The Company remains flexible to reduce capital spending to operating cash flow levels should market conditions further deteriorate. The Company anticipates annual gas sales volume growth of 15% in 2009

 

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through concentrating spending on drilling where midstream capacity has already been built. If the capital markets become unconstrained, the Company believes it has a long-term production growth potential of greater than 20% per year. The Company’s forecasted 2009 capital expenditures contemplate up to 675 gross wells, including 375 horizontals.

 

Capital expenditures for drilling and development totaled $701 million and $328 million during 2008 and 2007, respectively. The Company drilled 668 gross wells, including 389 gross horizontal wells in 2008, compared to 634 gross wells, including 88 gross horizontal wells during 2007. Capital expenditures for 2008 also included $85.2 million for undeveloped property acquisitions, primarily within the Marcellus acreage.

 

Capital expenditures for the midstream operations totaled $594 million and $434 million during 2008 and 2007, respectively. These capital expenditures were used primarily for the construction and expansion of natural gas pipelines and natural gas processing facilities. Included in such expenditures for 2008 was $366 million for gathering pipeline and compression, including $105 million in the Mayking corridor; $105 million for the Ranger liquids line project and Kentucky Hydrocarbon processing plant upgrade; and $35 million for completion of the Big Sandy Pipeline. Approximately $84 million of 2008 capital expenditures related to compliance, line loss, facilities and information technology.

 

Capital expenditures for well development and midstream infrastructure increased in 2007 as compared to 2006 primarily due to an increased drilling and development program in 2007, capital expended for the continued construction of the Big Sandy Pipeline, upgrades to the Kentucky Hydrocarbon plant and increased investment in gathering system compression and pipelines. Capital expenditures for distribution infrastructure decreased in 2007 as compared to 2006 primarily due to the installation of electronic meter reading technology on meters in 2006, a project that was substantially completed in the third quarter of 2006.

 

Financing Activities

 

Cash flows provided by financing activities totaled $785.1 million for 2008 as compared to $245.1 million of cash flows provided by financing activities for 2007. The increase in cash flows provided by financing activities was attributable largely to the following:

 

·                  net proceeds of $560.7 million from a public offering of 8.625 million shares of common stock in the second quarter of 2008. The proceeds from the offering were used for general corporate purposes, including the Company’s natural gas drilling, development and midstream infrastructure projects;

 

·                  a public offering during the first quarter of 2008 of $500.0 million in aggregate principal of 6.50% Senior Notes. The proceeds were used to repay short-term borrowings under the Company’s revolving credit facility.

 

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 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.

 

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. In addition to funding working capital requirements, which are significantly impacted by seasonality, the Company utilizes short-term borrowings to fund margin deposit requirements until the underlying transactions are settled or the deposits are returned and to finance capital expenditures until they can be permanently financed. The Company’s $1.5 billion revolving credit facility matures on October 26, 2011. The facility may be used for working capital, capital expenditures, share repurchases and other purposes including support of a commercial paper program.

 

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Table of Contents

 

The credit facility is underwritten by a syndicate of 15 financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by the Company. Lehman Brothers Bank, FSB (Lehman) is one of the 15 financial institutions in the syndicate and has committed to make loans not exceeding $95 million under the facility. Lehman failed to fund its portion of all recent borrowings by the Company which effectively reduces the total amount available under the facility to $1,405 million. Otherwise, the Company’s large syndicate group and relatively low percentage of participation by each lender is expected to limit the Company’s exposure if further problems or consolidation occur in the banking industry.

 

As of December 31, 2008, the Company had outstanding under the revolving credit facility loans of $319.9 million in support of corporate purposes and an irrevocable standby letter of credit of $25.8 million. The weighted average interest rates on the Company’s short-term borrowings was 3.5% for 2008. The interest rate on the revolving credit facility fluctuates with the LIBOR rate.

 

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

 

Security Ratings and Financing Triggers

 

The table below reflects the current credit ratings for the outstanding debt instruments of the Company. Changes in credit ratings may affect the Company’s cost of short-term and long-term debt and its access to the credit markets.

 

 

 

Unsecured

 

 

 

 

 

Medium-Term

 

Commercial

 

Rating Service

 

Notes

 

Paper

 

Moody’s Investors Service

 

Baa1

 

P-2

 

Standard & Poor’s Ratings Services

 

BBB

 

A-3

 

 

On October 15, 2008, S&P placed its ratings on EQT, as well as three other diversified energy companies, on CreditWatch with negative implications “in light of an increasing percentage of operating income and capital spending that is related to oil and gas exploration and production (E&P) activities.”  S&P stated that it expected to resolve the CreditWatch listing within three months but has not yet announced a decision.

 

On November 4, 2008, Moody’s reaffirmed its ratings on EQT and stated that the “rating reflects the diversification and vertical integration among its three business segments as well as the Baa stand-alone quality of both its E&P and LDC (local distribution company) operations.”

 

The Company’s credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization and each rating should be evaluated independently of any other rating. The Company cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant. If the credit rating agencies downgrade the Company’s ratings, particularly below investment grade, the Company’s access to the capital markets may be limited, borrowing costs and margin deposits would increase, counterparties may request additional assurances and the potential pool of investors and funding sources may decrease. The required margin is subject to significant change as a result of other factors besides credit rating such as gas prices and credit thresholds set forth in agreements between the hedging counterparties and the Company.

 

The Company’s debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. The most significant default events include maintaining covenants with respect to maximum leverage ratio, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. The Company’s current credit facility’s financial covenants require a total debt-to-total capitalization ratio of no greater than 65%. The calculation of this ratio excludes the effects of accumulated other comprehensive income (loss). As of December 31, 2008, the Company is in compliance with all existing debt provisions and covenants.

 

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Table of Contents

 

Commodity Risk Management

 

The Company’s overall objective in its hedging program is to protect earnings from undue exposure to the risk of changing commodity prices. The Company’s risk management program includes the use of exchange-traded natural gas futures contracts and options and OTC natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and for trading purposes. The derivative commodity instruments currently utilized by the Company are primarily fixed price swaps or collars.

 

The approximate volumes and prices of the Company’s total hedge position for 2009 through 2011 are:

 

 

 

2009

 

2010

 

2011

 

Swaps

 

 

 

 

 

 

 

Total Volume (Bcf)

 

37

 

23

 

19

 

Average Price per Mcf (NYMEX)*

 

$

5.91

 

$

5.12

 

$

5.10

 

 

 

 

 

 

 

 

 

Collars

 

 

 

 

 

 

 

Total Volume (Bcf)

 

23

 

21

 

18

 

Average Floor Price per Mcf (NYMEX)*

 

$

7.34

 

$

7.29

 

$

7.16

 

Average Cap Price per Mcf (NYMEX)*

 

$

13.68

 

$

13.51

 

$

13.48

 

 


* The above price is based on a conversion rate of 1.05 MMBtu/Mcf

 

The Company’s current hedged position provides price protection for greater than 65% of expected production in 2009 and 40% of expected production through 2011. The Company’s earnings per share exposure to a $0.10 change in average NYMEX natural gas price is approximately $0.03 per diluted share for 2009 and ranges from $0.04 to $0.05 per diluted share per year for 2010 and 2011. The Company also engages in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices.

 

See the “Quantitative and Qualitative Disclosures About Market Risk,” in Item 7A and Note 3 to the Company’s Consolidated Financial Statements for further discussion.

 

Other Items

 

Off-Balance Sheet Arrangements

 

In connection with the sale of its NORESCO domestic business in 2005, the Company agreed to maintain certain guarantees which benefit NORESCO. These guarantees, the majority of which predate the sale of NORESCO, became off-balance sheet arrangements upon the closing of the sale of NORESCO. These arrangements include guarantees of NORESCO’s obligations to the purchasers of certain of NORESCO’s contract receivables and agreements to maintain guarantees supporting NORESCO’s obligations under certain customer contracts. In addition, NORESCO and the purchaser agreed that NORESCO would fully perform its obligations under each underlying agreement and that the purchaser or NORESCO would reimburse the Company for losses under the guarantees. The purchaser’s obligations to reimburse the Company are capped at $6 million. The total maximum potential obligation under these arrangements is estimated to be approximately $318 million as of December 31, 2008, and decreases over time as the guarantees expire or the underlying obligations are fulfilled by NORESCO. In 2008, the original purchaser of NORESCO sold its interest in NORESCO and transferred its obligations to a third party. In connection with that event, the new owner is expected to deliver to the Company a $1 million letter of credit supporting its obligations. The Company determined that the likelihood the Company will be required to perform on these arrangements is remote, and as such, the Company has not recorded any liabilities in its Consolidated Balance Sheets related to these guarantees.

 

In November 1995, EQT, through a subsidiary, guaranteed a tax indemnification to the limited partners of Appalachian Basin Partners, LP (ABP) for any tax losses resulting from a disallowance of the nonconventional fuels

 

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tax credits, if certain representations and warranties of the Company were not true. The Company guaranteed the tax indemnification until the tax statute of limitations closes. The Company does not have any recourse provisions with third parties or any collateral held by third parties associated with this guarantee that could be liquidated to recover amounts paid, if any, under the guarantee. As of December 31, 2008, the maximum amount of future payments the Company could be required to make is estimated to be approximately $12 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN 45, and has not been modified subsequent to issuance. Additionally, based on the status of the Company’s IRS examinations, the Company has determined that any potential loss from this guarantee is remote.

 

The Company has a non-equity interest in a variable interest entity, Appalachian NPI, LLC (ANPI), in which EQT was not deemed to be the primary beneficiary. Thus, ANPI is not consolidated within the Company’s Consolidated Financial Statements. In determining the primary beneficiary, the Company estimated the expected losses and expected residual returns of ANPI under various scenarios in order to identify the party that would absorb the majority of the losses or benefit from the majority of the returns. The primary assumptions utilized in the scenarios included commodity price and production volumes. As of December 31, 2008, ANPI had $181 million of total assets and $227 million of total liabilities (including $102 million of long-term debt, including current maturities), excluding minority interest. ANPI is financed primarily through cash provided by operating activities.

 

The Company provides a liquidity reserve guarantee to ANPI, which is subject to certain restrictions and limitations that limit the amount of the guarantee to the calculated present value of the project’s future cash flows from the preceding year-end until the termination date of the agreement. This liquidity reserve guarantee is secured by the fair market value of the assets purchased by the Appalachian Natural Gas Trust (ANGT). The Company received a market-based fee for the issuance of the reserve guarantee. As of December 31, 2008, the maximum amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be approximately $22 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN 45 and has not been modified subsequent to issuance. The terms of the ANPI liquidity reserve guarantee require the Company to provide a letter of credit in favor of ANPI as security for the Company’s obligations. The amount of this letter of credit requirement at December 31, 2008 was approximately $25.8 million and is expected to decline over time under the terms of the liquidity reserve guarantee.

 

The Company has entered into an agreement with ANGT to provide gathering and operating services to deliver ANGT’s gas to market. In addition, the Company receives a marketing fee for the sale of gas based on the net revenue for gas delivered. The revenue earned from these fees totaled approximately $15.9 million, $15.8 million and $16.8 million for 2008, 2007 and 2006, respectively.

 

See Note 21 to the Consolidated Financial Statements for further discussion of the Company’s guarantees.

 

Pension Plans

 

Total pension expense recognized by the Company in 2008, 2007 and 2006, excluding special termination benefits, settlement losses and curtailment losses, totaled $0.5 million, $0.6 million and $0.1 million, respectively. The Company recognized special termination benefits, settlement losses and curtailment losses in 2008, 2007 and 2006 of $9.4 million, $1.4 million and $3.0 million, respectively.

 

During the fourth quarter of 2008, the Company settled its pension obligations under a plan covering employees of the former Kentucky West Virginia Gas Company LLC, an EQT subsidiary which merged into Equitable Gathering LLC. The former Kentucky West Virginia employees transferred to Equitable Gathering LLC or Equitable Production Company. As a result of the settlement, the Company recognized pension settlement expense of approximately $8 million. An additional $1.4 million of pension settlement losses were recognized in 2008 for lump sum payments made during the normal course of plan operations.

 

During 2007, the Company recognized a settlement expense of $0.5 million due to a plan design change for a specific union and an additional settlement expense for $0.5 million due to the transfer of some current active employees to non-union employment. During the fourth quarter of 2006, the Company recognized a settlement expense of approximately $2.7 million for an early retirement program.

 

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The Company made cash contributions to its pension plan of approximately $3.4 million, $1.3 million and $1.8 million during 2008, 2007 and 2006, respectively, as a result of the previously described settlements. Under current law, the Company expects to make cash payments related to its pensions of approximately $15 million in 2009 which will meet the 80% funding obligations on its remaining plans. Pension contributions will be funded by cash flow from operations or by borrowings under the Company’s revolving credit facility.

 

Rate Regulation

 

The Company’s distribution operations, transmission and storage operations and a portion of its gathering operations are subject to various forms of regulation as previously discussed. Accounting for the Company’s regulated operations is performed in accordance with the provisions of SFAS No. 71. As described in Notes 1 and 11 to the Consolidated Financial Statements, regulatory assets and liabilities are recorded to reflect future collections or payments through the regulatory process. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of the deferred costs.

 

Schedule of Contractual Obligations

 

The following table details the undiscounted future projected payments associated with the Company’s contractual obligations as of December 31, 2008.

 

 

 

Total

 

2009

 

2010-2011

 

2012-2013

 

2014+

 

 

 

(Thousands)

 

Purchase obligations

 

$

1,973,032

 

$

128,822

 

$

126,076

 

$

277,235

 

$

1,440,899

 

Long-term debt

 

1,253,500

 

4,300

 

6,000

 

210,000

 

1,033,200

 

Interest payments

 

709,328

 

76,709

 

152,860

 

139,657

 

340,102

 

Operating leases

 

186,630

 

32,468

 

46,753

 

16,960

 

90,449

 

Pension and other post-retirement benefits

 

107,339

 

14,850

 

23,142

 

21,737

 

47,610

 

Other liabilities

 

19,354

 

 

19,354

 

 

 

Total contractual obligations

 

$

4,249,183

 

$

257,149

 

$

374,185

 

$

665,589

 

$

2,952,260

 

 

Purchase obligations primarily are for commitments for demand charges under existing long-term contracts with pipeline suppliers as well as under binding precedent agreements. Approximately $19.4 million of these obligations each year are believed to be recoverable in customer rates.

 

Operating leases are primarily entered into for various office locations and warehouse buildings, as well as dedicated drilling rigs in support of the Company’s drilling program. In 2008, the Company entered into an agreement with Liberty Avenue Holdings, LLC to provide office space for the Company’s new corporate headquarters. The obligations for the Company’s various office locations and warehouse buildings totaled approximately $132.8 million as of December 31, 2008. The Company has agreements with Highlands Drilling, LLC (Highlands) and Patterson UTI Drilling Company, LLC (Patterson) for Highlands and Patterson to provide drilling equipment and services to the Company. These obligations totaled approximately $53.8 million as of December 31, 2008.

 

The other liabilities line represents commitments for total estimated payouts for the 2007 Supply Long-Term Incentive Program and the 2008 Executive Performance Incentive Program. See section titled “Critical Accounting Policies Involving Significant Estimates” and Note 17 to the Consolidated Financial Statements for further discussion regarding factors that affect the ultimate amount of the payout of these obligations. The Company adopted the 2009 Shareholder Value Plan in December 2008 and the Company may adopt other plans in the future. The contractual obligations do not include any payments under the 2009 Shareholder Value Plan or any potential future plans.

 

As discussed in Note 7 to the Consolidated Financial Statements, the Company had a total FIN 48 liability for unrecognized tax benefits at December 31, 2008 of $47.6 million. The Company is currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities; therefore, this amount has been excluded from the schedule of contractual obligations presented above.

 

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Contingent Liabilities and Commitments

 

Several West Virginia lessors claimed in a suit filed on July 31, 2006 that Equitable Production Company had underpaid royalties on gas produced and marketed from leases. The suit sought compensatory and punitive damages, an accounting, and other relief. The plaintiffs later amended their complaint to name Equitable Resources, Inc. as an additional defendant. While the Company believes that it paid the proper royalty, it established a reserve to cover any potential liability. The Company has settled the litigation. The settlement covers all of the Company’s lessors in West Virginia and is subject to court approval. The Company believes the reserve established for royalty matters is sufficient.

 

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 pending litigation, which it believes are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company.

 

See Note 20 to the Consolidated Financial Statements for further discussion of the Company’s contingent liabilities and commitments.

 

Critical Accounting Policies Involving Significant Estimates

 

The Company’s significant accounting policies are described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Form 10-K. The discussion and analysis of the Consolidated Financial Statements and results of operations are based upon EQT’s Consolidated Financial Statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these Consolidated Financial Statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the related disclosure of contingent assets and liabilities. The following critical accounting policies, which were reviewed and approved by the Company’s Audit Committee, relate to the Company’s more significant judgments and estimates used in the preparation of its Consolidated Financial Statements. There can be no assurance that actual results will not differ from those estimates.

 

Accounting for Oil and Gas Producing Activities:  The Company uses the successful efforts method of accounting for its oil and gas production activities. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the property has proved reserves. If an exploratory well does not result in proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows pursuant to SFAS No. 19. The costs of development wells are capitalized whether productive or nonproductive. Depletion is calculated based on the annual actual production multiplied by the depletion rate per unit. The depletion rate is derived by dividing the total costs capitalized over the number of units expected to be produced over the life of the reserves.

 

The carrying values of the Company’s proved oil and gas properties are reviewed for indications of impairment whenever events or circumstances indicate that the remaining carrying value may not be recoverable. In order to determine whether impairment has occurred, the Company estimates the expected future cash flows (on an undiscounted basis) from its proved oil and gas properties and compares those future cash flows to the carrying values of the applicable properties. The estimated future cash flows used to test properties for recoverability are based on proved reserves, utilizing assumptions about the use of the asset, market prices for oil and gas and future operating costs. Proved oil and gas properties that have carrying amounts in excess of estimated future cash flows would be deemed unrecoverable. Those properties would be written down to fair value, which would be estimated by discounting the estimated future cash flows using discount rate assumptions that marketplace participants would use in their estimates of fair value.

 

Capitalized costs of unproved properties are evaluated at least annually for recoverability on an aggregated prospect basis. Indicators of potential impairment include changes brought about by economic factors, potential

 

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shifts in business strategy employed by management and historical experience. If it is determined that the properties will not yield proved reserves, the related costs are expensed in the period in which that determination is made. Unproved properties had a net book value of $83.5 million in 2008. There were no significant unproved properties balances at December 31, 2007 or 2006.

 

The Company believes that the accounting estimate related to the accounting for oil and gas producing activities is a “critical accounting estimate” because the Company must assess the remaining recoverable proved reserves, a process which can be significantly impacted by assumed market prices for oil and gas. Should the Company begin to develop new producing regions or begin more significant exploration activities, future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions.

 

Oil and Gas Reserves:  Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are the estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate, with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made).

 

The Company’s estimates of proved reserves are made and reassessed annually using geological and reservoir data as well as production performance data. Reserve estimates are prepared and updated by the Company’s engineers and reviewed by the Company’s independent engineers. Revisions may result from changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits sooner. A material change in the estimated volumes of reserves could have an impact on the depletion rate calculation and the financial statements.

 

The Company estimates future net cash flows from natural gas and oil reserves based on selling prices and costs at year-end price levels. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Income tax expense is computed using expected future tax rates and giving effect to tax deductions and credits available under current laws and which relate to oil and gas producing activities.

 

The Company believes that the accounting estimate related to oil and gas reserves is a “critical accounting estimate” because the Company must periodically reevaluate proved reserves along with estimates of future production and the estimated timing of development expenditures. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions.

 

Income Taxes:  The Company accounts for income taxes under the provisions of SFAS No. 109, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the Company’s Consolidated Financial Statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. See Note 7 to the Company’s Consolidated Financial Statements for further discussion.

 

The Company has recorded deferred tax assets principally resulting from mark-to-market hedging losses recorded in other comprehensive loss, deferred revenues and expenses, federal and state net operating loss carryforwards, and an alternative minimum tax credit carryforward. The Company has established a valuation allowance against a portion of the deferred tax assets related to the state net operating loss carryforwards, as it is believed that it is more likely than not that these deferred tax assets will not all be realized. The Company also recorded a $0.2 million charge in 2008 and $0.1 million charge in 2007 and 2006 related to compensation deferred and accrued under certain compensation plans, as it was determined that this compensation will not be deductible under Section 162(m) of the IRC. No other valuation allowances have been established, as it is believed that future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize these deferred tax assets. Any change in the valuation allowance would impact the Company’s income tax expense and net income in the period in which such a determination is made.

 

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The Company accounts for uncertainty in income taxes under the provisions of FIN 48.  This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.  The recognition threshold requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit.  If the first step is satisfied, then the Company must measure the tax position.  The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.  See Note 7 to the Company’s Consolidated Financial Statements for further discussion.

 

The Company believes that accounting estimates related to income taxes are “critical accounting estimates” because the Company must assess the likelihood that deferred tax assets will be recovered from future taxable income and provide judgment on the amount of financial statement benefit that an uncertain tax position will realize upon ultimate settlement. To the extent the Company believes it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, a valuation allowance must be established. Significant management judgment is required in determining any valuation allowance recorded against deferred tax assets and in determining the amount of financial statement benefit to record for uncertain tax positions. The Company considers all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed and considers the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit. Evidence used for the valuation allowance includes information about the Company’s current financial position and results of operations for the current and preceding years, as well as all currently available information about future years, including the Company’s anticipated future performance, the reversal of deferred tax assets and liabilities and tax planning strategies available to the Company. To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, the Company must include an expense or benefit within tax expense in the income statement.

 

Derivative Commodity Instruments:  The Company enters into derivative commodity instrument contracts to mitigate exposure to commodity price risk associated with future natural gas production. Under SFAS No. 133, derivative instruments are required to be recorded on the balance sheet as either an asset or a liability measured at fair value. If the derivative qualifies for cash flow hedge accounting, the change in fair value of the derivative is recognized in accumulated other comprehensive income (equity) to the extent that the hedge is effective and in the income statement to the extent it is ineffective. If the derivative does not qualify as a hedge or is not designated as a hedge under SFAS No. 133, the change in fair value of the derivative is recognized currently in earnings. See “Commodity Risk Management” above and Item 7A—“Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding hedging activities.

 

The Company estimates the fair value of all derivative instruments using quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk. Nonperformance risk considers the effect of the Company’s credit standing on the fair value of liabilities and the effect of the counterparty’s credit standing on the fair value of assets. The Company estimates nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to the Company’s or counterparty’s credit rating and the yield of a risk free instrument and credit default swap rates where available. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control.

 

A substantial majority of the Company’s derivative financial instruments are designated as cash flow hedges. Should these instruments fail to meet the criteria for hedge accounting or be de-designated, the subsequent changes in fair value of the instruments would be recorded in earnings, which could materially impact the results of operations. One of the requirements for hedge accounting is that a derivative instrument be highly effective at offsetting the changes in cash flows of the transaction being hedged. Effectiveness is impacted by counterparty credit rating as it must be probable that the counterparty will perform in order for the hedge to be effective. The

 

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Company monitors counterparty credit quality by reviewing counterparty credit spreads, credit ratings, credit default swap rates and market activity.

 

In addition, the derivative commodity instruments used to mitigate exposure to commodity price risk associated with future natural gas production may limit the benefit the Company would receive from increases in the prices for oil and natural gas and may expose the Company to margin requirements. Given the Company’s price risk management position and price volatility, the Company may be required from time to time to deposit cash with or provide letters of credit to its counterparties in order to satisfy these margin requirements.

 

The Company believes that the accounting estimates related to derivative commodity instruments are “critical accounting estimates” because the Company’s financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments due to the volatility of natural gas prices, changes in the effectiveness of cash flow hedge’s due to changes in estimates of non-performance risk, and by changes in margin requirements. As of December 31, 2008 and 2007 the net market value of our derivatives was an asset of $16.3 million and a liability of $479.5 million, respectively.

 

Contingencies and Asset Retirement Obligations:  The Company is involved in various regulatory and legal proceedings that arise in the ordinary course of business. The Company records a liability for contingencies based upon its assessment that a loss is probable and the amount of the loss can be reasonably estimated. The recording of contingencies is guided by the principles of SFAS No. 5. The Company considers many factors in making these assessments, including history and specifics of each matter. Estimates are developed in consultation with legal counsel and are based upon an analysis of potential results.

 

In addition to the obligation to record contingent liabilities, SFAS No. 143 requires that the Company accrue a liability for legal asset retirement obligations based on an estimate of the timing and amount of their settlement. For oil and gas wells, the fair value of the Company’s plugging and abandonment obligations is required to be recorded at the time the obligations are incurred, which is typically at the time the wells are drilled. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to depreciation, depletion, and amortization, and the initial capitalized costs are depleted over the useful lives of the related assets.

 

The Company is required to operate and maintain its natural gas pipeline and storage systems, and intends to do so as long as supply and demand for natural gas exists, which the Company expects for the foreseeable future. Therefore, the Company believes that the substantial majority of its natural gas pipeline and storage system assets have indeterminate lives.

 

The Company believes that the accounting estimates related to contingencies and asset retirement obligations are “critical accounting estimates” because the Company must assess the probability of loss related to contingencies and the expected amount and timing of asset retirement obligations. In addition, the Company must determine the estimated present value of future liabilities. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions.

 

Share Based Compensation: The Company awards share-based compensation in connection with specific programs established under the 1999 Long-Term Incentive Plan. The Company accounts for all of its share-based payment awards in accordance with SFAS No. 123R. The Company treats its Executive Performance Incentive Programs, including the 2008 Executive Performance Incentive Program (2008 EPIP) and the 2007 Supply Long-Term Incentive Program (2007 Supply Program) as liability awards. The actual cost to be recorded for these plans will not be known until the measurement date, requiring the Company to estimate the total expense to be recognized at each reporting date. The Company reviews the assumptions for both programs on a quarterly basis and adjusts its accrual when changes in these assumptions result in a material change in the fair value of the ultimate payouts.

 

Approximately 70,000 units were granted under the 2008 EPIP. The payout of this program will be between zero and three times this number of units valued at the price of the Company’s common stock at the end of the performance period, December 31, 2011. The payout multiple is dependent upon the level of total shareholder return relative to a predefined peer group’s total shareholder return and the downward discretion of the Compensation

 

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Committee of the Board of Directors. The Company granted approximately 165,000 awards under the 2007 Supply Program. The awards earned may be increased to a maximum of three times the initial award or reduced to zero based upon achievement of the predetermined production sales revenue targets. The performance period for the 2007 Supply Program ends on December 31, 2010.

 

Assuming no change in the current payout multiple assumptions for both programs, a 10% increase in the Company’s stock price assumptions for the 2008 EPIP plan and the 2007 Supply Program would result in an increase in 2009 compensation expense under these plans of approximately $0.7 million.

 

The Compensation Committee of the Board of Directors adopted the 2009 Shareholder Value Plan (2009 SVP) in December 2008. A total of 977,600 units were granted under the plan. The payout of this award will depend on a combination of the level of total shareholder return relative to a predefined peer group and the Company’s average absolute return on total capital during the performance period of January 1, 2005 to December 31, 2009. Payout of awards will be between zero and 250% the number of units awarded at the price of the Company’s common stock at the end of the performance period, December 31, 2009. Assuming a payout multiple of 175% and a 10% increase in the Company’s year-end stock price, the 2009 SVP plan would result in compensation expense of approximately $7.7 million in 2009.

 

The 1999 Long-Term Incentive Plan permits the grant of restricted stock awards and non-qualified stock options to employees of the Company. For time restricted stock awards, compensation expense, which is based on the grant date fair value, is recognized in the Company’s financial statements over the vesting period. The majority of the time-based restricted shares granted will vest at the end of the three-year period commencing with the date of grant. For non-qualified stock options, compensation expense is based on the grant date fair value and is recognized in the Company’s financial statements over the vesting period. The Company utilizes the Black-Scholes option pricing model to measure the fair value of stock options, which includes assumptions for a risk-free interest rate, dividend yield, volatility factor and expected term. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The dividend yield is based on the historical dividend yield of the Company’s stock. Expected volatilities are based on historical volatility of the Company’s stock. The expected term of options granted represents the period of time that options granted are expected to be outstanding based on historical option exercise experience.

 

The Company believes that the accounting estimates related to share-based compensation are “critical accounting estimates” because they are likely to change from period to period based on changes in the market price of the Company’s shares and the various performance factors. The impact on net income of these changes can be material and management’s assumptions regarding these performance factors require significant judgment.

 

Item 7A.            Quantitative and Qualitative Disclosures About Market Risk

 

Derivative Commodity Instruments

 

The Company’s primary market risk exposure is the volatility of future prices for natural gas and natural gas liquids, which can affect the operating results of the Company primarily through the EQT Production and EQT Midstream segments. The Company’s use of derivatives to reduce the effect of this volatility is described in Notes 1 and 3 to the Consolidated Financial Statements and under the caption “Commodity Risk Management” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (Item 7) of this Form 10-K. The Company uses non-leveraged derivative commodity instruments that are placed with major financial institutions whose creditworthiness is continually monitored. The Company also enters into energy trading contracts to leverage its assets and limit its exposure to shifts in market prices. The Company’s use of these derivative financial instruments is implemented under a set of policies approved by the Company’s Corporate Risk Committee and Board of Directors.

 

Commodity Price Risk

 

The following sensitivity analysis estimates the potential effect on fair value or future earnings from derivative commodity instruments due to a 10% increase and a 10% decrease in commodity prices.

 

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For the derivative commodity instruments used to hedge the Company’s forecasted production, the Company sets policy limits relative to the expected production and sales levels, which are exposed to price risk. For the derivative commodity instruments used to hedge forecasted natural gas purchases and sales, which are exposed to price risk, the Company sets limits related to acceptable exposure levels. The Company holds an immaterial amount of derivative commodity instruments for trading purposes.

 

The financial instruments currently utilized by the Company include futures contracts, swap agreements and collar agreements, which may require payments to or receipt of payments from counterparties based on the differential between a fixed and variable price for the commodity. The Company also considers options and other contractual agreements in determining its commodity hedging strategy.

 

Management monitors price and production levels on a continuous basis and will make adjustments to quantities hedged as warranted.  Due to the significant well development and infrastructure investment at EQT Production and EQT Midstream, the Company’s overall objective in its hedging program has been to ensure an adequate level of return for these investments. To the extent that the Company has hedged its production at prices below the current market price, the Company is unable to benefit fully from increases in the price of natural gas.

 

With respect to the derivative commodity instruments held by the Company for purposes other than trading as of December 31, 2008, the Company hedged portions of expected equity production through 2015 and portions of forecasted purchases and sales by utilizing futures contracts, swap agreements and collar agreements covering approximately 210.4 Bcf of natural gas. See the “Commodity Risk Management” in the “Capital Resources and Liquidity” sections of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (Item 7) of this Form 10-K for further discussion. A hypothetical decrease of 10% in the market price of natural gas from the December 31, 2008 levels would increase the fair value of non-trading natural gas derivative instruments by approximately $54.9 million. A hypothetical increase of 10% in the market price of natural gas from the December 31, 2008 levels would decrease the fair value of non-trading natural gas derivative instruments by approximately $52.4 million.

 

The Company determined the change in the fair value of the derivative commodity instruments using a model similar to its normal change in fair value as described in Note 1 to the Consolidated Financial Statements. The Company assumed a 10% change in the price of natural gas from its levels at December 31, 2008. The price change was then applied to the derivative commodity instruments recorded on the Company’s balance sheet, resulting in the change in fair value.

 

The above analysis of the derivative commodity instruments held by the Company for purposes other than trading does not include the offsetting impact that the same hypothetical price movement may have on the Company and its subsidiaries’ physical sales of natural gas. The portfolio of derivative commodity instruments held for risk management purposes approximates the notional quantity of a portion of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the derivative commodity instrument portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held for risk management purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions, assuming the derivative commodity instruments are not closed out in advance of their expected term, the derivative commodity instruments continue to function effectively as hedges of the underlying risk and the anticipated transactions occur as expected.

 

If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur, or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.

 

Other Market Risks

 

The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. The Company believes that NYMEX-traded futures contracts have minimal credit risk because the Commodity Futures Trading

 

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Commission regulations are in place to protect exchange participants, including the Company, from any potential financial instability of the exchange members. The Company manages the credit risk of the other derivative contracts by limiting dealings to those counterparties who meet the Company’s criteria for credit and liquidity strength and continually monitoring counterparty risk factors.

 

The Company utilizes various information technology systems to monitor and evaluate its credit risk exposures. This includes closely monitoring current market conditions, counterparty credit spreads and credit default swap rates. Credit exposure is controlled through credit approvals and limits. To manage the level of credit risk, the Company enters transactions with financial counterparties that are of investment grade, enters into netting agreements whenever possible and may obtain collateral or other security.

 

Approximately 52%, or $154.4 million, of OTC derivative contracts outstanding at December 31, 2008 have a positive fair value. All derivative contracts outstanding as of December 31, 2008 are with counterparties having an S&P rating of A- or above at that date.

 

In September 2008, the credit support provider of one counterparty (Lehman Brothers) declared bankruptcy resulting in a default under various derivative contracts with the Company. As a result, those contracts were terminated and a reserve of $5.2 million was recorded against the entire balance due to the Company. There is no additional income statement exposure to Lehman Brothers beyond the reserve recorded this year. As of December 31, 2008, the Company is not in default under any derivative contracts and has no knowledge of default by any other counterparty to derivative contracts. The Company will continue to monitor market conditions that may impact the fair value of derivative contracts reported in the Condensed Consolidated Balance Sheet.

 

The Company is also exposed to the risk of nonperformance by credit customers on physical sales of natural gas. A significant amount of revenues and related accounts receivable from EQT Production are generated from the sale of produced natural gas to certain marketers, including the Company’s wholly owned marketing subsidiary Equitable Energy, and utility and industrial customers located mainly in the Appalachian area. Additionally, a significant amount of revenues and related accounts receivable at EQT Midstream are generated from the sale of produced natural gas liquids to a gas processor in Kentucky and gathering of natural gas in Kentucky, Virginia, Pennsylvania and West Virginia.

 

The Company has a $1.5 billion revolving credit facility that matures on October 26, 2011. The credit facility is underwritten by a syndicate of 15 financial institutions each of which is obligated to fund its pro-rata portion of any borrowings by the Company. Lehman is one of the 15 financial institutions in the syndicate and has committed to make loans not exceeding $95 million under the facility. Lehman failed to fund its portion of all recent borrowings by the Company which effectively reduces the total amount available under the facility to $1,405 million. As of December 31, 2008, the Company has outstanding under the facility $319.9 million of loans in support of corporate activities and a $25.8 million irrevocable standby letter of credit.

 

No one lender in the syndicate holds more than 10% of the facility. The Company’s large syndicate group and relatively low percentage of participation by each lender is expected to otherwise limit the Company’s exposure if further problems or consolidation occur in the banking industry.

 

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Item 8.                     Financial Statements and Supplementary Data

 

 

 

Page Reference

 

 

 

Reports of Independent Registered Public Accounting Firm

 

56

 

 

 

Statements of Consolidated Income for each of the three years in the period ended December 31, 2008

 

58

 

 

 

Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2008

 

59

 

 

 

Consolidated Balance Sheets as of December 31, 2008 and 2007

 

60

 

 

 

Statements of Common Stockholders’ Equity for each of the three years in the period ended December 31, 2008

 

62

 

 

 

Notes to Consolidated Financial Statements

 

63

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

The Board of Directors and Shareholders

EQT Corporation

 

We have audited the accompanying consolidated balance sheets of EQT Corporation and Subsidiaries (formerly Equitable Resources, Inc.) as of December 31, 2008 and 2007, and the related consolidated statements of income, common stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of EQT Corporation and Subsidiaries (formerly Equitable Resources, Inc.) at December 31, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

 

In 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Post-Retirement Plans. In 2007, the Company adopted the provisions of FASB Interpretation No. 48 Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No.109.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of EQT Corporation and Subsidiaries’ (formerly Equitable Resources, Inc.) internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 17, 2009, expressed an unqualified opinion thereon.

 

 

 

 

Pittsburgh, Pennsylvania

February 17, 2009

 

56



Table of Contents

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

The Board of Directors and Shareholders

EQT Corporation

 

We have audited EQT Corporation and Subsidiaries’ (formerly Equitable Resources, Inc.) internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). EQT Corporation and Subsidiaries’ (formerly Equitable Resources, Inc.) management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

In our opinion, EQT Corporation and Subsidiaries (formerly Equitable Resources, Inc.) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of EQT Corporation and Subsidiaries (formerly Equitable Resources, Inc.) as of December 31, 2008 and 2007, and the related consolidated statements of income, common shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2008 and our report dated February 17, 2009 expressed an unqualified opinion thereon.

 

 

 

Pittsburgh, Pennsylvania

February 17, 2009

 

57



Table of Contents

 

EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME

YEARS ENDED DECEMBER 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands except per share amounts)

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

1,576,488

 

$

1,361,406

 

$

1,267,910

 

Cost of sales

 

645,136

 

574,466

 

504,329

 

Net operating revenues (see Note 1)

 

931,352

 

786,940

 

763,581

 

Operating expenses:

 

 

 

 

 

 

 

Operation and maintenance

 

129,502

 

106,965

 

104,620

 

Production

 

80,068

 

62,273

 

62,471

 

Exploration

 

9,064

 

862

 

802

 

Selling, general and administrative

 

111,096

 

195,365

 

125,951

 

Office consolidation impairment charges

 

 

 

(2,908

)

Depreciation, depletion and amortization

 

136,816

 

109,802

 

100,122

 

Total operating expenses (see Note 1)

 

466,546

 

475,267

 

391,058

 

Operating income

 

464,806

 

311,673

 

372,523

 

Other than temporary impairment of available-for-sale securities

 

(7,835

)

 

 

Gain on sale of assets, net

 

 

126,088

 

 

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

 

 

1,042

 

 

Other income

 

6,233

 

7,645

 

1,442

 

Equity in earnings of nonconsolidated investments

 

5,714

 

3,099

 

260

 

Interest expense

 

58,394

 

47,669

 

48,494

 

Income from continuing operations before income taxes

 

410,524

 

401,878

 

325,731

 

Income taxes

 

154,920

 

144,395

 

109,706

 

Income from continuing operations

 

255,604

 

257,483

 

216,025

 

Income from discontinued operations, net of tax benefit of $3,246 for the year ended December 31, 2006

 

 

 

4,261

 

Net income

 

$

255,604

 

$

257,483

 

$

220,286

 

Earnings per share of common stock:

 

 

 

 

 

 

 

Basic:

 

 

 

 

 

 

 

Income from continuing operations

 

$

2.01

 

$

2.12

 

$

1.79

 

Income from discontinued operations

 

 

 

0.04

 

Net income

 

$

2.01

 

$

2.12

 

$

1.83

 

Diluted:

 

 

 

 

 

 

 

Income from continuing operations

 

$

2.00

 

$

2.10

 

$

1.77

 

Income from discontinued operations

 

 

 

0.03

 

Net income

 

$

2.00

 

$

2.10

 

$

1.80

 

 

See notes to consolidated financial statements.

 

58



Table of Contents

 

EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

YEARS ENDED DECEMBER 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income

 

$

255,604

 

$

257,483

 

$

220,286

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

 

 

Income from discontinued operations, net of tax

 

 

 

(4,261

)

Provision for losses on accounts receivable

 

11,744

 

353

 

4,715

 

Depreciation, depletion and amortization

 

136,816

 

109,802

 

100,122

 

Other than temporary impairment of available-for-sale securities

 

7,835

 

 

 

Gain on sale of assets, net

 

 

(126,088

)

 

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

 

 

(1,042

)

 

Other income

 

(6,233

)

(7,645

)

(1,442

)

Equity in earnings of nonconsolidated investments

 

(5,714

)

(3,099

)

(260

)

Deferred income taxes

 

245,801

 

33,020

 

32,325

 

Excess tax benefits from share-based payment arrangements

 

(946

)

(15,687

)

(15,739

)

Office consolidation impairment charges

 

 

 

(2,908

)

Changes in other assets and liabilities:

 

 

 

 

 

 

 

Accounts receivable and unbilled revenues

 

(33,377

)

2,455

 

63,527

 

Margin deposits

 

1,496

 

(5,919

)

317,821

 

Inventory

 

(4,697

)

(14,357

)

20,793

 

Prepaid expenses and other

 

(100,532

)

39,155

 

(27,135

)

Regulatory assets

 

(6

)

6,120

 

576

 

Accounts payable

 

77,475

 

65,931

 

(29,292

)

Derivative instruments, at fair value

 

(82,564

)

10,863

 

(53,846

)

Deferred income taxes

 

 

 

33,375

 

Pension and other post-retirement benefits

 

5,673

 

(9,179

)

(1,751

)

Other current liabilities

 

(58,326

)

99,357

 

(31,878

)

Other items, net

 

59,108

 

(14,803

)

(7,182

)

Net cash provided by operating activities

 

509,157

 

426,720

 

617,846

 

 

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Capital expenditures

 

(1,343,996

)

(776,667

)

(403,094

)

Capital contributions to Nora Gathering, LLC

 

(29,000

)

 

 

Purchase of working interest

 

 

(28,092

)

 

Proceeds from sale of assets

 

 

193,451

 

 

Proceeds from contribution of assets

 

 

23,584

 

 

Proceeds from sale of available-for-sale securities

 

 

7,295

 

 

Investment in available-for-sale securities

 

(3,000

)

(9,709

)

(2,471

)

Net cash used in continuing investing activities

 

(1,375,996

)

(590,138

)

(405,565

)

Net cash used in discontinued investing activities

 

 

 

(724

)

Net cash used in investing activities

 

(1,375,996

)

(590,138

)

(406,289

)

 

 

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

 

 

Dividends paid

 

(111,403

)

(107,086

)

(104,871

)

Proceeds from issuance of common stock

 

560,739

 

 

 

Proceeds from issuance of long-term debt

 

500,000

 

 

 

Debt issuance costs

 

(6,645

)

 

 

(Decrease) increase in short-term loans

 

(130,083

)

314,001

 

(229,301

)

Repayments and retirements of long-term debt

 

 

(10,000

)

(3,000

)

Proceeds from note payable to Nora Gathering, LLC

 

 

69,786

 

 

Repayments of note payable to Nora Gathering, LLC

 

(29,329

)

(40,457

)

 

Proceeds from exercises under employee compensation plans

 

903

 

3,198

 

34,910

 

Excess tax benefits from share-based payment arrangements

 

946

 

15,687

 

15,739

 

Net cash provided by (used in) financing activities

 

785,128

 

245,129

 

(286,523

)

Net (decrease) increase in cash and cash equivalents

 

(81,711

)

81,711

 

(74,966

)

Cash and cash equivalents at beginning of year

 

81,711

 

 

74,966

 

Cash and cash equivalents at end of year

 

$

 

$

81,711

 

$

 

 

 

 

 

 

 

 

 

Cash paid (received) during the year for:

 

 

 

 

 

 

 

Interest, net of amount capitalized

 

$

51,234

 

$

48,464

 

$

48,702

 

Net income taxes (received) paid

 

$

(13,963

)

$

63,384

 

$

58,631

 

 

See notes to consolidated financial statements.

 

59



Table of Contents

 

EQT CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

 

 

 

2008

 

2007

 

 

 

(Thousands)

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

 

$

81,711

 

Accounts receivable (less accumulated provision for doubtful accounts: 2008, $26,636; 2007, $19,829)

 

209,008

 

188,561

 

Unbilled revenues

 

49,930

 

48,744

 

Margin deposits with financial institutions

 

4,434

 

5,930

 

Inventory

 

288,182

 

283,485

 

Derivative instruments, at fair value

 

192,191

 

37,143

 

Prepaid expenses and other

 

183,437

 

96,673

 

Total current assets

 

927,182

 

742,247

 

 

 

 

 

 

 

Equity in nonconsolidated investments

 

169,241

 

135,366

 

 

 

 

 

 

 

Property, plant and equipment

 

5,503,921

 

4,207,402

 

Less: accumulated depreciation and depletion

 

1,406,402

 

1,287,911

 

Net property, plant and equipment

 

4,097,519

 

2,919,491

 

 

 

 

 

 

 

Investments, available-for-sale

 

25,880

 

35,675

 

Regulatory assets

 

83,525

 

78,015

 

Other

 

26,315

 

26,177

 

Total assets

 

$

5,329,662

 

$

3,936,971

 

 

See notes to consolidated financial statements.

 

60



Table of Contents

 

EQT CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

 

 

 

2008

 

2007

 

 

 

(Thousands)

 

 

 

 

 

 

 

Liabilities and Common Stockholders’ Equity

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Current portion of long-term debt

 

$

4,300

 

$

 

Short-term loans

 

319,917

 

450,000

 

Note payable to Nora Gathering, LLC

 

 

29,329

 

Accounts payable

 

356,732

 

279,257

 

Derivative instruments, at fair value

 

175,889

 

516,626

 

Other current liabilities

 

185,770

 

244,096

 

Total current liabilities

 

1,042,608

 

1,519,308

 

 

 

 

 

 

 

Long-term debt

 

1,249,200

 

753,500

 

Deferred income taxes and investment tax credits

 

781,520

 

400,465

 

Unrecognized tax benefits

 

47,553

 

50,845

 

Pension and other post-retirement benefits

 

69,409

 

41,768

 

Other credits

 

89,279

 

73,613

 

Total liabilities

 

3,279,569

 

2,839,499

 

Common stockholders’ equity:

 

 

 

 

 

Common stock, no par value, authorized 320,000 shares; shares issued: 2008, 157,630 and 2007, 149,008

 

948,497

 

382,191

 

Treasury stock, shares at cost: 2008, 26,764, 2007, 26,853; (net of shares and cost held in trust for deferred compensation of 163, $2,784 and 180, $3,085)

 

(483,464

)

(485,051

)

Retained earnings

 

1,653,797

 

1,509,596

 

Accumulated other comprehensive loss

 

(68,737

)

(309,264

)

Total common stockholders’ equity

 

2,050,093

 

1,097,472

 

Total liabilities and common stockholders’ equity

 

$

5,329,662

 

$

3,936,971

 

 

See notes to consolidated financial statements.

 

61



Table of Contents

 

EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF COMMON STOCKHODLDERS’ EQUITY

YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

 

 

 

Common Stock

 

 

 

Accumulated
Other

 

Common

 

 

 

Shares
Outstanding

 

No
Par Value

 

Retained
Earnings

 

Comprehensive
(Loss) Income

 

Stockholders’
Equity

 

 

 

(Thousands)

 

Balance, December 31, 2005

 

119,906

 

$

(137,827

)

$

1,247,895

 

$

(755,600

)

$

354,468

 

Comprehensive income (net of tax):

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

220,286

 

 

 

220,286

 

Net change in cash flow hedges:

 

 

 

 

 

 

 

 

 

 

 

Natural gas, net of tax of $272,066 (see Note 3)

 

 

 

 

 

 

 

454,817

 

454,817

 

Interest rate

 

 

 

 

 

 

 

116

 

116

 

Unrealized gain on available-for-sale securities

 

 

 

 

 

 

 

2,399

 

2,399

 

Pension and other post-retirement benefits liability adjustment prior to the adoption of SFAS No. 158, net of tax benefit of $730

 

 

 

 

 

 

 

(1,024

)

(1,024

)

Total comprehensive income

 

 

 

 

 

 

 

 

 

676,594

 

Pension and other post-retirement benefits liability adjustment due to the adoption of SFAS No. 158, net of tax benefit of $9,988

 

 

 

 

 

 

 

(15,010

)

(15,010

)

Dividends ($0.87 per share)

 

 

 

 

 

(104,871

)

 

 

(104,871

)

Stock-based compensation plans, net

 

1,697

 

35,099

 

 

 

 

 

35,099

 

Balance, December 31, 2006

 

121,603

 

$

(102,728

)

$

1,363,310

 

$

(314,302

)

$

946,280

 

Comprehensive income (net of tax):

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

257,483

 

 

 

257,483

 

Net change in cash flow hedges:

 

 

 

 

 

 

 

 

 

 

 

Natural gas, net of tax of $370 (see Note 3)

 

 

 

 

 

 

 

(20

)

(20

)

Interest rate

 

 

 

 

 

 

 

115

 

115

 

Unrealized loss on available-for-sale securities

 

 

 

 

 

 

 

(97

)

(97

)

Pension and other post-retirement benefits liability adjustment, net of tax benefit of $3,700

 

 

 

 

 

 

 

5,040

 

5,040

 

Total comprehensive income

 

 

 

 

 

 

 

 

 

262,521

 

Liability adjustment due to the adoption of FIN 48

 

 

 

 

 

(4,111

)

 

 

(4,111

)

Dividends ($0.88 per share)

 

 

 

 

 

(107,086

)

 

 

(107,086

)

Stock-based compensation plans, net

 

549

 

(132

)

 

 

 

 

(132

)

Balance, December 31, 2007

 

122,152

 

$

(102,860

)

$

1,509,596

 

$

(309,264

)

$

1,097,472

 

Comprehensive income (net of tax):

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

255,604

 

 

 

255,604

 

Net change in cash flow hedges:

 

 

 

 

 

 

 

 

 

 

 

Natural gas, net of tax of $150,934 (see Note 3)

 

 

 

 

 

 

 

249,620

 

249,620

 

Interest rate

 

 

 

 

 

 

 

115

 

115

 

Unrealized loss on available-for-sale securities

 

 

 

 

 

 

 

(3,872

)

(3,872

)

Pension and other post-retirement benefits liability adjustment, net of tax benefit of $8,697

 

 

 

 

 

 

 

(13,158

)

(13,158

)

Total comprehensive income

 

 

 

 

 

 

 

 

 

488,309

 

Adoption of SFAS No. 157, net of tax of $4,744

 

 

 

 

 

 

 

7,822

 

7,822

 

Dividends ($0.88 per share)

 

 

 

 

 

(111,403

)

 

 

(111,403

)

Stock-based compensation plans, net

 

89

 

7,154

 

 

 

 

 

7,154

 

Issuance of common shares

 

8,625

 

560,739

 

 

 

 

 

560,739

 

Balance, December 31, 2008

 

130,866

 

$

465,033

 

$

1,653,797

 

$

(68,737

)

$

2,050,093

 

 

Common shares authorized: 320,000,000 shares. Preferred shares authorized: 3,000,000 shares. There are no preferred shares issued or outstanding.

 

See notes to consolidated financial statements.

 

62



Table of Contents

 

EQT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2008

 

1.                                      Summary of Significant Accounting Policies

 

Principles of Consolidation: The Consolidated Financial Statements include the accounts of EQT Corporation and all subsidiaries, ventures and partnerships in which a controlling equity interest is held (“EQT” or “the Company”). All significant intercompany accounts and transactions have been eliminated in consolidation. EQT utilizes the equity method of accounting for companies where its ownership is less than or equal to 50% and significant influence exists.

 

On June 30, 2008, the former Equitable Resources, Inc. (Old EQT) entered into and completed an Agreement and Plan of Merger (the Plan) under which Old EQT reorganized into a holding company structure such that a newly formed Pennsylvania corporation, also named Equitable Resources, Inc. (New EQT), became the publicly traded holding company of Old EQT and its subsidiaries. The primary purpose of this reorganization (the Reorganization) was to separate Old EQT’s state-regulated distribution operations into a new subsidiary in order to better segregate its regulated and unregulated businesses and improve overall financing flexibility. To effect the Reorganization, Old EQT formed New EQT, a wholly-owned subsidiary, and New EQT, in turn, formed EGC Merger Co., a Pennsylvania corporation owned solely by New EQT (MergerSub). Under the Plan, MergerSub merged with and into Old EQT with Old EQT surviving (the Merger). The Merger resulted in Old EQT becoming a direct, wholly-owned subsidiary of New EQT. New EQT changed its name to EQT Corporation effective February 9, 2009. Throughout these statements, references to EQT, EQT Corporation and the Company refer collectively to New EQT and its consolidated subsidiaries.

 

Reclassification: Certain previously reported amounts have been reclassified to conform to the current year presentation.

 

Use of Estimates:  The preparation of financial statements in conformity with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and accompanying notes. Actual results could differ from those estimates.

 

Cash Equivalents:  The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. These investments are accounted for at cost. Interest earned on cash equivalents is included as a reduction of interest expense.

 

Inventories:  Generally, the Company’s inventory balance consists of natural gas stored underground and materials and supplies recorded at the lower of average cost or market. At December 31, 2008, $36.7 million of the inventory balance relates to coated steel pipe which was purchased for use in the Company’s midstream infrastructure projects. This pipe is valued at average cost which is lower than the current market value. The Company is re-evaluating the use of this pipe inventory and expects it will either be sold or used in infrastructure projects in the next 12 months.

 

63



Table of Contents

 

EQT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

Property, Plant and Equipment: The Company’s property, plant and equipment consists of the following:

 

 

 

December 31,

 

 

 

2008

 

2007

 

 

 

(Thousands)

 

Oil and gas producing properties, successful efforts method

 

$

2,709,162

 

$

2,029,932

 

Accumulated depletion

 

692,327

 

621,881

 

Net oil and gas producing properties

 

2,016,835

 

1,408,051

 

Distribution plant

 

917,052

 

877,955

 

Accumulated depreciation and amortization

 

293,478

 

282,379

 

Net distribution plant

 

623,574

 

595,576

 

Midstream plant

 

1,749,153

 

1,201,665

 

Accumulated depreciation and amortization

 

352,896

 

319,214

 

Net midstream plant

 

1,396,257

 

882,451

 

Other properties, at cost less accumulated depreciation

 

60,853

 

33,413

 

Net property, plant and equipment

 

$

4,097,519

 

$

2,919,491

 

 

Oil and gas producing properties use the successful efforts method of accounting for production activities. Under this method, the cost of productive wells, including mineral interests, wells and related equipment, development dry holes, as well as productive acreage, are capitalized and depleted on the unit-of-production method. These capitalized costs include salaries, benefits and other internal costs directly attributable to these activities. The Company capitalized internal costs of $35.6 million, $14.4 million and $11.3 million in 2008, 2007 and 2006, respectively. Depletion expense is calculated based on the annual actual production multiplied by the depletion rate per unit. The depletion rate is derived by dividing the total costs capitalized over the number of units expected to be produced over the life of the reserves. EQT Production calculates a single depletion field including all reserves located in Kentucky, West Virginia, Virginia and Pennsylvania. Costs of exploratory dry holes, geological and geophysical, delay rentals and other property carrying costs are charged to expense. The majority of the Company’s oil and gas producing properties consist of gas producing properties which were depleted at a rate of $0.81/Mcf, $0.70/Mcf and $0.62/Mcf produced for the years ended December 31, 2008, 2007 and 2006, respectively.

 

The carrying values of the Company’s proved oil and gas properties are reviewed for indications of impairment whenever events or circumstances indicate that the remaining carrying value may not be recoverable. In order to determine whether impairment has occurred, the Company estimates the expected future cash flows (on an undiscounted basis) from its proved oil and gas properties and compares these estimates to their respective carrying values. The estimated future cash flows used to test those properties for recoverability are based on proved reserves, utilizing assumptions about the use of the asset, market prices for oil and gas and future operating costs. Proved oil and gas properties that have carrying amounts in excess of estimated future cash flows would be deemed unrecoverable. Those properties would be written down to fair value, which would be estimated by discounting the estimated future cash flows using discount rate assumptions that marketplace participants would use in their estimates of fair value. For the years ended December 31, 2008, 2007 and 2006, the Company did not recognize impairment charges on oil and gas properties.

 

Capitalized costs of unproved properties are evaluated at least annually for recoverability on an aggregated prospect basis. Indicators of potential impairment included changes brought about by economic factors, potential shifts in business strategy employed by management and historical experience. If it is determined that the properties will not yield proved reserves, the related costs are expensed in the period in which that determination is made. Unproved properties had a net book value of $83.5 million at December 31, 2008. The Company had capitalized exploratory well costs pending the determination of proved reserves at December 31, 2008 of $6.9 million. All of these costs were incurred in 2008. There were no significant unproved properties balances at December 31, 2007 or 2006. For additional information on oil and gas properties see Note 24 (unaudited).

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

Midstream property, plant and equipment is carried at cost. Depreciation is calculated using the straight-line method based on estimated service lives. Midstream property consists largely of gathering and transmission systems (25-60 year estimated service life), buildings (35 year estimated service life), office equipment (3-7 year estimated service life), vehicles (5 year estimated service life), and computer and telecommunications equipment and systems (3-7 year estimated service life).

 

Distribution property, plant and equipment, principally regulated property, is carried at cost. Depreciation is recorded using composite rates on a straight-line basis. The overall rate of depreciation for the years ended December 31, 2008, and December 31, 2007, was approximately 4% and 3% of net properties.

 

Major maintenance projects that do not increase the overall life of the related assets are expensed. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized.

 

Sales and Retirements Policies:  No gain or loss is recognized on the partial sale of oil and gas reserves from the depletion pool unless non-recognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of the proceeds. Due to the significance of the transaction, a gain was recognized on the sale and contribution of Nora assets in 2007. See Note 5.

 

Regulatory Accounting:  EQT Midstream’s regulated operations consist of interstate pipeline operations subject to regulation by the FERC and certain state-regulated gathering operations. Equitable Distribution’s rates, terms of service, and contracts with affiliates are subject to comprehensive regulation by the Pennsylvania Public Utility Commission (PA PUC) and the West Virginia Public Service Commission (WV PSC). The issuance of securities by Equitable Gas Company, the Company’s gas distribution subsidiary, is subject to regulation by the PA PUC. Equitable Distribution also provides field line service, also referred to as “farm tap” service, in Kentucky which is subject only to rate regulation by the Kentucky Public Service Commission. Accounting for the Company’s regulated operations is performed in accordance with the provisions of Statement of Financial Accounting Standard (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). The application of this accounting policy allows the Company to defer expenses and income on its Consolidated Balance Sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the Statements of Consolidated Income for a non-regulated company. The deferred regulatory assets and liabilities are then recognized in the Statements of Consolidated Income in the period in which the same amounts are reflected in rates.

 

Where permitted by regulatory authority under purchased natural gas adjustment clauses or similar tariff provisions, Equitable Distribution defers the difference between its purchased natural gas cost, less refunds, and the billing of such cost and amortizes the deferral over subsequent periods in which billings either recover or repay such amounts. Such amounts are reflected on the Company’s Consolidated Balance Sheets as other current assets or liabilities. For further information regarding regulatory assets, see Note 11.

 

When any portion of Equitable Distribution’s or EQT Midstream’s regulated operations ceases to meet the criteria for application of regulatory accounting treatment for all or part of their operations, the regulatory assets and liabilities related to those portions are eliminated from the Consolidated Balance Sheets and are included in the Statements of Consolidated Income in the period in which the discontinuance of regulatory accounting treatment occurs.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

The following table presents the total regulated net revenues and operating expenses of the Company:

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Distribution revenues

 

$

695,631

 

$

455,506

 

$

445,168

 

Midstream revenues

 

83,374

 

69,245

 

73,799

 

Total regulated revenue

 

$

779,005

 

$

524,751

 

$

518,967

 

 

 

 

 

 

 

 

 

Distribution purchased gas costs

 

$

527,057

 

$

305,706

 

$

301,833

 

Midstream purchased gas costs

 

 

 

 

Total purchased gas costs

 

$

527,057

 

$

305,706

 

$

301,833

 

 

 

 

 

 

 

 

 

Distribution net revenue

 

$

168,574

 

$

149,800

 

$

143,335

 

Midstream net revenue

 

83,374

 

69,245

 

73,799

 

Total regulated net revenue

 

$

251,948

 

$

219,045

 

$

217,134

 

 

 

 

 

 

 

 

 

Distribution operating expenses

 

$

110,512

 

$

125,729

 

$

108,528

 

Midstream operating expenses

 

53,825

 

41,156

 

39,156

 

Total regulated operating expenses

 

$

164,337

 

$

166,885

 

$

147,684

 

 

The following table presents the regulated net property, plant and equipment of the Company:

 

 

 

As of December 31,

 

 

 

 

 

2008

 

2007

 

 

 

 

 

 

 

 

 

 

 

Distribution property, plant & equipment, net

 

$

623,574

 

$

595,576

 

 

 

Midstream property, plant & equipment, net

 

489,985

 

418,351

 

 

 

Total regulated property, plant & equipment, net

 

$

1,113,559

 

$

1,013,927

 

 

 

 

Derivative Instruments:  Derivatives are held as part of a formally documented risk management program. The Company’s risk management activities are subject to the management, direction and control of the Company’s Corporate Risk Committee (CRC). The CRC reports to the Audit Committee of the Board of Directors and is comprised of the chief executive officer, the president and chief operating officer, the chief financial officer and other officers and employees.

 

The Company’s risk management program includes the consideration and, when appropriate, the use of (i) exchange-traded natural gas futures contracts and options and OTC natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and for trading purposes and (ii) interest rate swap agreements to hedge exposures to fluctuations in interest rates. At contract inception, the Company designates its derivative instruments as hedging or trading activities.

 

All derivative instruments are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), as amended. As a result, the Company recognizes all derivative instruments as either assets or liabilities at fair value. The measurement of fair value is based upon actively quoted market prices when available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based upon valuation methodologies deemed appropriate by the Company’s CRC.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

The accounting for the changes in fair value of the Company’s derivative instruments depends on the use of the derivative instruments. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income (loss), net of tax, and is subsequently reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The Company assesses the effectiveness of hedging relationships, the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, both at the inception of the hedge and on an on-going basis. If the gain (loss) for the hedging instrument is greater than the loss (gain) on the hedged item, the ineffective portion of the cash flow hedge is immediately recognized in operating revenues in the Statements of Consolidated Income.

 

If a cash flow hedge is terminated or de-designated as a hedge before the settlement date of the hedged item, the amount of accumulated other comprehensive income (loss) recorded up to that date remains accrued provided that the forecasted transaction remains probable of occurring, and going forward, the change in fair value of the derivative instrument is recorded in earnings. The derivative instruments that comprise the amount recorded in accumulated other comprehensive income (loss) are primarily instruments which are designated and qualify as cash flow hedges. During 2008, the Company entered into derivative transactions which had the effect of offsetting existing cash flow hedges, resulting in an effective reduction in the hedge position for years 2010 - 2013. The Company concurrently de-designated the original transactions. The fair value of these derivative instruments was an $18.4 million liability at December 31, 2008.  This amount will be recognized as part of the realized sales price in the Consolidated Statement of Income when the underlying physical transactions occur. The Company does not treat these derivatives as hedging instruments under SFAS No. 133. These amounts are included in the Consolidated Balance Sheet as derivative instruments, at fair value.

 

The Company reports all gains and losses on its energy trading contracts net on its Statements of Consolidated Income in accordance with EITF No. 02-3.

 

Allowance for Funds Used During Construction:  The Company capitalizes the carrying costs for the construction of certain long-term assets and amortizes the costs over the life of the related assets. The calculated allowance for funds used during construction (AFUDC) includes capitalization of the cost of financing construction of assets subject to regulation by the PA PUC, the WV PSC or the FERC, in accordance with SFAS No. 71. A computed interest cost and a designated cost of equity for financing the construction of these regulated assets are recorded in the Company’s income statement. The debt portion is calculated based on the average cost of debt and is included as a reduction of interest expense in the Statements of Consolidated Income. AFUDC interest costs were $2.1 million, $2.6 million and $0.2 million for the years ended December 31, 2008, 2007 and 2006, respectively.

 

The equity portion of AFUDC is calculated using the most recent equity rate of return approved by the applicable regulator. Equity amounts capitalized are included in other income in the Statements of Consolidated Income. The AFUDC equity amounts capitalized were $6.2 million, $7.6 million and $1.4 million for the years ended December 31, 2008, 2007 and 2006 respectively. Prior to 2007, 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 construction of the Big Sandy Pipeline, the equity portion has been reclassified to other income in the Statements of Consolidated Income for all periods presented.

 

Capitalized Interest:  Interest costs for the construction of certain long-term assets in unregulated Company businesses are capitalized and amortized over the related assets’ estimated useful lives. Interest costs during 2008, 2007 and 2006 of $14.9 million, $4.2 million and $0.4 million, respectively, were capitalized as a portion of the cost of the related long-term assets.

 

Impairment of Long-Lived Assets:  In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS No. 144), whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, the Company reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets’ undiscounted cash flows, the Company estimates an impairment loss by taking the difference between the carrying value and fair value of the assets.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

Revenue Recognition:  Revenue is recognized for production and gathering activities when deliveries of natural gas, crude oil and NGLs are made. Revenues from natural gas transportation and storage activities are recognized in the period service is provided. Sales of natural gas to distribution customers are billed on a monthly cycle basis; however, the billing cycle periods for certain customers do not necessarily coincide with accounting periods used for financial reporting purposes. The Company follows the revenue accrual method of accounting for distribution segment revenue whereby revenues applicable to gas delivered to customers but not yet billed under the cycle billing method are estimated and accrued and the related costs are charged to expense. Revenues from energy marketing activities are recognized when deliveries occur. In accordance with EITF No. 02-3, only revenues associated with energy trading activities that do not result in physical delivery of an energy commodity (i.e. are settled in cash) are recorded using mark-to-market accounting. The revenues associated with the physical delivery of an energy commodity are recognized at contract value when delivered. Revenues associated with the Company’s natural gas advance sales contracts are recognized as natural gas is gathered and delivered. The Company accounts for gas-balancing arrangements under the entitlement method. The Company uses the gross method to account for overhead cost reimbursements from joint operating partners.

 

Investments:  Investments in companies in which the Company has the ability to exert significant influence over operating and financial policies (generally 20% to 50% ownership) are accounted for using the equity method. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. These investments are classified as equity in nonconsolidated investments on the Consolidated Balance Sheets. APB No. 18 requires a company to recognize a loss in the value of an equity method investment that is other than a temporary decline. The Company analyzes its equity method investments based on its share of estimated future cash flows from the investment to determine whether the carrying amount will be recoverable.

 

Other investments in equity securities which are generally under 20% ownership and where the Company does not exert significant influence over operating and financial polices are accounted for as available-for-sale in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities (SFAS No. 115), and are classified as investments, available-for-sale on the Consolidated Balance Sheets. Available-for-sale securities are required to be carried at fair value, with any unrealized gains and losses reported on the Consolidated Balance Sheets within a separate component of equity, accumulated other comprehensive income (loss). The Company utilizes the specific identification method to determine the cost of the securities sold. In accordance with SFAS No. 115, the Company continually reviews its available-for-sale investments to determine whether a decline in fair value below the cost basis is other than temporary. If the decline in fair value is judged to be other than temporary, the cost basis of the security is written down to fair value and the amount of the write-down is included in the Statements of Consolidated Income. The Company recorded an other than temporary impairment of $7.8 million in 2008. See Note 10. No other than temporary decline in fair value was recorded in 2007 or 2006.

 

Income Taxes:  The Company files a consolidated Federal income tax return and utilizes the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable, net of amounts refunded or estimated to be refunded, for the current year and the change in deferred taxes, exclusive of amounts recorded in other comprehensive income. Any refinements to prior years’ taxes made due to subsequent information are reflected as adjustments in the current period. Separate income taxes are calculated for income from continuing operations, discontinued operations, and items charged or credited directly to stockholders’ equity.

 

Deferred income tax assets and liabilities are determined based on temporary differences between the financial reporting and tax bases of assets and liabilities in accordance with SFAS No. 109, Accounting for Income Taxes (SFAS No. 109), which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of such temporary differences. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. Where deferred tax liabilities will be passed through to customers in regulated rates, the Company establishes a corresponding regulatory asset for the increase in future revenues that will result when the temporary differences reverse.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

Investment tax credits realized in prior years were deferred and are being amortized over the estimated service lives of the related properties where required by ratemaking rules.

 

The Company accounts for uncertainty in income taxes under the provisions of FIN 48.  This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.  The recognition threshold requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit.  If it is more likely than not that a tax position will be sustained, then the Company must measure the tax position to determine the amount of benefit to recognize in financial statements.  The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income tax expense.

 

Provision for Doubtful Accounts:  Judgment is required to assess the ultimate realization of the Company’s accounts receivable, including assessing the probability of collection and the credit-worthiness of certain customers. Reserves for uncollectible accounts are recorded as part of selling, general and administrative expense on the Statements of Consolidated Income. The reserves are based on historical experience, current and expected economic trends and specific information about customer accounts. Accordingly, actual results may differ from these estimates under different assumptions or conditions.

 

Earnings Per Share (EPS):  Basic EPS is computed by dividing net income by the weighted average number of common shares outstanding during the period, without considering any dilutive items. Diluted EPS is computed by dividing net income by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Purchases of treasury shares are calculated using the average share price for the Company’s common stock during the period. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards. See Note 15.

 

Asset Retirement ObligationsSFAS No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143), requires that the Company accrue a liability for legal asset retirement obligations based on an estimate of the timing and amount of their settlement. For oil and gas wells, the fair value of the Company’s plugging and abandonment obligations is required to be recorded at the time the obligations are incurred, which is typically at the time the wells are drilled. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to depreciation, depletion, and amortization, and the initial capitalized costs are depleted over the useful lives of the related assets.

 

The Company is required to operate and maintain its natural gas pipeline and storage systems, and intends to do so as long as supply and demand for natural gas exists, which the Company expects for the foreseeable future. Therefore, the Company believes that the substantial majority of its natural gas pipeline and storage system assets have indeterminate lives.

 

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EQT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

The following table presents a reconciliation of the beginning and ending carrying amounts of the Company’s asset retirement obligations. The Company does not have any assets that are legally restricted for purposes of settling these obligations.

 

 

 

Year ended

 

 

 

December 31,
2008

 

 

 

(Thousands)

 

Asset retirement obligation as of beginning of period

 

$

51,143

 

Accretion expense

 

3,896

 

Liabilities incurred

 

1,885

 

Divestitures

 

(129

)

Liabilities settled

 

(1,645

)

Change in assumed cost of horizontal well plugging

 

(820

)

Asset retirement obligation as of end of period

 

$

54,330

 

 

Self-Insurance: The Company is self-insured for certain losses related to workers’ compensation. The Company maintains stop loss coverage with third party insurers to limit the total exposure for general liability, automobile liability, environmental liability and workers’ compensation. The recorded reserves represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are based on analyses of historical data and actuarial estimates and are not discounted. The liabilities are reviewed by management quarterly and by independent actuaries annually to ensure that they are appropriate. While the Company believes these estimates are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of claims or fluctuations in premiums, differ from estimates.

 

Recently Issued Accounting Standards:

 

Oil and Gas Reporting Requirements

 

In December 2008, the U.S. Securities and Exchange Commission (SEC) amended the oil and gas reporting requirements which exist in their current form in Regulation S-K and Regulation S-X under the Securities Act of 1933 and the Securities Exchange Act of 1934, as well as Industry Guide 2. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves by better aligning the oil and gas disclosure requirements with current practices and technology. The amendments are effective for annual reports for fiscal years ending on or after December 31, 2009. The Company is currently evaluating the impact the revised oil and gas reporting requirements will have on its consolidated financial statements.

 

Disclosures about Derivative Instruments and Hedging Activities

 

In March 2008, the Financial Accounting Standards Board (FASB) issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (SFAS No. 161). SFAS No. 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating the impact that SFAS No. 161 will have on its consolidated financial statement disclosures.

 

Employers’ Disclosures about Post-Retirement Benefit Plan Assets

 

In December 2008, the FASB issued final FSP No. FAS 132(R)-1, Employers’ Disclosures about Post-Retirement Benefit Plan Assets. The FSP contains amendments to FASB Statement No. 132(R) that are intended to enhance the transparency surrounding the types of assets and associated risks in an employer’s defined benefit pension or other post-retirement plan. The new disclosures are required to be included in the financial statements for

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

fiscal years ending after December 15, 2009. The Company is currently evaluating the impact that FSP No. FAS 132(R)-1 will have on its consolidated financial statement disclosures.

 

2.                                      Financial Information by Business Segment

 

Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and are subject to evaluation by the Company’s chief operating decision maker in deciding how to allocate resources.

 

In January 2008, the Company announced a change in organizational structure 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 reports its operations in three segments, which reflect its lines of business. The EQT Production segment includes the Company’s exploration for, and development and production of, natural gas and a limited amount of crude oil in the Appalachian Basin. EQT Midstream’s operations include the natural gas gathering, processing, transportation and storage activities of the Company as well as sales of NGLs. Equitable Distribution’s operations primarily comprise the state-regulated distribution activities of the Company.

 

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 expenses (income) and administrative expenses totaling ($17.4) million, $65.3 million and $21.9 million in 2008, 2007 and 2006, respectively, were not allocated to business segments. The unallocated income in 2008 primarily related to the reversal of previously recorded performance-related incentive expense, while the unallocated expense in 2007 and 2006 related to performance-related incentive expenses in those years.

 

Substantially all of the Company’s operating revenues, income from continuing operations and assets are generated or located in the United States.

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Revenues from external customers:

 

 

 

 

 

 

 

EQT Production

 

$

457,144

 

$

364,396

 

$

359,526

 

EQT Midstream

 

681,475

 

591,608

 

554,071

 

Equitable Distribution

 

698,385

 

624,744

 

586,194

 

Less: intersegment revenues (a)

 

(260,516

)

(219,342

)

(231,881

)

Total

 

$

1,576,488

 

$

1,361,406

 

$

1,267,910

 

 

 

 

 

 

 

 

 

Total operating expenses:

 

 

 

 

 

 

 

EQT Production

 

$

204,360

 

$

162,377

 

$

144,103

 

EQT Midstream

 

168,568

 

121,483

 

116,215

 

Equitable Distribution

 

111,009

 

126,088

 

108,890

 

Unallocated (income) expenses (b)

 

(17,391

)

65,319

 

21,850

 

Total

 

$

466,546

 

$

475,267

 

$

391,058

 

 

 

 

 

 

 

 

 

Operating income:

 

 

 

 

 

 

 

EQT Production

 

$

252,784

 

$

202,019

 

$

215,423

 

EQT Midstream

 

134,772

 

140,432

 

137,177

 

Equitable Distribution

 

59,859

 

34,541

 

41,773

 

Unallocated income (expenses) (b)

 

17,391

 

(65,319

)

(21,850

)

Total operating income

 

$

464,806

 

$

311,673

 

$

372,523

 

 

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EQT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

 

 

 

 

 

 

 

 

Reconciliation of operating income to net income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total operating income

 

$

464,806

 

$

311,673

 

$

372,523

 

 

 

 

 

 

 

 

 

Equity in earnings of nonconsolidated investments:

 

 

 

 

 

 

 

EQT Production

 

$

440

 

$

301

 

$

129

 

EQT Midstream

 

5,053

 

2,648

 

 

Unallocated

 

221

 

150

 

131

 

Total

 

$

5,714

 

$

3,099

 

$

260

 

 

 

 

 

 

 

 

 

Other income:

 

 

 

 

 

 

 

EQT Midstream

 

$

5,678

 

$

7,253

 

$

1,149

 

Equitable Distribution

 

555

 

392

 

293

 

Total

 

$

6,233

 

$

7,645

 

$

1,442

 

 

 

 

 

 

 

 

 

Other than temporary impairment of available-for-sale securities

 

(7,835

)

 

 

Gain on sale of assets, net

 

 

126,088

 

 

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

 

 

1,042

 

 

Interest expense

 

58,394

 

47,669

 

48,494

 

Income taxes

 

154,920

 

144,395

 

109,706

 

Income from continuing operations

 

255,604

 

257,483

 

216,025

 

Income from discontinued operations

 

 

 

4,261

 

Net income

 

$

255,604

 

$

257,483

 

$

220,286

 

 

 

 

As of December 31,

 

 

 

2008

 

2007

 

 

 

(Thousands)

 

Segment assets:

 

 

 

 

 

EQT Production

 

$

2,338,695

 

$

1,614,787

 

EQT Midstream

 

1,897,872

 

1,232,348

 

Equitable Distribution

 

951,179

 

906,113

 

Total operating segments

 

5,187,746

 

3,753,248

 

Headquarters assets, including cash and short-term investments

 

141,916

 

183,723

 

Total assets

 

$

5,329,662

 

$

3,936,971

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Depreciation, depletion and amortization:

 

 

 

 

 

 

 

EQT Production

 

$

78,234

 

$

62,084

 

$

53,471

 

EQT Midstream

 

34,802

 

26,333

 

25,822

 

Equitable Distribution

 

22,055

 

20,021

 

19,938

 

Other

 

1,725

 

1,364

 

891

 

Total

 

$

136,816

 

$

109,802

 

$

100,122

 

Expenditures for segment assets:

 

 

 

 

 

 

 

EQT Production (c)

 

$

700,745

 

$

328,080

 

$

205,047

 

EQT Midstream (c)

 

593,564

 

433,719

 

146,512

 

Equitable Distribution

 

45,770

 

41,684

 

48,721

 

Other

 

3,917

 

1,276

 

2,814

 

Total

 

$

1,343,996

 

$

804,759

 

$

403,094

 

 


(a)          Intersegment revenues primarily represent natural gas sales from EQT Production to EQT Midstream and transportation activities between EQT Midstream and Equitable Distribution.

(b)         Unallocated (income) expenses consist primarily of incentive compensation and administrative costs that are not allocated to the operating segments.

(c)          Expenditures for segment assets for 2007 include $24.4 million and $3.7 million, in the EQT Production and EQT Midstream segments, respectively, for the acquisition of additional working interest and related gathering assets in the Roaring Fork area.

 

3.                                      Derivative Instruments

 

Natural Gas Hedging Instruments

 

The Company’s overall objective in its hedging program is to ensure an adequate level of return for the significant well development and infrastructure investments at EQT Production and EQT Midstream. The various derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sale of equity production and forecasted natural gas purchases and sales have been designated and qualify as cash flow hedges. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from counterparties based on the differential between a fixed and variable price for the commodity. Collar agreements require the counterparty to pay the Company if the index price falls below the floor price and the Company to pay the counterparty if the index price rises above the cap price. Exchange-traded instruments are generally settled with offsetting positions. Over the counter (OTC) arrangements require settlement in cash.

 

The fair value of the Company’s derivative commodity instruments classified as cash flow hedges under SFAS No. 133 is presented below:

 

 

 

As of December 31,

 

 

 

2008

 

2007

 

 

 

(Thousands)

 

Asset

 

$

188,247

 

$

34,921

 

Liability

 

(154,606

)

(489,227

)

Net asset (liability)

 

$

33,641

 

$

(454,306

)

 

These amounts are included in the Consolidated Balance Sheets as derivative instruments, at fair value. The net amount of derivative instruments, at fair value, changed between years primarily as a result of the decrease in natural gas prices and reduced hedged quantities due to derivative settlements. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 243.0 Bcf and

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

287.3 Bcf as of December 31, 2008 and 2007, respectively, and are primarily related to natural gas swaps and collars. The open positions at December 31, 2008 had maturities extending through December 2015.

 

The Company had deferred net losses of $28.8 million and $286.2 million in accumulated other comprehensive loss, net of tax, as of December 31, 2008 and 2007, respectively, associated with the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $3.0 million of net unrealized gains on its derivative commodity instruments included in accumulated other comprehensive loss, net of tax, as of December 31, 2008 will be recognized in earnings during the next twelve months due to the physical settlement of hedged transactions. This recognition occurs through an adjustment to the Company’s net operating revenues resulting in the average hedged price becoming the realized sales price.

 

The net change in accumulated other comprehensive loss, including the impact of adopting SFAS No. 157, Fair Value Measurements (SFAS No. 157), of $7.8 million, related to derivatives is presented below:

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Net unrealized gain (loss)

 

$

163,731

 

$

(42,010

)

$

370,395

 

Net realized loss

 

93,711

 

41,990

 

84,422

 

Net gain (loss)

 

$

257,442

 

$

(20

)

$

454,817

 

 

For the years ended December 31, 2008, 2007 and 2006, ineffectiveness associated with the Company’s derivative instruments designated as cash flow hedges increased earnings by approximately $0.8 million, $1.4 million and $0.4 million, respectively. These amounts are included in operating revenues in the Statements of Consolidated Income.

 

In the fourth quarter 2008, the company entered into derivative transactions which had the effect of offsetting existing cash flow hedges and concurrently de-designated the original transactions as hedges. Thee transactions resulted in an effective reduction in the hedge position for years 2010 - 2013.  The fair value of these derivative instruments was an $18.4 million liability at December 31, 2008.  This amount will be recognized as part of the realized sales price in the Consolidated Statement of Income when the underlying physical transactions occur. The Company does not treat these derivatives as hedging instruments under SFAS No. 133. These amounts are included in the Consolidated Balance Sheet as derivative instruments, at fair value. In May 2007, the Company sold a portion of its interest in certain gas properties in the Nora area, as discussed in Note 5. As part of this transaction, the Company closed out certain cash flow hedges associated with forecasted production at this location by purchasing offsetting positions. The fair value of these derivative instruments was a $2.9 million liability at December 31, 2008.

 

The Company had an immaterial amount of other derivative commodity instruments held for trading purposes as of December 31, 2008 and December 31, 2007.

 

When the net fair value of any of the Company’s swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company records these deposits as a receivable in the Consolidated Balance Sheet. When the net fair value of any of the Company’s swap agreements represents an asset to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the Company requires the counterparty to remit funds as margin deposit in an amount equal to the portion of the derivative asset which is in excess of the threshold amount. The Company records a current liability for such amounts received. The Company had no such deposits in its Consolidated Balance Sheet as of December 31, 2008. As of December 31, 2007, the Company recorded such deposits held by counterparties in the amount of $1.6 million in its Consolidated Balance Sheet.

 

When the Company enters into exchange-traded natural gas contracts, exchanges may require the Company to remit funds to the corresponding broker as good-faith deposits to guard against the risks associated with changing

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

market conditions. Participants must make such deposits based on an established initial margin requirement as well as the net liability position, if any, of the fair value of the associated contracts. In the case where the fair value of such contracts is in a net asset position, the broker may remit funds to the Company, in which case the Company records a current liability for such amounts received. The initial margin requirements are established by the exchanges based on prices, volatility and the time to expiration of the related contract and are subject to change at the exchanges’ discretion. The Company recorded such deposits with brokers in the amount of $4.4 million and $4.3 million in its balance sheet as of December 31, 2008 and December 31, 2007, respectively.

 

4.                                      Fair Value Measurements

 

In September 2006, the Financial Accounting Standards Board issued SFAS No. 157 which established a framework for measuring fair value in accordance with generally accepted accounting principles and expanded disclosures about fair value measurements. The Company adopted the provisions of SFAS No. 157 on January 1, 2008. As a result of the implementation of SFAS No. 157, the Company recorded a gain in accumulated other comprehensive income of $7.8 million during the first quarter of 2008.

 

The Company has an established process for determining fair value for its financial instruments, principally derivative commodity instruments and available-for-sale investments. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk. Nonperformance risk considers the effect of the Company’s credit standing on the fair value of liabilities and the effect of the counterparty’s credit standing on the fair value of assets. The Company determines nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to the Company’s or counterparty’s credit rating and the yield of a risk free instrument. The Company also analyzes credit default swaps rates where available.

 

In accordance with SFAS No. 157, the Company has categorized its financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Financial instruments included in Level 1 include the Company’s futures contracts and available-for-sale investments, instruments included in Level 2 include the majority of the Company’s swap agreements and instruments included in Level 3 include the Company’s collar agreements and a portion of the Company’s swap agreements. Since the adoption of SFAS No. 157, the Company has not made any changes to its classification of financial instruments in each category.

 

The fair value of financial instruments included in Level 2 is based on industry models that use significant observable inputs, including NYMEX forward curves and LIBOR-based discount rates. Swaps included in Level 3 are valued using internal models; these internal models are validated each period with non-binding broker price quotes. The Company has not experienced significant differences between internally calculated values and broker price quotes. Collars make up over 98% of derivative instruments included in Level 3 and are valued using internal models calculated with publicly available volatilities. The Company uses NYMEX forward curves to value futures, NYMEX swaps, and collars. The NYMEX forward curves are validated to external sources at least monthly.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

The following assets and liabilities were measured at fair value on a recurring basis during the period:

 

 

 

 

 

Fair value measurements at reporting date using

 

Description

 

December 31,
2008

 

Quoted
prices in
active
markets for
identical
assets
(Level 1)

 

Significant
other
observable
inputs
(Level 2)

 

Significant
unobservable
inputs
(Level 3)

 

 

 

(Thousands)

 

Assets

 

 

 

 

 

 

 

 

 

Investments, available-for-sale

 

$

25,880

 

$

25,880

 

$

 

$

 

Derivative instruments, at fair value

 

192,191

 

33,842

 

70,044

 

88,305

 

Total assets

 

$

218,071

 

$

59,722

 

$

70,044

 

$

88,305

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

Derivative instruments, at fair value

 

$

(175,889

)

$

(27,083

)

$

(148,106

)

$

(700

)

Total liabilities

 

$

(175,889

)

$

(27,083

)

$

(148,106

)

$

(700

)

 

 

 

Fair value measurements using
significant unobservable inputs
(Level 3)

 

 

 

Derivative instruments, at fair
value, net

 

 

 

(Thousands)

 

Balance at January 1, 2008

 

$

(2,387

)

Total gains or losses:

 

 

 

Included in earnings

 

6,900

 

Included in other comprehensive income

 

105,452

 

Purchases, issuances, and settlements

 

(22,360

)

Transfers in and/or out of Level 3

 

 

Balance at December 31, 2008

 

87,605

 

 

 

 

 

The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets and liabilities still held as of December 31, 2008

 

$

(327

)

 

Gains and losses related to derivative commodity instruments included in earnings for the period are reported in operating revenues in the Statements of Consolidated Income. Any gains or loses included in earnings related to available-for-sale securities are included as a separate component of earnings.

 

5.                                      Sale of Properties

 

On April 13, 2007, the Company and Range Resources Corporation (Range) agreed to a development plan for the Nora area in Southwestern Virginia. The Company entered into a Purchase and Sale Agreement (Purchase Agreement) with Pine Mountain Oil and Gas, Inc. (PMOG), a subsidiary of Range, pursuant to which the Company agreed to sell to PMOG a portion of the Company’s interests in certain gas properties in the Nora area. Additionally, the Company entered into a Contribution Agreement (Contribution Agreement) with PMOG relating

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

to the contribution of certain Nora area gathering facilities and pipelines to Nora Gathering, LLC (Nora LLC), a newly formed entity that is equally owned by the Company and PMOG. This gathering system services production of the Company and Range. During the remainder of 2007, the Company completed a majority of the transactions contemplated by the Purchase Agreement by selling proved reserves of approximately 74 Bcf, including proved developed reserves of approximately 67 Bcf, to PMOG for proceeds of $193.5 million after purchase price adjustments.

 

Additionally in 2007, the Company entered into a Contribution Agreement with PMOG relating to the contribution of certain Nora area gathering facilities and pipelines to Nora Gathering, LLC (Nora LLC), a newly formed entity that is equally owned by the Company and PMOG. This gathering system services production of the Company and Range. The Company contributed Nora area gathering property to Nora LLC in exchange for a 50% interest in Nora LLC and cash of $23.6 million. The Company is accounting for its interest in Nora LLC under the equity method of accounting, as the Company determined that it has the ability to exert significant influence over the operating and financial policies of Nora LLC through its 50%, non-controlling interest. The Company and Nora LLC also entered into a demand note agreement whereby Nora LLC loaned to the Company $69.8 million on the initial closing date. At December 31, 2008, the note has been fully paid and cancelled.

 

The Company recorded a gain on these transactions of $154.5 million, net of costs to sell, in accordance with SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies (SFAS No. 19). As a result of the working interest sale, the Company reduced its hedge position by approximately 7.3 Bcf, resulting in the Company recording a hedge loss of $28.4 million as of the date of sale. These items are recorded in gain on sale of assets, net ($126.1 million) in the Company’s Statements of Consolidated Income for 2007.

 

6.                                      Acquisitions

 

In September 2007, the Company purchased an additional working interest of approximately 13.5% in the Roaring Fork area in Virginia and certain gathering assets from a minority interest holder for $28.5 million subject to post-closing adjustments, which increased the Company’s working interest to approximately 97.0%. The additional working interest of 13.5% represented approximately 12.3 Bcf of reserves, consisting of approximately 10.1 Bcf of proved developed reserves and approximately 2.2 Bcf of proved undeveloped reserves. The purchase price was funded using a portion of the proceeds received from the sale described in Note 5, as this transaction qualified as a like-kind exchange under the deferred exchange agreement.

 

On March 1, 2006, the Company entered into an agreement to acquire Dominion Resources, Inc.’s natural gas distribution assets in Pennsylvania and in West Virginia for approximately $970 million, subject to adjustments, in a cash transaction for the stock of The Peoples Natural Gas Company and Hope Gas, Inc. In light of the continued delay in achieving the final legal approvals for this transaction, the Company and Dominion agreed to terminate the agreement pursuant to a mutual termination agreement entered into on January 15, 2008. As a result of this previously proposed transaction and its termination, the Company recognized a total of $21 million in expense, including $9.8 million of deferred acquisition costs and $0.3 million of impairment charges in the 2007 Statements of Consolidated Income.

 

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DECEMBER 31, 2008

 

7.                                      Income Taxes

 

Income tax expense is summarized as follows:

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Current:

 

 

 

 

 

 

 

Federal

 

$

(89,630

)

$

102,692

 

$

75,875

 

State

 

(614

)

9,323

 

2,564

 

Subtotal

 

(90,244

)

112,015

 

78,439

 

Deferred:

 

 

 

 

 

 

 

Federal

 

238,034

 

23,756

 

42,122

 

State

 

7,767

 

9,264

 

(9,797

)

Subtotal

 

245,801

 

33,020

 

32,325

 

Amortization of deferred investment tax credit

 

(637

)

(640

)

(1,058

)

Total

 

$

154,920

 

$

144,395

 

$

109,706

 

 

The current federal tax benefit results in prepaid income taxes of approximately $93.5 million which is included in prepaid expenses and other assets in the Consolidated Balance Sheet.

 

Income tax expense differs from amounts computed at the federal statutory rate of 35% on pre-tax income from continuing operations as follows:

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Tax at statutory rate

 

$

143,683

 

$

140,657

 

$

114,006

 

State income taxes

 

4,511

 

8,951

 

(8,130

)

Federal tax credits and incentives

 

1,968

 

(5,066

)

(1,238

)

Book/Tax basis differences

 

(2,368

)

(3,514

)

(125

)

Other

 

7,126

 

3,367

 

5,193

 

Income tax expense

 

154,920

 

$

144,395

 

$

109,706

 

Effective tax rate

 

37.7

%

35.9

%

33.7

%

 

During 2008, state income taxes decreased as a result of a West Virginia law change enacted on March 31, 2008, providing for a graduated decrease in the statutory tax rate beginning in 2009 and reinstating separate financial organization apportionment. As a result of this change in West Virginia law, the Company recorded a tax benefit of $5.2 million to reflect an overall decrease in the Company’s expected deferred tax liability.

 

The Qualified Production Activities Deduction under Section 199 of the IRC, which provides for a phased-in deduction related to qualifying production activities, was provided for the first time under the American Jobs Creation Act of 2004. The Company recorded an income tax benefit for certain qualifying production activities of approximately $4.5 million and $0.6 million in 2007 and 2006, respectively. Due to the Company’s taxable loss position in 2008 and the resulting net operating loss carryback, no Section 199 benefit was recorded for 2008 and a portion of the prior years’ benefits was reversed. The reversal of the prior years’ Section 199 deduction was a detriment to the 2008 effective tax rate in the amount of $2.6 million in 2008.

 

During 2008, the Company applied for a change in accounting method that would allow current income tax deductions for certain repair costs that are capitalized for book purposes. The method request is a non-automatic change and requires the consent of the IRS, which the Company has not yet received. Thus, the impact of this method change has not yet been reflected in the Consolidated Financial Statements even though it is anticipated to increase the Company’s net operating loss for 2008 and the related refund on the net operating loss carryback.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

During 2007, state income taxes increased as a result of a West Virginia law change enacted on April 4, 2007 that was slated to be effective for the Company’s tax year beginning January 1, 2009. This new law mandated unitary combined reporting, changed certain apportionment provisions for tax partnerships, changed certain definitions for financial organizations and made miscellaneous changes to other corporate net income tax statutes. As a result of this law change, the Company recorded additional tax expense of $3.3 million to reflect an overall increase in the Company’s expected deferred tax liability as of the effective date.

 

During 2006, state income taxes decreased as a result of a change to state income tax rates as computed in accordance with SFAS No. 109 and the release of a state valuation allowance related to a state net operating loss carryover. During 2006, the Company reduced its valuation allowance for state net operating loss carryovers by $3.1 million as a result of an anticipated increase in prospective realization of those deferred tax assets.

 

The other category does not include any items that are individually significant.

 

The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the Company recognized a $4.1 million increase in the liability for unrecognized tax benefits which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. Additionally, as a result of the implementation of FIN 48, the Company recorded $29.7 million of unrecognized tax benefits related to a balance sheet reclassification that did not impact retained earnings. A total of $16.9 million of this reclassification relates to the gross up of certain tax positions that were previously recorded net of tax benefit, tax positions which relate to temporary differences that were previously part of deferred taxes and tax positions that were previously offset against deferred tax assets. The remaining $12.8 million relates to tax positions previously categorized as current liabilities. After the recognition of these items in connection with the implementation of FIN 48, the total liability for unrecognized tax benefits, inclusive of interest and penalties, at January 1, 2007 was $33.8 million.

 

A reconciliation of the beginning and ending amount of unrecognized tax benefits (excluding interest and penalties) is as follows:

 

 

 

2008

 

2007

 

 

 

(Thousands)

 

(Thousands)

 

Balance at January 1

 

31,367

 

22,760

 

Additions based on tax positions related to current year

 

5,628

 

3,140

 

Additions for tax positions of prior years

 

2,286

 

9,676

 

Reductions for tax positions of prior years

 

(854

)

(4,209

)

Settlements

 

(3,170

)

 

Lapse of statute of limitations

 

(1,086

)

 

Balance at December 31

 

34,171

 

31,367

 

 

Included in the tabular reconciliation above at December 31, 2008 and December 31, 2007 are $20.2 million and $18.1 million, respectively, for tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

 

The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income tax expense. During the year ended December 31, 2008, the Company reversed approximately $6.1 million of interest expense and for the year ended December 31, 2007, the Company recognized approximately $8.5 million of interest expense. Included in the balance sheet reserve at December 31, 2008 and December 31, 2007 is $13.4 million and $19.5 million of interest and penalty.

 

The total amount of unrecognized tax benefits, inclusive of interest and penalties, was $47.6 million and $50.8 million as of December 31, 2008 and 2007, respectively. As of December 31, 2008, $10.7 million is the total amount of unrecognized tax benefits (excluding interest and penalties) that, if recognized, would affect the effective tax rate and the amount as of December 31, 2007 was $11.1 million.

 

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DECEMBER 31, 2008

 

As of December 31, 2008, it is reasonably possible that the total amount of unrecognized tax benefits could decrease between $0.0 million and $21.1 million within the next 12 months due to potential settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.

 

The consolidated federal income tax liability of the Company has been settled with the Internal Revenue Service (IRS) through 2000. In December 2008, the Joint Committee on Taxation approved the settlement of all issues related to the 1998 through 2000 audit. The Company received a final net tax refund of $3.8 million, including interest, for these years.

 

 The IRS has completed its audit and review of the Company’s federal income tax filings for the 2001 through 2005 years and the Company expects a refund relating to the agreed upon audit adjustments for these years of approximately $3.4 million. The only unresolved issue relates to the research and experimentation tax credits claimed for years 2001 through 2005, which has been referred to the Appeals Division of the IRS. The Company also is the subject of various state income tax examinations. The Company believes that it is appropriately reserved for any uncertain tax positions claimed during these periods.

 

The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.

 

 

 

December 31,

 

 

 

2008

 

2007

 

 

 

(Thousands)

 

Deferred income taxes:

 

 

 

 

 

Total deferred income tax assets

 

$

(163,707

)

$

(339,135

)

Total deferred income tax liabilities

 

920,878

 

699,476

 

Total net deferred income tax liabilities

 

757,171

 

$

360,341

 

 

 

 

 

 

 

Total deferred income tax liabilities (assets)

 

 

 

 

 

Drilling and development costs expensed for income tax reporting

 

609,490

 

$

474,882

 

Tax depreciation in excess of book depreciation

 

257,353

 

123,633

 

Regulatory temporary differences

 

31,308

 

35,652

 

Deferred purchased gas cost

 

22,727

 

15,428

 

Financial instruments

 

(28

)

(26,385

)

Deferred compensation plans

 

(2,480

)

(2,550

)

Investment tax credit

 

(2,738

)

(2,784

)

Incentive compensation, net of valuation allowance of $182 and $0, respectively

 

(4,436

)

(43,224

)

Post-retirement benefits

 

(8,061

)

(8,314

)

Uncollectible accounts

 

(8,718

)

(6,645

)

Other comprehensive loss

 

(43,697

)

(188,593

)

Alternative minimum tax credit carryforward

 

(46,424

)

 

NOL carryforwards, net of valuation allowance of $3,591 and $3,265, respectively

 

(47,085

)

(6,756

)

Other

 

(40

)

(4,003

)

Total (including amounts classified as current assets of $17,546 and $32,274, respectively)

 

$

757,171

 

$

360,341

 

 

The net deferred tax asset relating to the Company’s accumulated other comprehensive loss balance as of December 31, 2008 was comprised of a $17.6 million deferred tax asset related to the Company’s net unrealized loss from hedging transactions, a $8.7 million deferred tax asset related to other post-retirement benefits, and a $17.4 million deferred tax asset related to the Company’s pension plans. The net deferred tax asset relating to the Company’s accumulated other comprehensive loss balance as of December 31, 2007 was comprised of a $173.3 million deferred tax asset related to the Company’s net unrealized loss from hedging transactions, a $7.5 million deferred tax asset related to other post-retirement benefits, a $9.9 million deferred tax asset related to the pension

 

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DECEMBER 31, 2008

 

plans, and a $2.1 million deferred tax liability related to the Company’s net unrealized gain on available-for-sale securities.

 

The Company expects a 2008 taxable loss that can be carried back to recover income taxes paid in tax years 2006 and 2007. The excess 2008 tax loss will be carried forward and the Company recorded a deferred tax benefit in the amount of $24.2 million for its net operating loss carryforward. The federal net operating loss carryforward period is 20 years and, if unused, the loss carryforward will expire in 2028. The Company is subject to alternative minimum tax (AMT) primarily due to limitations on deductions for intangible drilling costs. AMT taxes may be carried forward indefinitely and are creditable against regular income tax. The Company recorded a deferred tax asset in 2008 for AMT credits of $46.4 million.

 

The Company has recorded a deferred tax asset of $22.9 million, which is net of valuation allowances of $3.6 million, related to tax benefits from state net operating loss carryforwards with various expiration dates ranging from 2009 to 2028.

 

An income tax benefit of approximately $1 million, $18 million and $19 million for the years ended December 31, 2008, 2007 and 2006, respectively, triggered by the exercise of nonqualified employee stock options and vesting of restricted share awards is reflected as an addition to common stockholders’ equity.

 

8.                                      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 fourth quarter of 2006, the Company recorded a tax benefit of $3.2 million related to a reduced tax liability on the sale. The Company also reassessed its remaining reserves for costs incurred related to the sale and recorded after-tax income of $1.1 million as a result. These items are included in income from discontinued operations in the Company’s Statement of Consolidated Income for the year ended December 31, 2006.

 

In 2006, the Company completed the sale of the remaining interest in its investment in IGC/ERI Pan-Am Thermal Generating Limited (Pan Am), previously included in the NORESCO business segment, for total proceeds of $2.6 million. The Company did not record a gain or loss on this sale.

 

Cash flows generated from the discontinued operations and the proceeds received from the sale of the Pan Am investment of $2.6 million are included in the Consolidated Statements of Cash Flows for the year ended December 31, 2006.

 

9.                                      Equity in Nonconsolidated Investments

 

The Company has ownership interests in nonconsolidated investments that are accounted for under the equity method of accounting. The following table summarizes the equity in the nonconsolidated investments:

 

 

 

 

 

Interest

 

Ownership
as of
December

 

December 31,

 

Investees

 

Location

 

Type

 

31, 2008

 

2008

 

2007

 

 

 

 

 

 

 

 

 

(Thousands)

 

Nora Gathering, LLC (Nora LLC)

 

USA

 

Joint

 

50

%

$

131,037

 

$

96,985

 

Appalachian Natural Gas Trust (ANGT)

 

USA

 

Limited

 

1

%

38,204

 

38,381

 

Total equity in nonconsolidated investments

 

 

 

 

 

 

 

$

169,241

 

$

135,366

 

 

The Company’s ownership share of the earnings for 2008, 2007 and 2006 related to the total investments was $5.7 million, $3.1 million and $0.3 million, respectively.

 

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DECEMBER 31, 2008

 

EQT Midstream’s equity investment in Nora LLC represents a 50% ownership interest which was obtained through a series of transactions with PMOG by contributing Nora area gathering property in exchange for the ownership interest, as discussed in Note 5. EQT Midstream’s investment in Nora LLC totaled $131.0 million and $97.0 million as of December 31, 2008 and 2007, respectively. EQT Midstream made additional equity investments in Nora LLC of $29.0 million in 2008.

 

EQT Production’s equity investment in ANGT represents an ownership interest in transactions by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. As of December 31, 2008, EQT Production’s investment in ANGT totaled $25.4 million while the Company’s total investment was $38.2 million. As of December 31, 2007, EQT Production’s investment in ANGT totaled $25.5 million, while the Company’s total investment was $38.4 million. The portion of the investment not held by EQT Production is intended to fund plugging and abandonment and other liabilities for which the Company self-insures. The Company did not make any additional equity investments in ANGT during 2008.

 

The following tables summarize the unaudited condensed financial statements for nonconsolidated investments accounted for under the equity method of accounting for the periods noted:

 

Summarized Balance Sheets

 

 

 

As of December 31,

 

 

 

 

 

2008

 

2007

 

 

 

 

 

(Thousands)

 

 

 

Current assets

 

$

20,994

 

$

44,240

 

 

 

Noncurrent assets

 

421,152

 

337,247

 

 

 

Total assets

 

$

442,146

 

$

381,487

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

$

21,205

 

$

11,068

 

 

 

Stockholders’ equity

 

420,941

 

370,419

 

 

 

Total liabilities and stockholders’ equity

 

$

442,146

 

$

381,487

 

 

 

 

Summarized Statements of Income

 

 

 

Year Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Revenues

 

$

140,658

 

$

101,817

 

$

94,477

 

Costs and expenses applicable to revenues

 

 

 

 

Net revenues

 

140,658

 

101,817

 

94,477

 

Operating expenses

 

64,273

 

51,345

 

43,056

 

Net income

 

$

76,385

 

$

50,472

 

$

51,421

 

 

10.                               Investments, Available-For-Sale

 

As of December 31, 2008, the investments classified by the Company as available-for-sale consist of approximately $25.9 million of equity and bond funds intended to fund plugging and abandonment and other liabilities for which the Company self-insures.

 

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DECEMBER 31, 2008

 

 

 

December 31, 2008

 

 

 

Adjusted
Cost

 

Gross
Unrealized
Gains

 

Gross
Unrealized
Losses

 

Fair
Value

 

 

 

(Thousands)

 

Equity funds

 

$

20,219

 

$

 

$

 

$

20,219

 

Bond funds

 

5,661

 

 

 

5,661

 

Total investments

 

$

25,880

 

$

 

$

 

$

25,880

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2007

 

 

 

Cost

 

Gross
Unrealized
Gains

 

Gross
Unrealized
Losses

 

Fair
Value

 

 

 

(Thousands)

 

Equity funds

 

$

24,839

 

$

5,914

 

$

 

$

30,753

 

Bond funds

 

4,879

 

43

 

 

4,922

 

Total investments

 

$

29,718

 

$

5,957

 

$

 

$

35,675

 

 

The Company accounts for these debt and equity securities in accordance with SFAS No. 115. These investments had a fair market value which was $7.8 million below cost as of December 31, 2008. The Company analyzed the decline in these investments based on the extent and duration of the impairment, nature of the underlying assets and the Company’s intent and ability to hold the investments. Based on this analysis, the Company concluded that the decline in the securities values was other-than-temporary and recorded the decline in value as other than temporary impairment of available-for-sale securities within the Statements of Consolidated Income. This impaired value is the new (adjusted) cost of these investments for purposes of future impairment and unrealized gain or loss determinations. In 2007, increases in the value of these securities were recognized within the Condensed Consolidated Balance Sheets as a component of equity, accumulated other comprehensive income.

 

During the first three months of 2008, the Company purchased additional equity and bond funds with a cost basis totaling $3.0 million. During the first quarter of 2007, the Company reviewed its investment portfolio including its investment allocation and as a result 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. The Company used the proceeds from these sales and other available cash to purchase other bond and equity funds with a cost basis totaling $9.7 million during the first quarter of 2007. These investments are classified as available-for-sale in the Consolidated Balance Sheet.

 

The Company utilizes the specific identification method to determine the cost of all investment securities sold.

 

11.                               Regulatory Assets

 

The following table summarizes the Company’s regulatory assets, net of amortization, as of December 31, 2008 and 2007. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of its regulatory assets.

 

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DECEMBER 31, 2008

 

 

 

December 31,

 

Description

 

2008

 

2007

 

 

 

(Thousands)

 

Deferred taxes

 

$

68,288

 

$

62,897

 

Deferred purchased gas costs

 

56,451

 

39,081

 

Other post-retirement benefits (SFAS No. 106)

 

11,599

 

13,010

 

Transmission costs recoverable

 

2,929

 

367

 

Delinquency Reduction Opportunity Program

 

696

 

1,734

 

Other

 

13

 

7

 

Total regulatory assets

 

139,976

 

117,096

 

Amounts classified as other current assets

 

56,451

 

39,081

 

Total long-term regulatory assets

 

$

83,525

 

$

78,015

 

 

The regulatory asset associated with deferred taxes primarily represents deferred income taxes recoverable through future rates once the taxes become current. The Company expects to recover the amortization of this asset through rates. At December 31, 2008 and 2007, the deferred purchased gas costs regulatory asset was reduced by $10.3 million and $3.6 million, respectively, of unrealized gains on derivative contracts designated as cash flow hedges that would have been classified as other comprehensive income absent the probability of recovery through rates. Deferred purchased gas cost is included in prepaid expenses and other in the Consolidated Balance Sheet.

 

The Company amortizes post-retirement benefits other than pensions previously deferred as well as recognizing expenses for on-going post-retirement benefits other than pensions, which are subject to recovery in approved rates. The reduction in the Company’s regulatory asset for amortization of post-retirement benefits other than pensions previously deferred was approximately $1.4 million for each of the years ended December 31, 2008 and 2007.

 

Transmission costs recoverable include costs related to Equitrans’ 2006 rate case settlement with the Federal Energy Regulatory Commission which allows the Company 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. Other costs that are allowed under tariff to be recovered over time from ratepayers are also included in this category.

 

The Company adopted SFAS 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. 158), as of December 31, 2006 and recorded a regulatory asset at that time for Equitrans’ other post-retirement benefits. This regulatory asset was $8.9 million at December 31, 2008 and $8.8 million at December 31, 2007. The Company believes the future recovery of the unfunded status of the Equitrans other post-retirement benefits is probable in accordance with the requirements of SFAS No. 71.

 

The regulatory asset associated with a Delinquency Reduction Opportunity Program at Equitable Distribution relates to uncollectible accounts receivable resulting from unusually high natural gas prices and unseasonably cold weather experienced during the winter of 2000-2001. The regulatory asset was initially established based upon the Company’s ability to recover these costs through a surcharge in rates. In 2002, the PA PUC issued an order approving a Delinquency Reduction Opportunity Program that gives incentives to low-income customers to make payments that exceed their current bill amount in order to receive additional credits from the Company intended to speed the reduction of the customer’s delinquent balance. This program is funded through customer contributions and through the existing surcharge in rates.

 

The following regulatory assets do not earn a return on investment: deferred taxes, other post-retirement benefits (SFAS No. 106) and Delinquency Reduction Opportunity Program.

 

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DECEMBER 31, 2008

12.                               Short-Term Loans

 

On October 27, 2006, the Company entered into a $1.5 billion, five-year revolving credit agreement, which replaced the Company’s previous $1 billion, five-year revolving credit agreement. On December 15, 2006, the maturity date was extended to October 26, 2011 pursuant to its terms. Additionally, the Company may request two one-year extensions of the stated maturity date; however, these extensions require the approval of 51% of the lenders underwriting the credit facility. The revolving credit agreement may be used for working capital, capital expenditures, share repurchases and other purposes including support of a commercial paper program. Subject to certain terms and conditions, the Company may, on a one time basis, request that the lenders’ commitments be increased to an aggregate amount of up to $2.0 billion. Each lender in the facility may decide if it will increase its commitment.

 

The credit facility is underwritten by a syndicate of 15 financial institutions each of which is obligated to fund its pro-rata portion of any borrowings by the Company. Lehman Brothers Bank, FSB (Lehman) is one of the 15 financial institutions in the syndicate and had committed to make loans not exceeding $95 million under the facility. Lehman failed to fund its portion of all recent borrowings by the Company which effectively reduces the total amount available under the facility to $1,405 million.

 

The Company is not required to maintain compensating bank balances. The Company’s debt issuer credit ratings, as determined by either Standard & Poor’s or Moody’s on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Company’s debt credit rating, the higher the level of fees and borrowing rate.

 

As of December 31, 2008, the Company had outstanding under the revolving credit facility loans of $319.9 million and an irrevocable standby letter of credit of $25.8 million. As of December 31, 2007, the Company had outstanding short-term loans under the revolving credit facility of $450.0 million. Commitment fees averaging one-twelfth of one percent and one-seventeenth of one percent in 2008 and 2007, respectively, were paid to maintain credit availability under the revolving credit facility.

 

The weighted average interest rates for short-term loans outstanding as of December 31, 2008 and 2007 were 0.84% and 5.26%, respectively. The maximum amount of outstanding short-term loans at any time during the year was $620.0 million in 2008 and $450.0 million in 2007. The average daily balance of short-term loans outstanding over the course of the year was approximately $199.6 million and $199.5 million at weighted average annual interest rates of 3.47% and 5.84% during 2008 and 2007, respectively.

 

13.                               Long-Term Debt

 

 

 

December 31,

 

 

 

2008

 

2007

 

 

 

(Thousands)

 

5.15% notes, due March 1, 2018

 

$

200,000

 

$

200,000

 

5.15% notes, due November 15, 2012

 

200,000

 

200,000

 

5.00% notes, due October 1, 2015

 

150,000

 

150,000

 

6.50% notes, due April 1, 2018

 

500,000

 

 

7.75% debentures, due July 15, 2026

 

115,000

 

115,000

 

Medium-term notes:

 

 

 

 

 

8.5% to 9.0% Series A, due 2009 thru 2021

 

50,500

 

50,500

 

7.3% to 7.6% Series B, due 2013 thru 2023

 

30,000

 

30,000

 

7.6% Series C, due 2018

 

8,000

 

8,000

 

 

 

1,253,500

 

753,500

 

Less debt payable within one year

 

4,300

 

 

Total long-term debt

 

$

1,249,200

 

$

753,500

 

 

The indentures and other agreements governing the Company’s indebtedness contain certain restrictive financial and operating covenants including covenants that restrict the Company’s ability to incur indebtedness,

 

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DECEMBER 31, 2008

 

incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. The covenants do not contain a rating trigger. Therefore, a change in Company’s debt rating would not trigger a default under the indentures and other agreements governing the Company’s indebtedness.

 

Aggregate maturities of long-term debt are $4.3 million in 2009, $0 in 2010, $6.0 million in 2011, $200.0 million in 2012 and $10.0 million in 2013.

 

14.                               Pension and Other Post-retirement Benefit Plans

 

During the fourth quarter of 2008, the Company settled its pension obligations under a plan covering employees of the former Kentucky West Virginia Gas Company LLC, an EQT subsidiary which merged into Equitable Gathering LLC. The former Kentucky West Virginia employees transferred to Equitable Gathering LLC or Equitable Production Company. As a result of the settlement, the Company recognized settlement expense of approximately $9.0 million, comprised of $8.0 million for pension benefits and $1.0 for other post-retirement benefits, for an early retirement program. Under this settlement, the affected employees were provided the option to either roll over the lump-sum value of their pension benefit to the Company’s defined contribution plan or to receive an insured annuity benefit. The $9.0 million settlement expense is recorded as operating and maintenance expense included within operating expense of the EQT Midstream business segment (see Note 2). As a result of this settlement, the Company’s projected benefit obligation decreased by approximately $3.9 million. The Company made a cash contribution to the pension plan in the fourth quarter of 2008 to fund the pension conversion payments. Additional funding to complete the plan termination will be made during 2009.

 

During 2007, the Company recognized a settlement expense of $0.5 million due to a plan design change for a specific union and an additional settlement expense for $0.5 million due to the transfer of some current active employees to non-union employment.

 

During the fourth quarter of 2006, the Company recognized a settlement expense of approximately $3.3 million, comprised of $2.7 million for pension benefits and $0.6 million for other post-retirement benefits, for an early retirement program. This settlement expense was primarily the result of special termination benefits. Under this settlement, the affected employees were provided the option to either receive the lump-sum value or an insured monthly annuity of their pension benefit or roll over the lump-sum value of their pension benefit to the Company’s defined contribution plan. As a result of this settlement, the Company’s projected benefit obligation decreased by approximately $1.4 million. The Company made a cash contribution of $1.3 million to the pension plan in the first quarter of 2007 to fund the early retirement program.

 

During 2006, the Company made certain retiree medical plan design changes that decreased the Company’s other post-retirement benefits plan benefits obligation by approximately $10.2 million. These design changes included a decrease in the Company’s capped contribution per retiree and the elimination of certain retiree benefits.

 

All other non-represented employees are participants in a defined contribution plan.

 

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DECEMBER 31, 2008

 

The following table sets forth the defined benefit pension and other post-retirement benefit plans’ funded status and amounts recognized for those plans in the Company’s Consolidated Balance Sheets:

 

 

 

Pension Benefits

 

Other Benefits

 

 

 

2008

 

2007

 

2008

 

2007

 

 

 

(Thousands)

 

Change in benefit obligation:

 

 

 

 

 

 

 

 

 

Benefit obligation at beginning of year

 

$

73,228

 

$

82,122

 

$

40,266

 

$

47,144

 

Service cost

 

176

 

252

 

441

 

493

 

Interest cost

 

4,321

 

4,373

 

2,438

 

2,542

 

Amendments

 

 

 

 

(1,055

)

Actuarial loss (gain)

 

3,070

 

(1,985

)

4,462

 

(3,338

)

Benefits paid

 

(6,686

)

(7,014

)

(5,884

)

(5,520

)

Curtailments

 

 

 

961

 

 

Settlements

 

(6,067

)

(4,718

)

 

 

Special termination benefits

 

4,288

 

198

 

18

 

 

Benefit obligation at end of year

 

$

72,330

 

$

73,228

 

$

42,702

 

$

40,266

 

 

 

 

 

 

 

 

 

 

 

Change in plan assets:

 

 

 

 

 

 

 

 

 

Fair value of plan assets at beginning of year

 

$

66,968

 

$

72,616

 

$

 

$

 

Actual (loss) gain on plan assets

 

(16,785

)

4,745

 

 

 

Employer contributions

 

3,373

 

1,339

 

 

 

Benefits paid

 

(6,686

)

(7,014

)

 

 

Settlements

 

(6,067

)

(4,718

)

 

 

Fair value of plan assets at end of year

 

$

40,803

 

$

66,968

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

Funded status at end of year

 

$

(31,527

)

$

(6,260

)

$

(42,702

)

$

(40,266

)

 

 

 

 

 

 

 

 

 

 

 

 

Pension Benefits

 

Other Benefits

 

 

 

2008

 

2007

 

2008

 

2007

 

 

 

(Thousands)

 

Amounts recognized in the statement of financial position consist of:

 

 

 

 

 

 

 

 

 

Current liabilities

 

$

 

$

 

$

(4,820

)

$

(4,758

)

Noncurrent liabilities

 

(31,527

)

(6,260

)

(37,882

)

(35,508

)

Net amount recognized

 

$

(31,527

)

$

(6,260

)

$

(42,702

)

$

(40,266

)

Amounts recognized in accumulated other comprehensive loss consist of, net of tax:

 

 

 

 

 

 

 

 

 

Net loss

 

$

26,057

 

$

14,556

 

$

16,986

 

$

15,371

 

Net prior service cost (credit)

 

33

 

305

 

(3,558

)

(3,872

)

Net amount recognized

 

$

26,090

 

$

14,861

 

$

13,428

 

$

11,499

 

 

The accumulated benefit obligation for all defined benefit pension plans was $72.3 million and $73.2 million at December 31, 2008 and 2007, respectively. The Company uses a December 31 measurement date for its defined benefit pension and other post-retirement plans.

 

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DECEMBER 31, 2008

 

The Company’s costs related to its defined benefit pension and other post-retirement benefit plans were as follows:

 

 

 

Pension Benefits

 

Other Benefits

 

 

 

2008

 

2007

 

2006

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Components of net periodic benefit cost:

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

176

 

$

252

 

$

430

 

$

441

 

$

493

 

$

553

 

Interest cost

 

4,321

 

4,373

 

4,389

 

2,438

 

2,542

 

2,899

 

Expected return on plan assets

 

(5,333

)

(5,616

)

(6,132

)

 

 

 

Amortization of prior service cost

 

116

 

166

 

370

 

(902

)

(859

)

(137

)

Recognized net actuarial loss

 

1,249

 

1,453

 

1,069

 

2,043

 

2,373

 

2,146

 

Settlement loss and special termination benefits

 

9,019

 

864

 

2,348

 

17

 

 

179

 

Curtailment loss

 

337

 

547

 

602

 

961

 

 

410

 

Net periodic benefit cost

 

$

9,885

 

$

2,039

 

$

3,076

 

$

4,998

 

$

4,549

 

$

6,050

 

 

Under the Equitrans rate case settlement, the Company began amortization of post-retirement benefits other than pensions previously deferred as well as recognizing expenses for on-going post-retirement benefits other than pensions, which are now subject to recovery from July 1, 2005 forward in the approved rates. Expenses recognized by the Company for the year ended December 31, 2008 for amortization of post-retirement benefits other than pensions previously deferred and on-going post-retirement benefits other than pensions were approximately $1.4 million and $1.2 million, respectively. Expenses recognized by the Company for the year ended December 31, 2007 for amortization of post-retirement benefits other than pensions previously deferred and on-going post-retirement benefits other than pensions were approximately $1.4 million and $1.2 million, respectively. In addition, as a part of the rate case settlement, the Company recognized expenses for year ended December 31, 2006 of approximately $1.3 million for amortization of post-retirement benefits other than pensions previously deferred and on-going post-retirement benefits other than pensions for the period July 1, 2005 to December 31, 2005.

 

 

 

Pension Benefits

 

Other Benefits

 

 

 

2008

 

2007

 

2006

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Other changes in plan assets and benefit obligations recognized in other comprehensive loss, net of tax:

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss (gain).

 

$

11,501

 

$

(1,834

)

$

1,024

 

$

1,615

 

$

(2,574

)

$

17,945

 

Net prior service (credit) cost

 

(272

)

(422

)

727

 

314

 

(210

)

(3,662

)

Total recognized in other comprehensive loss, net of tax

 

11,229

 

(2,256

)

1,751

 

1,929

 

(2,784

)

14,283

 

Total recognized in net periodic benefit cost and other comprehensive loss, net of tax

 

$

21,114

 

$

(217

)

$

4,827

 

$

6,927

 

$

1,765

 

$

20,333

 

 

The estimated net loss for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year is $1.3 million. The estimated net loss and net prior service credit for the other post-retirement benefit plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year are $2.0 million and ($0.9 million).

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

The following weighted average assumptions were used to determine the benefit obligations for the Company’s defined benefit pension and other post-retirement benefit plans at December 31:

 

 

 

Pension Benefits

 

Other Benefits

 

 

 

2008

 

2007

 

2008

 

2007

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

5.75

%

6.25

%

5.75

%

6.25

%

Rate of compensation increase

 

N/A

 

N/A

 

N/A

 

N/A

 

 

The following weighted average assumptions were used to determine the net periodic benefit cost for the Company’s defined benefit pension and other post-retirement benefit plans for the years ended December 31:

 

 

 

Pension Benefits

 

Other Benefits

 

 

 

2008

 

2007

 

2008

 

2007

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

6.25

%

5.75

%

6.25

%

5.75

%

Expected return on plan assets

 

8.25

%

8.25

%

N/A

 

N/A

 

Rate of compensation increase

 

N/A

 

N/A

 

N/A

 

N/A

 

 

The expected rate of return is established at the beginning of the fiscal year to which it relates based upon information available to the Company at that time, including the plans’ investment mix and the forecasted rates of return on the types of securities held. The Company considered the historical rates of return earned on plan assets, an expected return percentage by asset class based upon a survey of investment managers and the Company’s actual and targeted investment mix. Any differences between actual experience and assumed experience are deferred as an unrecognized actuarial gain or loss. The unrecognized actuarial gains or losses are amortized into the Company’s net periodic benefit cost. The expected rate of return determined as of January 1, 2009 is 8%. This assumption will be used to derive the Company’s 2009 net periodic benefit cost. The rate of compensation increase is not applicable in determining future benefit obligations as a result of plan design. Pension expense increases as the expected rate of return decreases or if the discount rate is lowered.

 

For measurement purposes, the annual rate of increase in the per capita cost of covered health care benefits in 2009 is 9.5% for both the Pre-65 and Post-65 medical charges. The rates were assumed to decrease gradually to ultimate rates of 5.0% in 2018.

 

Assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

 

 

 

One-Percentage-Point
Increase

 

One-Percentage-Point
Decrease

 

 

 

(Thousands)

 

(Thousands)

 

 

 

2008

 

2007

 

2006

 

2008

 

2007

 

2006

 

Increase (decrease) to total of service and interest cost components

 

$

50

 

$

55

 

$

115

 

$

(49

)

$

(54

)

$

(109

)

Increase (decrease) to post-retirement benefit obligation

 

$

1,064

 

$

751

 

$

1,071

 

$

(1,007

)

$

(717

)

$

(1,000

)

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

The Company’s pension asset allocation at December 31, 2008 and 2007 and target allocation for 2008 by asset category are as follows:

 

 

 

Target

 

Percentage of Plan Assets
at December 31,

 

Asset Category

 

Allocation 2008

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Domestic broadly diversified equity securities

 

40% - 60%

 

46

%

46

%

Fixed income securities and inflation hedge securities

 

20% - 50%

 

45

%

40

%

International broadly diversified equity securities

 

5% - 15%

 

9

%

13

%

Other

 

0% - 15%

 

 

1

%

 

 

 

 

100

%

100

%

 

The investment activities of the Company’s pension plan are supervised and monitored by the Benefits Investment Committee (BIC). The BIC reports to the Compensation Committee of the Board of Directors and is comprised of the Chief Financial Officer and other officers and employees of the Company. The BIC has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the BIC are to minimize high levels of risk at the total pension investment fund level. The BIC monitors the actual asset allocation on a quarterly basis and adjustments are made, as needed, to rebalance the assets within the prescribed target ranges. Comparative market and peer group benchmarks are utilized to ensure that each of the firm’s investment managers is performing satisfactorily.

 

The Company made cash contributions of approximately $3.4 million and $1.3 million to its pension plan during 2008 and 2007, respectively, as a result of the previously described settlements. The Company expects to make cash payments of approximately $15 million related to its pensions during 2009.

 

The following pension benefit payments, which reflect expected future service, are expected to be paid by the plan during each of the next five years and the five years thereafter: $12.5 million in 2009; $6.6 million in 2010; $7.0 million in 2011; $6.6 million in 2012; $6.3 million in 2013; and $28.2 million in the five years thereafter.

 

The following benefit payments for post-retirement benefits other than pensions, which reflect expected future service, are expected to be paid by the Company during each of the next five years and the five years thereafter: $5.0 million in 2009; $4.8 million in 2010; $4.7 million in 2011; $4.5 million in 2012; $4.3 million in 2013; and $19.4 million in the five years thereafter.

 

Expense recognized by the Company related to its 401(k) employee savings plans totaled $8.8 million in 2008, $6.5 million in 2007 and $5.2 million in 2006.

 

15.                               Common Stock and Earnings Per Share

 

At December 31, 2008, shares of EQT’s authorized and unissued common stock were reserved as follows:

 

 

 

(Thousands)

 

 

 

 

 

Possible future acquisitions

 

20,457

 

Stock compensation plans

 

5,817

 

Total

 

26,274

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

Earnings Per Share

 

The computation of basic and diluted earnings per common share is shown in the table below:

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands, except per share amounts)

 

Basic earnings per common share:

 

 

 

 

 

 

 

Income from continuing operations

 

$

255,604

 

$

257,483

 

$

216,025

 

Income from discontinued operations, net of tax

 

 

 

4,261

 

Net income applicable to common stock

 

$

255,604

 

$

257,483

 

$

220,286

 

Average common shares outstanding

 

127,234

 

121,381

 

120,124

 

Basic earnings per common share

 

$

2.01

 

$

2.12

 

$

1.83

 

Diluted earnings per common share:

 

 

 

 

 

 

 

Income from continuing operations

 

$

255,604

 

$

257,483

 

$

216,025

 

Income from discontinued operations, net of tax

 

 

 

4,261

 

Net income applicable to common stock

 

$

255,604

 

$

257,483

 

$

220,286

 

Average common shares outstanding

 

127,234

 

121,381

 

120,124

 

Potentially dilutive securities:

 

 

 

 

 

 

 

Stock options and awards (a)

 

872

 

1,458

 

1,989

 

Total

 

128,106

 

122,839

 

122,113

 

Diluted earnings per common share

 

$

2.00

 

$

2.10

 

$

1.80

 

 


(a)          Options to purchase 6,480, 7,298 and 53,093 shares of common stock were not included in the computation of diluted earnings per common share for 2008, 2007 and 2006, respectively, because the options’ exercise prices were greater than the average market prices of the common shares.

 

16.                               Accumulated Other Comprehensive Loss

 

The components of accumulated other comprehensive loss, net of tax, are as follows:

 

 

 

2008

 

2007

 

 

 

(Thousands)

 

 

 

 

 

 

 

Net unrealized loss from hedging transactions

 

$

(29,219

)

$

(286,776

)

Unrealized gain on available-for-sale securities

 

 

3,872

 

Pension and other post-retirement benefits adjustment

 

$

(39,518

)

(26,360

)

Accumulated other comprehensive loss

 

$

(68,737

)

$

(309,264

)

 

Due to the significant decline in natural gas prices, the Company recorded a lower of cost or market adjustment related to hedged items (gas currently in storage for future sale) during fiscal year 2008. SFAS No. 133 allows companies to reclassify unrealized hedge gains deferred in accumulated other comprehensive income related to these items into earnings in the same period as the lower of cost or market adjustment. This resulted in $32.8 million of unrealized hedge gains, net of tax, being reclassified from accumulated other comprehensive income into earnings, offsetting the lower of cost or market adjustment, and is the primary cause of accumulated other comprehensive income continuing to be in a loss position at December 31, 2008.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

17.                               Share-Based Compensation Plans

 

The Company accounts for its share-based payment awards in accordance with SFAS No. 123R, Share-Based Payment (SFAS No. 123R).

 

Share-based compensation (income) expense recorded by the Company was as follows:

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

2005 Executive Performance Incentive Program

 

$

(41,778

)

$

63,515

 

$

21,093

 

2008 Executive Performance Incentive Program

 

496

 

 

 

2007 Supply Long-Term Incentive Program

 

2,426

 

780

 

 

Restricted stock awards

 

5,394

 

2,830

 

3,450

 

Non-qualified stock options

 

1,306

 

201

 

976

 

Non-employee directors’ share-based awards

 

(958

)

1,801

 

1,111

 

Total share-based compensation (income) expense

 

$

(33,114

)

$

69,127

 

$

26,630

 

 

Executive Performance Incentive Programs

 

In February 2005, the Compensation Committee of the Board of Directors adopted the 2005 Executive Performance Incentive Program (2005 Program) under the 1999 Long-Term Incentive Plan. The 2005 Program was established to provide additional incentive benefits to retain executive officers and certain other employees of the Company in order to further align the interests of the persons primarily responsible for the success of the Company with the interests of the shareholders. The vesting of the stock units granted under the 2005 Program occurred on December 31, 2008, after the ordinary close of the performance period. The vesting resulted in approximately 1.9 million units (175% of the award) with a value of approximately $64 million being distributed in cash and stock on December 31, 2008. Greater than 90% of the award was distributed in cash. The Company accounted for these awards as liability awards and as such recorded compensation expense for the remeasurement of the fair value of the awards at the end of each reporting period. The Company recorded a reversal of previously recorded compensation expense in 2008 primarily due to the reduction in the Company’s stock price during the year. A portion of the 2005 Program expense is included as an unallocated expense in deriving total operating income for segment reporting purposes. See Note 2.

 

In the third quarter of 2008, the Compensation Committee of the Board of Directors adopted the 2008 Executive Performance Incentive Program (2008 Program) under the 1999 Long-Term Incentive Plan. The 2008 Program was established to provide additional long-term incentive opportunities to key executives to further align their interests with those of the Company’s shareholders and with the strategic objectives of the Company. A total of 68,860 units were granted and no additional units may be granted. The vesting of these units will occur upon payment after the end of the performance period at a payout multiple dependent upon the level of total shareholder return relative to a predefined peer group’s total shareholder return during the 3.5 year performance period. As a result, zero to approximately 210,000 units (reflecting a 300% payout multiple) may be distributed upon vesting. The Compensation Committee of the Board of Directors retained the discretion to reduce the payout multiple by up to 75% if the Company does not attain a specified revenue target. However, if the Company’s total shareholder return ranking is median or above, the payout multiple may not be decreased below 100%. Payment of awards is expected to be in cash based on the price of the Company’s common stock at the end of the performance period, December 31, 2011. The Company accounts for these awards as liability awards and as such records compensation expense for the remeasurement of the fair value of the awards at the end of each reporting period. The Company continually monitors its stock price and performance in order to assess the impact on the ultimate payout under the 2008 Program. The Company’s current assumptions for the ultimate share price and payout multiple are $50 and 100% of the units awarded, respectively. The 2008 Program expense is classified as selling, general and administrative expense in the Statements of Consolidated Income.

 

The peer companies for the 2008 Program are as follows:

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

Atlas Energy Resources, LLC

Cabot Oil & Gas Corp.

Chesapeake Energy Corp.

CNX Gas Corp.

El Paso Corp.

Enbridge Inc.

Energen Corp.

Markwest Energy Partners, L.P.

MDU Resources Group Inc.

National Fuel Gas Co.

ONEOK, Inc.

Penn Virginia Corp.

Questar Corp.

Range Resources Corp.

Sempra Energy

Southern Union Co.

Southwestern Energy Co.

Spectra Energy Corp.

TransCanada Corp.

The Williams Companies, Inc.

 

2009 Shareholder Value Plan

 

In December 2008, the Compensation Committee of the Board of Directors adopted the 2009 Shareholder Value Plan (SVP) under the 1999 Long-Term Incentive Plan. The SVP was established to ensure continued alignment with shareholders, to recognize the Company’s evolution from a diversified utility to an integrated energy company and to continue to encourage sustained high performance and shareholder return. The effective date of the SVP was January 1, 2009 and as such no compensation expense was recorded in 2008. A total of 977,600 units were granted under the plan. The vesting of these units will occur upon payment after the end of the performance period. The payment will vary between zero and 2.5 times the number of units granted contingent upon a combination of the level of total shareholder return relative to a predefined peer group and the Company’s average absolute return on total capital during the performance period of January 1, 2005 to December 31, 2009. Payout of awards is expected to be in cash based on the price of the Company’s common stock at the end of the performance period, December 31, 2009.

 

2007 Supply Long-Term Incentive Program

 

On July 1, 2007, the Compensation Committee of the Board of Directors established the 2007 Supply Long-Term Incentive Program (2007 Supply Program) to provide a long-term incentive compensation opportunity to key employees in the EQT Production and EQT Midstream segments. Awards granted may be earned by achieving pre-determined total sales targets and by satisfying certain applicable employment requirements. The awards earned may be increased to a maximum of three times the initial award or reduced to zero based upon achievement of the predetermined performance levels. Payment of awards will be made in cash based on the price of the Company’s common stock at the end of the performance period, December 31, 2010. The Company accounts for these awards as liability awards and as such records compensation expense for the remeasurement of the fair value of the awards at the end of each reporting period. Approximately 162,000 awards were outstanding under this program as of December 31, 2008. In the third quarter of 2008, the Company decreased its assumption for the ultimate share price at the vesting date for the 2007 Supply Program to $45.00. In the fourth quarter of 2008, the Company increased its assumption for the payout multiple to approximately 200% of the units awarded. Total compensation cost recorded for the 2007 Supply Program was $5.1 million for the year ended December 31, 2008, which included $2.7 million of cost capitalized as part of oil and gas-producing properties and $2.4 million recorded as expense in the Company’s Consolidated Statement of Income.

 

Restricted Stock Awards

 

The Company granted 157,730, 77,540, and 112,700 restricted stock awards during the years ended December 31, 2008, 2007, and 2006, respectively, to key employees of the Company. The majority of the shares granted will be fully vested at the end of the three-year period commencing with the date of grant. The weighted average fair value of these restricted stock grants, based on the grant date fair value of the Company’s stock, was approximately $59, $44 and $36 for the years ended December 31, 2008, 2007, and 2006, respectively. The total fair value of restricted stock awards vested during the years ended December 31, 2008, 2007, and 2006 was $3.7 million, $6.7 million and $1.5 million, respectively.

 

As of December 31, 2008, there was $6.0 million of total unrecognized compensation cost related to nonvested restricted stock awards. That cost is expected to be recognized over a remaining weighted average vesting term of approximately 23 months.

 

A summary of restricted stock activity as of December 31, 2008, and changes during the year then ended, is presented below:

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

Restricted Stock

 

Non-
Vested
Shares

 

Weighted
Average
Fair Value

 

Weighted
Average
Remaining
Contractual
Term
(months)

 

Aggregate
Fair Value

 

 

 

 

 

 

 

 

 

 

 

Outstanding at January 1, 2008

 

275,350

 

$

37.66

 

 

 

$

10,370,200

 

 

 

 

 

 

 

 

 

 

 

Granted

 

157,730

 

$

58.54

 

 

 

$

9,233,920

 

 

 

 

 

 

 

 

 

 

 

Vested

 

(107,228

)

$

34.66

 

 

 

$

(3,716,035

)

 

 

 

 

 

 

 

 

 

 

Forfeited

 

(19,792

)

$

47.14

 

 

 

$

(932,978

)

 

 

 

 

 

 

 

 

 

 

Outstanding at December 31, 2008

 

306,060

 

$

48.86

 

23

 

$

14,955,107

 

 

Non-Qualified Stock Options

 

In the third quarter of 2008, the Compensation Committee of the Board of Directors approved the grant of 905,700 non-qualified stock options to key employees at a weighted average grant date fair value of $10.32.

 

The fair value of the Company’s option grants was estimated at the dates of grant using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the years ended December 31, 2008, 2007, and 2006. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The dividend yield is based on the historical dividend yield of the Company’s stock. Expected volatilities are based on historical volatility of the Company’s stock. The expected term of options granted represents the period of time that options granted are expected to be outstanding based on historical option exercise experience.

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

Risk-free interest rate

 

3.28%

 

3.99% to 4.97%

 

4.51% to 5.04%

 

Dividend yield

 

1.51%

 

1.77% to 2.29%

 

2.34% to 2.38%

 

Volatility factor

 

.22

 

.15 to .18

 

.21 to .23

 

Expected term

 

5 years

 

3 - 6 years

 

7 years

 

 

The Company granted 905,700, 27,421, and 84,935 stock options during the years ended December 31, 2008, 2007, and 2006, respectively. All of the 2007 and 2006 stock option grants were options granted for reload rights associated with previously-awarded options. The weighted average grant date fair value of these options was $10.32, $7.33 and $9.43 for the years ended December 31, 2008, 2007, and 2006, respectively. The total intrinsic value of options exercised during the years ended December 31, 2008, 2007, and 2006 was $2.3 million, $47.6 million and $52.2 million, respectively.

 

As of December 31, 2008, there was $7.6 million of total unrecognized compensation cost related to outstanding nonvested stock options.

 

A summary of option activity as of December 31, 2008, and changes during the year then ended, is presented below:

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

Non-qualified Stock Options

 

Shares

 

Weighted
Average
Exercise
Price

 

Weighted
Average
Remaining
Contractual
Term

 

Aggregate
Intrinsic
Value

 

Outstanding at January 1, 2008

 

1,629,922

 

$

16.76

 

 

 

 

 

Granted

 

905,700

 

$

48.91

 

 

 

 

 

Exercised

 

(53,701

)

$

16.82

 

 

 

 

 

Forfeited

 

 

$

 

 

 

 

 

Outstanding at December 31, 2008

 

2,481,921

 

$

28.49

 

4.1 years

 

$

27,070,281

 

Exercisable at December 31, 2008

 

1,576,221

 

$

16.75

 

2.6 years

 

$

27,070,281

 

 

Non-employee Directors’ Share-Based Awards

 

At December 31, 2008, 101,500 options were outstanding under the 1999 Non-employee Directors’ Stock Incentive Plan at prices ranging from $7.66 to $19.56 per share. The exercise price for each award is equal to the market price of the Company’s common stock on the date of grant. Each option is subject to time-based vesting provisions and expires 5 to 10 years after date of grant. No options have been granted to non-employee directors since 2002 and all previously granted options are vested.

 

The Company has also historically granted to non-employee directors share-based awards which vest upon award. The value of the share-based awards will be paid in cash on the earlier of the director’s death or retirement from the Company’s Board of Directors. The Company accounts for these awards as liability awards and as such records compensation expense for the remeasurement of the fair value of the awards at the end of each reporting period. A total of 96,956 non-employee director share based awards were outstanding as of December 31, 2008. A total of 12,800, 15,570, and 18,000 share based awards were granted to non-employee directors during the years ended December 31, 2008, 2007, and 2006, respectively. The weighted average fair value of these grants, based on the grant date fair value of the Company’s stock, was $68.22, $49.88 and $35.12 for the years ended December 31, 2008, 2007, and 2006, respectively.

 

Cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2008, 2007, and 2006, was $0.9 million, $3.2 million and $34.9 million, respectively. The actual tax benefits realized for tax deductions from share-based payment arrangements for the years ended December 31, 2008, 2007, and 2006, was $2.2 million, $19.4 million and $18.9 million, respectively.

 

18.                               Fair Value of Financial Instruments

 

The carrying value of cash equivalents and short-term loans approximates fair value due to the short maturity of the instruments. The fair value of the available-for-sale securities is based on quoted market prices for those investments. See Note 4.

 

The estimated fair value of long-term debt described in Note 13 at December 31, 2008 and 2007 was $1,200 million and $777 million, respectively. The fair value was estimated based on discounted values using a current discount rate reflective of the remaining maturity.

 

The estimated fair value of liabilities for derivative instruments described, excluding trading activities which are marked-to-market, was a $188.2 million asset and a $154.6 million liability at December 31, 2008, and a $34.9 million asset and a $489.2 million liability at December 31, 2007. See Note 3 and Note 4.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

19.                               Concentrations of Credit Risk

 

Revenues and related accounts receivable from the EQT Production segment’s operations are generated primarily from the sale of produced natural gas and limited amounts of crude oil to certain marketers, Equitable Energy, LLC (an affiliate), other Appalachian Basin purchasers and utility and industrial customers located mainly in the Appalachian area. For the year ended December 31, 2008, sales to one marketer accounted for approximately 13% of revenues for EQT Production. No customers accounted for more than 10% of revenues in 2007 or 2006. EQT Midstream’s gathering and processing revenues include the sale of produced NGLs to a gas processor in Kentucky and the gathering of natural gas in Kentucky, Virginia, Pennsylvania and West Virginia.

 

The transmission and storage operations of EQT Midstream include FERC-regulated interstate pipeline transportation and storage service for Equitable Distribution, as well as other utility and end-user customers located in the northeastern United States. These operations also provide commodity procurement and delivery, physical natural gas management operations and control and customer support services to energy consumers including large industrial, utility, commercial, institutional and certain marketers primarily in the Appalachian and mid-Atlantic regions.

 

Equitable Distribution’s operating revenues and related accounts receivable are generated primarily from state-regulated distribution natural gas sales and transportation to approximately 275,800 residential, commercial and industrial customers located in southwestern Pennsylvania, northern West Virginia and eastern Kentucky. Equitable Distribution continues to aggressively monitor and analyze various customer-related metrics and their impact on accounts receivable.  The Company employs a firm collections strategy which is comprised of various collections tactics, including termination of service if necessary, as well as outreach to low income customers to provide information regarding energy assistance programs.  The outreach to low income customers includes enrolling customers into the Customer Assistance Program which is an affordable payment plan for low income customers based on a percentage of total household income. This program is subsidized by the Company and recovered through rates charged to other residential customers.

 

Approximately 68% and 65% of the Company’s accounts receivable balance as of December 31, 2008 and 2007, respectively, represent amounts due from marketers. The Company manages the credit risk of sales to marketers by limiting its dealings to those marketers who meet the Company’s criteria for credit and liquidity strength and by proactively monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a marketer in order for that marketer to meet the Company’s credit criteria. As a result, the Company did not experience any significant defaults on sales of natural gas to marketers during the years ended December 31, 2008 and 2007.

 

The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. The Company believes that NYMEX-traded future contracts have minimal credit risk because Commodity Futures Trading Commission regulations are in place to protect exchange participants, including the Company, from any potential financial instability of the exchange members. The Company monitors counterparty credit quality by reviewing counterparty credit spreads, credit ratings, credit default swap rates, and market activity.

 

The Company utilizes various processes and information technology systems to monitor and evaluate its credit risk exposures. This includes closely monitoring current market conditions, counterparty credit spreads and credit default swap rates. Credit exposure is controlled through credit approvals and limits. To manage the level of credit risk, the Company deals with financial counterparties that are of investment grade or better, enters into netting agreements whenever possible, and may obtain collateral or other security.

 

In September 2008, the credit support provider of one counterparty (Lehman Brothers) declared bankruptcy resulting in the default under various derivative contracts with the Company. As a result, those contracts were terminated and a reserve of $5.2 million was recorded against the entire balance due to the Company. There is no additional income statement exposure to Lehman Brothers beyond the reserve recorded in 2008. As of December 31, 2008, the Company is not in default under any derivative contracts and has no knowledge of default by any other

 

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DECEMBER 31, 2008

 

counterparty to derivative contracts. The Company will continue to monitor market conditions that may impact the fair value of derivative contracts reported in the Consolidated Balance Sheet.

 

20.                               Commitments and Contingencies

 

The Company has commitments for demand charges under existing long-term contracts with pipeline suppliers and under binding precedent agreements. Future payments for these items as of December 31, 2008 totaled $1,886.0 million (2009 - $41.8 million, 2010 - $47.9 million, 2011 - $78.2 million, 2012 - $147.7 million, 2013 - $129.5 million and thereafter - $1,440.9 million). The Company believes that approximately $19.4 million of the demand charges are recoverable in customer rates.

 

The Company has agreements with Highlands Drilling, LLC (Highlands) and Patterson UTI Drilling Company, LLC (Patterson) for Highlands and Patterson to provide drilling equipment and services to the Company. These obligations totaled approximately $53.8 million as of December 31, 2008. Operating lease rentals for Highlands and Patterson, office locations (including the new corporate headquarters) and warehouse buildings, as well as a limited amount of equipment, amounted to approximately $40.4 million in 2008, $12.0 million in 2007 and $6.0 million in 2006. Future lease payments under non-cancelable operating leases as of December 31, 2008 totaled $186.6 million (2009 - $32.5 million, 2010 - $30.5 million, 2011 - $16.3 million, 2012 - $8.9 million, 2013 - $8.0 million and thereafter - $90.4 million)

 

Several West Virginia lessors claimed in a suit filed on July 31, 2006 that Equitable Production Company had underpaid royalties on gas produced and marketed from leases. The suit sought compensatory and punitive damages, an accounting and other relief. The plaintiffs later amended their complaint to name Equitable Resources, Inc. as an additional defendant. While the Company believes that it paid the proper royalty, it established a reserve to cover any potential liability. The Company has settled the litigation. The settlement covers all of the Company’s lessors in West Virginia and is subject to court approval. The Company believes the reserve established for royalty matters is sufficient.

 

The Company is subject to various federal, state and local environmental and environmentally related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, certain costs are deferred as regulatory assets when recoverable through regulated rates. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company’s financial position or results of operations. The Company has identified situations that require remedial action for which approximately $1.4 million is included in other credits in the Consolidated Balance Sheet as of December 31, 2008.

 

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 pending litigation, which it believes are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company.

 

21.                               Guarantees

 

NORESCO Guarantees

 

In connection with the sale of its NORESCO domestic operations in December 2005, the Company agreed to maintain in place guarantees of certain of NORESCO’s obligations previously issued to the purchasers of NORESCO’s receivables. The guaranteed obligations of NORESCO include certain receivable sales and customer contracts, for which the undiscounted maximum aggregate payments that may be due is approximately $318 million

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DECEMBER 31, 2008

 

as of December 31, 2008, extending at a decreasing amount for approximately 20 years. In addition, the Company agreed to maintain in place certain outstanding payment and performance bonds, letters of credit and other guarantee obligations supporting NORESCO’s obligations under certain customer contracts, existing leases and other items with an undiscounted maximum exposure to the Company as of December 31, 2008 of approximately $42 million, of which approximately $34 million relates to work already completed under the associated contracts. In addition, approximately $35 million of these guarantee obligations will end or be terminated not later than December 30, 2010.

 

In exchange for the Company’s agreement to maintain these guarantee obligations, the purchaser of the NORESCO business and NORESCO agreed, among other things, that NORESCO would fully perform its obligations under each underlying agreement and agreed to reimburse the Company for any loss under the guarantee obligations, provided that the purchaser’s reimbursement obligation will not exceed $6 million in the aggregate and will expire on November 18, 2014. In 2008, the original purchaser of NORESCO sold its interest in NORESCO and transferred its obligations to a third party. In connection with that event, the new owner is expected to deliver to the Company a $1 million letter of credit supporting its obligations.

 

The Company has determined that the likelihood it will be required to perform on these arrangements is remote and has not recorded any liabilities in its Consolidated Balance Sheet related to these guarantees.

 

Other Guarantees

 

In November 1995, EQT, through a subsidiary, guaranteed a tax indemnification to the limited partners of Appalachian Basin Partners, LP (ABP) for any tax losses resulting from a disallowance of the nonconventional fuels tax credits, if certain representations and warranties of the Company were not true. The Company guaranteed the tax indemnification until the tax statute of limitations closes. The Company does not have any recourse provisions with third parties or any collateral held by third parties associated with this guarantee that could be liquidated to recover amounts paid, if any, under the guarantee. As of December 31, 2008, the maximum potential amount of future payments the Company could be required to make is estimated to be approximately $12 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN 45, and has not been modified subsequent to issuance. Additionally, based on the status of the Company’s IRS examinations, the Company has determined that the likelihood of loss from this guarantee is remote.

 

In December 2000, the Company entered into a transaction with ANGT by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. ANGT manages the assets and produces, markets, and sells the related natural gas from the properties. Appalachian NPI, LLC (ANPI) contributed cash to ANGT. The assets of ANPI, including its interest in ANGT, collateralize ANPI’s debt.

 

The Company has a non-equity interest in a variable interest entity, Appalachian NPI, LLC (ANPI), in which EQT was not deemed to be the primary beneficiary. Thus, ANPI is not consolidated within the Company’s Consolidated Financial Statements. In determining the primary beneficiary, the Company estimated the expected losses and expected residual returns of ANPI under various scenarios in order to identify the party that would absorb the majority of the losses or benefit from the majority of the returns. The primary assumptions utilized in the scenarios included commodity price and production volumes. As of December 31, 2008, ANPI had $181 million of total assets and $227 million of total liabilities (including $102 million of long-term debt, including current maturities), excluding minority interest. ANPI is financed primarily through cash provided by operating activities.

 

The Company provided ANPI with a liquidity reserve guarantee secured by the fair market value of the assets purchased by ANGT. This guarantee is subject to certain restrictions that limit the amount of the guarantee to the calculated present value of the project’s future cash flows from the preceding year-end until the termination date of the agreement. The agreement also defines events of default, use of proceeds and demand procedures. The Company receives a market-based fee for providing the guarantee. As of December 31, 2007, the maximum amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be approximately $22 million. The Company has not recorded a liability for this guarantee as the guarantee was issued prior to the effective date of FIN 45, has not been modified subsequent to issuance and the Company determined that the likelihood it will be required to perform on this arrangement is remote. The terms of this guarantee require

 

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DECEMBER 31, 2008

 

the Company to provide a letter of credit in favor of ANPI as security for its obligations under the liquidity reserve guarantee. The amount of the letter of credit outstanding at December 31, 2008 was approximately $25.8 million and is expected to decline over time under the terms of the liquidity reserve guarantee.

 

22.                               Office Consolidation / Impairment Charges

 

In May 2005, the Company completed the relocation of its corporate headquarters and other operations to a newly constructed office building located at the North Shore in Pittsburgh. The relocation resulted in the early termination of several operating leases and the early retirement of assets and leasehold improvements at several locations. In accordance with SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities (SFAS No. 146), the Company recognized a loss of $5.3 million on the early termination of operating leases during 2005 for facilities deemed to have no economic benefit to the Company. During 2006, the Company began to utilize certain of the leased space previously deemed to have no economic benefit to the Company and reversed approximately $2.4 million of the associated early termination liability for these leases. Additionally, the Company recorded a $0.5 million reduction in the early termination liability during the second quarter of 2006 resulting from a revision of the amount of estimated cash flows for one of its operating leases.

 

23.                               Interim Financial Information (Unaudited)

 

The following quarterly summary of operating results reflects variations due primarily to the seasonal nature of the Company’s distribution and storage businesses and volatility of natural commodity prices.

 

 

 

March 31

 

June 30

 

September 30

 

December 31

 

 

 

(Thousands, except per share amounts)

 

2008 (a)

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

535,774

 

$

334,009

 

$

297,827

 

$

408,878

 

Net operating revenues

 

264,596

 

215,657

 

215,713

 

235,386

 

Operating income

 

119,423

 

101,133

 

162,726

 

81,524

 

Net income

 

70,520

 

55,391

 

96,198

 

33,495

 

Earnings per share of common stock:

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

 

 

 

 

Basic

 

$

0.58

 

$

0.44

 

$

0.74

 

$

0.26

 

Diluted

 

$

0.57

 

$

0.44

 

$

0.73

 

$

0.26

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31

 

June 30(b)

 

September 30

 

December 31

 

 

 

(Thousands, except per share amounts)

 

2007 (a)

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

456,546

 

$

293,240

 

$

226,806

 

$

384,814

 

Net operating revenues

 

236,534

 

176,287

 

158,084

 

216,035

 

Operating income

 

98,854

 

61,519

 

57,368

 

93,932

 

Net income

 

56,618

 

107,343

 

32,925

 

60,597

 

Earnings per share of common stock:

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

 

 

 

 

Basic

 

$

0.47

 

$

0.88

 

$

0.27

 

$

0.50

 

Diluted

 

$

0.46

 

$

0.87

 

$

0.27

 

$

0.49

 

 


(a)          The sum of the quarterly data in some cases may not equal the yearly total due to rounding.

(b)         Amounts for the quarter ended June 30, 2007, include $119.4 million gain on the sale of assets in the Nora area.

 

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DECEMBER 31, 2008

 

24.                               Natural Gas Producing Activities (Unaudited)

 

The supplementary information summarized below presents the results of natural gas and oil activities for the EQT Production segment in accordance with SFAS No. 69, Disclosures About Oil and Gas Producing Activities — an amendment of FASB Statements 19, 25, 33 and 39 (SFAS No. 69).

 

Production Costs

 

The following table presents the costs incurred relating to natural gas and oil production activities (a):

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

At December 31:

 

 

 

 

 

 

 

Capitalized costs

 

$

2,709,162

 

$

2,029,932

 

$

1,752,222

 

Accumulated depreciation and depletion

 

692,327

 

621,881

 

566,118

 

Net capitalized costs

 

2,016,835

 

$

1,408,051

 

$

1,186,104

 

Costs incurred for the years ended December 31:

 

 

 

 

 

 

 

Property acquisition:

 

 

 

 

 

 

 

Proved properties

 

$

1,686

 

$

24,376

 

$

 

Unproved properties

 

83,525

 

 

 

Exploration (b)

 

15,950

 

862

 

802

 

Development (c)

 

599,256

 

298,665

 

200,652

 

 


(a)          Amounts exclude capital expenditures for facilities and information technology.

(b)         Amounts include capitalizable exploratory costs and exploration expense.

(c)          Amounts include $85.7 million, $59.0 million, and $57.2 million of costs incurred during 2008, 2007 and 2006, respectively, to develop the Company’s proved undeveloped reserves. The Company estimates that its future total development costs will be comprised of a similar percentage of costs incurred to develop the Company’s proved undeveloped reserves.

 

Results of Operations for Producing Activities

 

The following table presents the results of operations related to natural gas and oil production for the years ended December 31:

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Revenues:

 

 

 

 

 

 

 

Affiliated

 

$

19,128

 

$

14,368

 

$

14,879

 

Nonaffiliated

 

438,016

 

350,028

 

344,647

 

Production costs

 

78,877

 

61,484

 

62,016

 

Exploration costs

 

9,064

 

862

 

802

 

Depreciation, depletion and accretion

 

78,234

 

62,084

 

53,471

 

Income tax expense

 

110,568

 

91,187

 

92,430

 

Results of operations from producing activities
(excluding corporate overhead)

 

$

180,401

 

$

148,779

 

$

150,807

 

 

Reserve Information

 

The information presented below represents estimates of proved natural gas and oil reserves prepared by Company engineers, which were reviewed by the independent consulting firm of Ryder Scott Company L.P., who is hired by the Company’s management. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. There were no differences between the internally prepared and externally reviewed estimates. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred. Ryder Scott Company L.P. reviewed 100 percent

 

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DECEMBER 31, 2008

 

of the total net gas and liquid hydrocarbon reserves attributable to the Company’s interests as of December 31, 2008. Ryder Scott conducted a detailed, well by well, review of the Company’s largest properties. This review covered 80 percent of the Company’s proved reserves. Ryder Scott’s review of the remaining 20% of the Company’s properties consisted of a review of aggregated groups not exceeding 200 well per group. The review utilized the performance method and the analogy method. Where historical reserve or production data was definitive the performance method, which extrapolates historical data, was utilized. In other cases the analogy method, which calculates reserves based on correlations to comparable surrounding wells, was utilized. All of the Company’s proved reserves are in the United States.

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Millions of Cubic Feet)

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

 

Proved developed and undeveloped reserves:

 

 

 

 

 

 

 

Beginning of year

 

2,669,865

 

2,487,545

 

2,359,200

 

Revision of previous estimates

 

(66,327

)

5,818

 

(20,255

)

Purchase of natural gas in place

 

 

12,185

 

 

Sale of natural gas in place

 

(1,214

)

(74,253

)

(1,418

)

Extensions, discoveries and other additions (a)

 

584,897

 

320,971

 

230,716

 

Production

 

(89,961

)

(82,401

)

(80,698

)

End of year

 

3,097,260

 

2,669,865

 

2,487,545

 

Proved developed reserves:

 

 

 

 

 

 

 

Beginning of year

 

1,746,095

 

1,715,775

 

1,666,990

 

End of year

 

1,881,767

 

1,746,095

 

1,715,775

 

 

 

 

 

 

 

 

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands of Bbls)

 

Oil (b)

 

 

 

 

 

 

 

Proved developed and undeveloped reserves:

 

 

 

 

 

 

 

Beginning of year

 

2,091

 

1,635

 

1,008

 

Revision of previous estimates

 

138

 

551

 

739

 

Purchase of oil in place

 

 

24

 

 

Sale of oil in place

 

 

 

 

Production

 

(104

)

(119

)

(112

)

End of year

 

2,125

 

2,091

 

1,635

 

Proved developed reserves:

 

 

 

 

 

 

 

Beginning of year

 

2,091

 

1,635

 

1,008

 

End of year

 

2,125

 

2,091

 

1,635

 

 


(a)          Includes 243,870 MMcf, 122,169 MMcf and 59,374 MMcf of proved developed reserve extensions, discoveries and other additions during 2008, 2007 and 2006, respectively, which were not previously classified as proved undeveloped. The remaining balance represents additional proved undeveloped reserves.

(b)         One thousand Bbl equals approximately 6 MMcf.

 

During 2008, the Company recorded downward revisions of 65.5 Bcfe to the December 31, 2007 estimates of its reserves due to decreased prices and other revisions. The reserves were computed using a $ $41.85 per Bbl price at December 31, 2008, the Columbia Gas Transmission Corp. 2008 year-end price of $6.095 per Dth, and the Dominion Transmission, Inc. 2008 year-end price of $6.225 per Dth. The Company’s 2008 extensions, discoveries and other additions, resulting from extensions of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 584.9 Bcfe exceeded the 2008 production of 90.6 Bcfe.

 

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DECEMBER 31, 2008

 

During 2007, the Company sold to Pine Mountain Oil and Gas, Inc., 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 Company purchased an additional working interest of approximately 13.5% in certain gas properties in the Roaring Fork area totaling 12.3 Bcf of proved reserves. During 2007, the Company recorded upward revisions of 9.1 Bcfe to the December 31, 2006 estimates of its reserves due to increased prices and other revisions. The reserves were computed using a $93.28 per Bbl price at December 31, 2007, the Columbia Gas Transmission Corp. 2007 year-end price of $7.030 per Dth, and the Dominion Transmission, Inc. 2007 year-end price of $7.200 per Dth. The company’s 2007 extensions, discoveries and other additions, resulting from extensions of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 321.0 Bcfe exceeded the 2007 production of 83.1 Bcfe.

 

During 2006, the Company recorded downward revisions of 15.8 Bcfe to the December 31, 2005 estimates of its reserves due to decreased prices and other revisions. The reserves were computed using a $58.40 per Bbl price at December 31, 2006 the Columbia Gas Transmission Corp. 2006 year-end price of $5.625 per Dth, and the Dominion Transmission, Inc. 2006 year-end price of $5.765 per Dth. The Company’s 2006 extensions, discoveries and other additions, resulting from extensions of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 230.7 Bcfe exceeded the 2006 production of 81.4 Bcfe.

 

Standard Measure of Discounted Future Cash Flow

 

Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.

 

Estimated future net cash flows from natural gas and oil reserves based on selling prices and costs at year-end price levels are as follows at December 31:

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Future cash inflows (a)

 

$

16,600,260

 

$

17,546,789

 

$

13,260,521

 

Future production costs

 

(3,532,686

)

(3,488,772

)

(2,738,366

)

Future development costs

 

(1,959,482

)

(1,286,924

)

(989,549

)

Future net cash flow before income taxes

 

11,108,092

 

12,771,093

 

9,532,606

 

10% annual discount for estimated timing of cash flows

 

(7,862,712

)

(8,782,137

)

(6,539,463

)

Discounted future net cash flows before income taxes

 

3,245,380

 

3,988,956

 

2,993,143

 

Future income tax expenses, discounted at 10% annually

 

(1,233,245

)

(1,515,803

)

(1,137,394

)

Standardized measure of discounted future net cash flows

 

$

2,012,135

 

$

2,473,153

 

$

1,855,749

 

 


(a)  The majority of the Company’s production is sold through liquid trading points on interstate pipelines.

Accordingly, the price of gas on these pipelines was determined using the year-end prices published in the December 31, 2008 edition of Platts Gas Daily (Columbia Gas Transmission Corp. 2008 year-end price was $6.095 per Dth; Dominion Transmission, Inc. 2008 year-end price was $6.225 per Dth).

 

Holding production and development costs constant, a change in price of $1 per Dth for natural gas and $10 per barrel for oil would result in a change in the December 31, 2008 discounted future net cash flows before income taxes of the Company’s proved reserves of approximately $1,042 million and $7 million, respectively.

 

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DECEMBER 31, 2008

 

Summary of changes in the standardized measure of discounted future net cash flows for the years ended December 31:

 

 

 

2008

 

2007

 

2006

 

 

 

(Thousands)

 

Sales and transfers of natural gas and oil produced — net

 

$

(378,267

)

$

(331,448

)

$

(315,132

)

Net changes in prices, production and development costs

 

(1,861,454

)

356,045

 

(5,710,391

)

Extensions, discoveries and improved recovery, less related costs

 

611,555

 

478,232

 

276,804

 

Development costs incurred

 

219,601

 

129,753

 

110,023

 

Purchase of minerals in place — net

 

 

18,370

 

 

Sale of minerals in place — net

 

(1,809

)

(89,085

)

(4,560

)

Revisions of previous quantity estimates

 

(68,776

)

13,507

 

(18,977

)

Accretion of discount

 

398,849

 

289,942

 

759,813

 

Net change in income taxes

 

282,558

 

(378,409

)

1,471,631

 

Other

 

336,725

 

130,497

 

293,510

 

Net increase (decrease)

 

(461,018

)

617,404

 

(3,137,279

)

Beginning of year

 

2,473,153

 

1,855,749

 

4,993,028

 

End of year

 

$

2,012,135

 

$

2,473,153

 

$

1,855,749

 

 

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Item 9.                     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

Not Applicable.

 

Item 9A.            Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

Under the supervision and with the participation of management, including the Company’s Principal Executive Officer and Principal Financial Officer, an evaluation of the Company’s disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act), was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report.

 

Changes in Internal Control over Financial Reporting

 

There were no changes in internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

Management’s Report on Internal Control over Financial Reporting

 

The management of EQT is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)). EQT’s internal control system is designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.

 

EQT’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2008.

 

Ernst & Young LLP, the independent registered public accounting firm that audited the Company’s Consolidated Financial Statements, has issued an attestation report on the Company’s internal control over financial reporting. Ernst & Young’s attestation report on the Company’s internal control over financial reporting appears in Part II, Item 8 of this Annual report on Form 10-K and is incorporated by reference herein.

 

Item 9B.            Other Information

 

Not Applicable.

 

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PART III

 

Item 10.              Directors, Executive Officers and Corporate Governance

 

The following information is incorporated herein by reference from the Company’s definitive proxy statement relating to the annual meeting of the shareholders to be held on April 22, 2009, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2008:

 

·                  Information required by Item 401 of Regulation S-K with respect to directors is incorporated herein by reference from the sections captioned “Item No. 1 - Election of Directors,” “Nominees to Serve for a Three-Year Term Expiring in 2012”, “Directors Whose Terms Expire in 2011,” “Directors Whose Terms Expire in 2010” and “Corporate Governance and Board Matters” in the Company’s definitive proxy statement;

 

·                  Information required by Item 405 of Regulation S-K with respect to compliance with Section 16(a) of the Exchange Act is incorporated herein by reference from the section captioned “Stock Ownership — Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive proxy statement;

 

·                  Information required by Item 407(d)(4) of Regulation S-K with respect to disclosure of the existence of the Company’s separately designated standing Audit Committee and the identification of the members of the Audit Committee is incorporated herein by reference from the section captioned “Corporate Governance and Board Matters - Meetings of the Board of Directors and Committee Membership-Audit Committee” in the Company’s definitive proxy statement; and

 

·                  Information required by Item 407(d)(5) of Regulation S-K with respect to disclosure of audit committee financial expert is incorporated herein by reference from the section captioned “Meetings of the Board of Directors and Committee Membership-Audit Committee” in the Company’s definitive proxy statement.

 

Information required by Item 401 of Regulation S-K with respect to executive officers is included after Item 4 at the end of Part I of this Form 10-K under the heading “Executive Officers of the Registrant (as of February 20, 2009),” and is incorporated herein by reference.

 

The Company has adopted a code of ethics applicable to all directors and employees, including the principal executive officer, principal financial officer and principal accounting officer. The code of ethics is posted on the Company’s website, http://www.eqt.com (accessible through the “Corporate Governance” link on the main page or under the “Corporate Governance” caption of the Investor page) and a printed copy will be delivered on request by writing to the corporate secretary at EQT Corporation, c/o corporate secretary, 225 North Shore Drive, Pittsburgh, Pennsylvania 15212. The Company intends to satisfy the disclosure requirement regarding certain amendments to, or waivers from, provisions of its code of ethics by posting such information on the Company’s website.

 

By certification dated May 19, 2008, the Company’s Chief Executive Officer certified to the New York Stock Exchange (NYSE) that he was not aware of any violation by the Company of the NYSE corporate governance listing standards.

 

Item 11.              Executive Compensation

 

The following information is incorporated herein by reference from the Company’s definitive proxy statement relating to the annual meeting of the shareholders to be held on April 22, 2009, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2008:

 

·                  Information required by Item 402 of Regulation S-K with respect to executive and director compensation is incorporated herein by reference from the sections captioned “Executive Compensation” and “Directors’ Compensation” in the Company’s definitive proxy statement; and

 

·                  Information required by paragraphs (e)(4) and (e)(5) of Item 407 of Regulation S-K with respect to certain matters related to the Compensation Committee is incorporated herein by reference from the sections

 

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captioned “Corporate Governance and Board Matters — Compensation Committee Interlocks and Insider Participation” and “Report of the Compensation Committee” in the Company’s definitive proxy statement.

 

Item 12.              Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

Information required by Item 403 of Regulation S-K with respect to stock ownership of significant shareholders, directors and executive officers is incorporated herein by reference to the section captioned “Stock Ownership - Significant Shareholders” and “Stock Ownership - Stock Ownership of Directors and Executive Officers” in the Company’s definitive proxy statement relating to the annual meeting of shareholders to be held on April 22, 2009, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2008.

 

Information required by Item 201(d) of Regulation S-K with respect to shares of EQT’s common stock that may be issued under the Company’s existing equity compensation plans is incorporated herein by reference to the sections captioned “Executive Compensation -Equity Compensation Plan Information” in the Company’s definitive proxy statement relating to the annual meeting of shareholders to be held on April 22, 2009, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2008.

 

Item 13.              Certain Relationships and Related Transactions, and Director Independence

 

Information required by Items 404 and 407(a) of Regulation S-K is incorporated herein by reference to the sections captioned “Corporate Governance and Board Matters - Director Independence” and “Corporate Governance and Board Matters - Certain Relationships and Related Transactions” in the Company’s definitive proxy statement relating to the annual meeting of shareholders to be held on April 22, 2009, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2008.

 

Item 14.              Principal Accounting Fees and Services

 

Information required by Item 9(e) of Schedule 14A is incorporated herein by reference to the section captioned “Item No. 2 — Ratification of Appointment of Independent Registered Public Accounting Firm” in the Company’s definitive proxy statement relating to the annual meeting of stockholders to be held on April 22, 2009, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2008.

 

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PART IV

 

Item 15.              Exhibits and Financial Statement Schedules

 

(a)

1.

Financial Statements

 

 

The financial statements listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K.

 

 

 

 

2.

Financial Statement Schedule

 

 

The financial statement schedule listed in the accompanying index to financial statements and financial schedule is filed as part of this Annual Report on Form 10-K.

 

 

 

 

3.

Exhibits

 

 

The exhibits listed on the accompanying index to exhibits (pages 109 through 115) are filed as part of this Annual Report on Form 10-K.

 

EQT CORPORATION

 

INDEX TO FINANCIAL STATEMENTS COVERED

BY REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

 

Item 15 (a)

 

1.                                       The following Consolidated Financial Statements of EQT Corporation and Subsidiaries are included in Item 8:

 

 

 

Page Reference

 

 

 

Statements of Consolidated Income for each of the three years in the period ended
December 31, 2008

 

58

Statements of Consolidated Cash Flows for each of the three years in the period ended
December 31, 2008

 

59

Consolidated Balance Sheets as of December 31, 2008 and 2007

 

60

Statements of Common Stockholders’ Equity for each of the three years in the period ended
December 31, 2008

 

62

Notes to Consolidated Financial Statements

 

63

 

 

 

2.

Schedule for the Years Ended December 31, 2008, 2007 and 2006 included in Part IV:

 

 

II — Valuation and Qualifying Accounts and Reserves

 

108

 

All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.

 

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EQT CORPORATION AND SUBSIDIARIES
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

FOR THE THREE YEARS ENDED DECEMBER 31, 2008

 

Column A

 

Column B

 

Column C

 

Column D

 

Column E

 

Description

 

Balance at
Beginning
of Period

 

Additions
Charged to
Costs and
Expenses

 

Additions
Charged to
Other
Accounts (a)

 

Deductions
(b)

 

Balance at
End of
Period

 

 

 

(Thousands)

 

Allowance for doubtful accounts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2008

 

$

19,829

 

$

11,744

 

$

 

$

4,937

 

$

26,636

 

 

 

 

 

 

 

 

 

 

 

 

 

2007

 

$

20,442

 

$

353

 

$

7,041

 

$

8,007

 

$

19,829

 

 

 

 

 

 

 

 

 

 

 

 

 

2006

 

$

23,329

 

$

4,715

 

$

4,589

 

$

12,191

 

$

20,442

 

 


Note:

 

(a)                       CAP surcharge included in residential rates.

(b)                      Customer accounts written off, less recoveries.

 

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INDEX TO EXHIBITS

 

Exhibits

 

Description

 

Method of Filing

2.01

 

Stock Purchase Agreement dated as of March 1, 2006 between Equitable Resources, Inc. and Dominion Resources, Inc. (as successor by merger to Consolidated Natural Gas Company). Schedules (or similar attachments) to the Stock Purchase Agreement are not filed. The Registrant will furnish supplementally a copy of any omitted schedule to the Commission upon request.

 

Filed as Exhibit 2.1 to Form 8-K filed on March 3, 2006

 

 

 

 

 

2.02

 

Letter agreement dated as of July 3, 2007 between Equitable Resources, Inc. and Dominion Resources, Inc. (as successor by merger to Consolidated Natural Gas Company)

 

Filed as Exhibit 2.1 to Form 10-Q for the quarter ended June 30, 2007

 

 

 

 

 

2.03

 

Mutual Termination Agreement dated as of January 15, 2008 between Equitable Resources, Inc. and Dominion Resources, Inc. (as successor by merger to Consolidated Natural Gas Company)

 

Filed as Exhibit 10.1 to Form 8-K filed on January 17, 2008

 

 

 

 

 

3.01

 

Restated Articles of Incorporation (amended through February 9, 2009)

 

Filed as Exhibit 3.1 to Form 8-K filed on February 9, 2009

 

 

 

 

 

3.02

 

By-Laws of Equitable Resources, Inc. (amended through February 9, 2009)

 

Filed as Exhibit 3.2 to Form 8-K filed on February 9, 2009

 

 

 

 

 

4.01(a)

 

Indenture dated as of April 1, 1983 between the Company and Pittsburgh National Bank

 

Filed as Exhibit 4.1(a) to Form 10-K for the year ended December 31, 2008

 

 

 

 

 

4.01(b)

 

Instrument appointing Bankers Trust Company as successor trustee to Pittsburgh National Bank

 

Filed as Exhibit 4.01(b) to Form 10-K for the year ended December 31, 1998

 

 

 

 

 

4.01(c)

 

Supplemental Indenture dated as of March 15, 1991 with Bankers Trust Company eliminating limitations on liens and additional funded debt

 

Filed as Exhibit 4.01(f) to Form 10-K for the year ended December 31, 1996

 

 

 

 

 

4.01(d)

 

Resolution adopted August 19, 1991 by the Ad Hoc Finance Committee of the Board of Directors of the Company Addenda Nos. 1 through 27, establishing the terms and provisions of the Series A Medium-Term Notes

 

Filed as Exhibit 4.01(g) to Form 10-K for the year ended December 31, 1996

 

 

 

 

 

4.01(e)

 

Resolutions adopted July 6, 1992 and February 19, 1993 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 through 8, establishing the terms and provisions of the Series B Medium-Term Notes

 

Filed as Exhibit 4.01(h) to Form 10-K for the year ended December 31, 1997

 

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)

 

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Exhibits

 

Description

 

Method of Filing

4.01(f)

 

Resolution adopted July 14, 1994 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 and 2, establishing the terms and provisions of the Series C Medium-Term Notes

 

Filed as Exhibit 4.01(i) to Form 10-K for the year ended December 31, 1995

 

 

 

 

 

4.01(g)

 

Supplemental Indenture dated as of June 30, 2008 between Equitable Resources, Inc. and Deutsche Bank Trust Company Americas

 

Field as Exhibit 4.01(g) to Form 8-K filed on July 1, 2008

 

 

 

 

 

4.02(a)

 

Indenture with The Bank of New York, as successor to Bank of Montreal Trust Company, as Trustee, dated as of July 1, 1996

 

Filed as Exhibit 4.01(a) to Form S-4 Registration Statement (#333-103178) filed on February 13, 2003

 

 

 

 

 

4.02(b)

 

Resolution adopted January 18 and July 18, 1996 by the Board of Directors of the Company and Resolutions adopted July 18, 1996 by the Executive Committee of the Board of Directors of the Company, establishing the terms and provisions of the 7.75% Debentures issued July 29, 1996

 

Filed as Exhibit 4.01(j) to Form 10-K for the year ended December 31, 1996

 

 

 

 

 

4.02(c)

 

Officer’s Declaration dated as of February 20, 2003 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000

 

Filed as Exhibit 4.01(c) to Form S-4 Registration Statement (#333-104392) filed on April 8, 2003

 

 

 

 

 

4.02(d)

 

Officer’s Declaration dated as of November 7, 2002 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000

 

Filed as Exhibit 4.01(c) to Form S-4/A Registration Statement (#333-103178) filed on March 12, 2003

 

 

 

 

 

4.02(e)

 

Officer’s Declaration dated as of September 27, 2005 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of $150,000,000

 

Filed as Exhibit 4.01(b) to Form S-4 Registration Statement (#333-104392) filed on October 28, 2005

 

 

 

 

 

4.02(f)

 

Supplemental Indenture dated as of June 30, 2008 between Equitable Resources, Inc. and The Bank of New York

 

Filed as Exhibit 4.02(f) to Form 8-K filed on July 1, 2008

 

 

 

 

 

4.03(a)

 

Indenture dated as of March 18, 2008 between Equitable Resources, Inc. and The Bank of New York, as Trustee

 

Filed as Exhibit 4.1 to Form 8-K filed on March 18, 2008

 

 

 

 

 

4.03(b)

 

First Supplemental Indenture (including the form of senior note) dated as of March 18, 2008 between Equitable Resources, Inc. and The Bank of New York, as Trustee, pursuant to which the 6.5% Senior Notes due 2018 were issued

 

Filed as Exhibit 4.2 to Form 8-K filed on March 18, 2008

 

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)

 

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Exhibits

 

Description

 

Method of Filing

 

 

 

 

 

4.03(c)

 

Second Supplemental Indenture dated as of June 30, 2008 between Equitable Resources, Inc. and The Bank of New York

 

Filed as Exhibit 4.03(c) to Form 8-K filed on July 1, 2008

 

 

 

 

 

* 10.01(a)

 

1999 Equitable Resources, Inc. Long-Term Incentive Plan (amended and restated December 3, 2008)

 

Filed herewith as Exhibit 10.01(a)

 

 

 

 

 

* 10.01(b)

 

Form of Participant Award Agreement (Restricted Stock) under 1999 Equitable Resources, Inc. Long-Term Incentive Plan (2007 and later)

 

Filed as Exhibit 10.01(b) to Form 10-K for the year ended December 31, 2006

 

 

 

 

 

* 10.01(c)

 

Form of Participant Award Agreement (Restricted Stock) under 1999 Equitable Resources, Inc. Long-Term Incentive Plan (Pre-2007)

 

Filed as Exhibit 10.05 to Form 10-K for the year ended December 31, 2004

 

 

 

 

 

* 10.01(d)

 

Form of Participant Award Agreement (Stock Option) under 1999 Equitable Resources, Inc. Long-Term Incentive Plan (Pre-2007)

 

Filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2004

 

 

 

 

 

* 10.01(e)

 

Form of Participant Award Agreement (Stock Option) under the 1999 Long-Term Incentive Plan (post 2007)

 

Filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2008

 

 

 

 

 

* 10.01(f)

 

Equitable Resources, Inc. 2005 Executive Performance Incentive Program

 

Filed as Exhibit 10.01 to Form 8-K filed on March 1, 2005

 

 

 

 

 

* 10.01(g)

 

Form of Participant Award Agreement under the Equitable Resources, Inc. 2005 Executive Performance Incentive Program

 

Filed as Exhibit 10.02 to Form 8-K filed on March 1, 2005

 

 

 

 

 

* 10.01(h)

 

Equitable Resources, Inc. 2007 Supply Long-Term Incentive Program

 

Filed herewith as Exhibit 10.01(h)

 

 

 

 

 

* 10.01(i)

 

Form of Participant Award Agreement under the Equitable Resources, Inc. 2007 Supply Long-Term Incentive Program

 

Filed herewith as Exhibit 10.01(i)

 

 

 

 

 

* 10.01(j)

 

Equitable Resources, Inc. 2008 Executive Performance Incentive Program

 

Filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2008

 

 

 

 

 

* 10.01(k)

 

Form of Participant Award Agreement under the Equitable Resources, Inc. 2008 Executive Performance Incentive Program

 

Filed as Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2008

 

 

 

 

 

* 10.01(l)

 

Equitable Resources, Inc. 2009 Shareholder Value Plan

 

Filed herewith as Exhibit 10.01(l)

 

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)

 

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Exhibits

 

Description

 

Method of Filing

* 10.01(m)

 

Form of Participant Award Agreement under the Equitable Resources, Inc. 2009 Shareholder Value Plan

 

Filed herewith as Exhibit 10.01(m)

 

 

 

 

 

* 10.02(a)

 

1999 Equitable Resources, Inc. Non-Employee Directors’ Stock Incentive Plan (as amended and restated December 3, 2008)

 

Filed herewith as Exhibit 10.02(a)

 

 

 

 

 

* 10.02(b)

 

Form of Participant Award Agreement (Stock Option) under 1999 Equitable Resources, Inc. Non-Employee Directors’ Stock Incentive Plan

 

Filed as Exhibit 10.04(b) to Form 10-K for the year ended December 31, 2006

 

 

 

 

 

* 10.02(c)

 

Form of Participant Award Agreement (Phantom Units Award) under 1999 Equitable Resources, Inc. Non-Employee Directors’ Stock Incentive Plan

 

Filed as Exhibit 10.04(c) to Form 10-K for the year ended December 31, 2006

 

 

 

 

 

* 10.03

 

Equitable Resources, Inc. Executive Short-Term Incentive Plan (as amended and restated December 3, 2008)

 

Filed herewith as Exhibit 10.03

 

 

 

 

 

* 10.04

 

Equitable Resources, Inc. 2005 Short-Term Incentive Plan

 

Filed as Exhibit 10.1 to Form 8-K filed on December 6, 2004

 

 

 

 

 

* 10.05

 

Equitable Resources, Inc. 2006 Payroll Deduction and Contribution Program (as amended and restated December 3, 2008)

 

Filed herewith as Exhibit 10.05

 

 

 

 

 

* 10.06

 

Equitable Resources, Inc. Directors’ Deferred Compensation Plan (as amended and restated May 15, 2003)

 

Filed as Exhibit 10.10 to Form 10-Q for the quarter ended June 30, 2003

 

 

 

 

 

* 10.07

 

Equitable Resources, Inc. 2005 Directors’ Deferred Compensation Plan (as amended and restated December 3, 2008)

 

Filed herewith as Exhibit 10.07

 

 

 

 

 

* 10.8(a)

 

Agreement dated as of September 23, 2008 with Murry S. Gerber

 

Filed as Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2008

 

 

 

 

 

* 10.8(b)

 

Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and Murry S. Gerber

 

Filed as Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2008

 

 

 

 

 

* 10.8(c)

 

Change of Control Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and Murry S. Gerber

 

Filed as Exhibit 10.6 to Form 10-Q for the quarter ended September 30, 2008

 

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)

 

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Exhibits

 

Description

 

Method of Filing

* 10.9(a)

 

Agreement dated as of September 23, 2008 with David L. Porges

 

Filed as Exhibit 10.7 to Form 10-Q for the quarter ended September 30, 2008

 

 

 

 

 

* 10.9(b)

 

Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and David L. Porges

 

Filed as Exhibit 10.8 to Form 10-Q for the quarter ended September 30, 2008

 

 

 

 

 

* 10.9(c)

 

Change of Control Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and David L. Porges

 

Filed as Exhibit 10.9 to Form 10-Q for the quarter ended September 30, 2008

 

 

 

 

 

* 10.10(a)

 

Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and Philip P. Conti

 

Filed as Exhibit 10.10 to Form 10-Q for the quarter ended September 30, 2008

 

 

 

 

 

* 10.10(b)

 

Change of Control Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and Philip P. Conti

 

Filed as Exhibit 10.11 to Form 10-Q for the quarter ended September 30, 2008

 

 

 

 

 

* 10.11(a)

 

Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and Theresa Z. Bone

 

Filed herewith as Exhibit 10.11(a)

 

 

 

 

 

* 10.11(b)

 

Change of Control Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and Theresa Z. Bone

 

Filed herewith as Exhibit 10.11(b)

 

 

 

 

 

* 10.12(a)

 

Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and Randall L. Crawford

 

Filed as Exhibit 10.12 to Form 10-Q for the quarter ended September 30, 2008

 

 

 

 

 

* 10.12(b)

 

Change of Control Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and Randall L. Crawford

 

Filed as Exhibit 10.13 to Form 10-Q for the quarter ended September 30, 2008

 

 

 

 

 

* 10.13(a)

 

Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and Lewis B. Gardner

 

Filed herewith as Exhibit 10.13(a)

 

 

 

 

 

* 10.13(b)

 

Change of Control Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and Lewis B. Gardner

 

Filed herewith as Exhibit 10.13(b)

 

 

 

 

 

* 10.14

 

Employment Agreement dated as of October 31, 2008 between Equitable Resources, Inc. and Joseph E. O’Brien.

 

Filed as Exhibit 10.1 to Form 8-K filed on November 6, 2008

 

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)

 

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Exhibits

 

Description

 

Method of Filing

 

 

 

 

 

* 10.15

 

Employment Agreement dated as of March 14, 2008 between Equitable Resources, Inc. and Johanna G. O’Loughlin

 

Filed as Exhibit 10.1 to Form 8-K filed on March 20, 2008

 

 

 

 

 

* 10.16(a)

 

Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and Steven T. Schlotterbeck

 

Filed herewith as Exhibit 10.16(a)

 

 

 

 

 

* 10.16(b)

 

Change of Control Agreement dated as of September 8, 2008 between Equitable Resources, Inc. and Steven T. Schlotterbeck

 

Filed herewith as Exhibit 10.16(b)

 

 

 

 

 

* 10.16(c)

 

Horizontal Drilling Special Grant Award Letters dated as of May 17, 2006 and August 22, 2008 between Equitable Resources, Inc., and Steven T. Schlotterbeck

 

Filed herewith as Exhibit 10.16(c)

 

 

 

 

 

* 10.17(a)

 

Agreement dated as of May 24, 1996 with Phyllis A. Domm for deferred payment of 1996 director fees beginning May 24, 1996

 

Filed as Exhibit 10.14(a) to Form 10-K for the year ended December 31, 1996

 

 

 

 

 

* 10.17(b)

 

Agreement dated as of November 27, 1996 with Phyllis A. Domm for deferred payment of 1997 director fees

 

Filed as Exhibit 10.14(b) to Form 10-K for the year ended December 31, 1996

 

 

 

 

 

* 10.17(c)

 

Agreement dated as of November 30, 1997 with Phyllis A. Domm for deferred payment of 1998 director fees

 

Filed as Exhibit 10.14(c) to Form 10-K for the year ended December 31, 1997

 

 

 

 

 

* 10.17(d)

 

Agreement dated as of December 5, 1998 with Phyllis A. Domm for deferred payment of 1999 director fees

 

Filed as Exhibit 10.20(d) to Form 10-K for the year ended December 31, 1998

 

 

 

 

 

* 10.18

 

Form of Indemnification Agreement between Equitable Resources, Inc. and all executive officers and outside directors

 

Filed herewith as Exhibit 10.18

 

 

 

 

 

* 10.19

 

Directors’ Compensation

 

Filed herewith as Exhibit 10.19

 

 

 

 

 

10.20(a)

 

Revolving Credit Agreement, dated as of October 27, 2006, among the Company, Bank of America, N.A., as Administrative Agent, Swing Line Lender and a Letter of Credit Issuer, JPMorgan Chase Bank, N.A., as Syndication Agent and a Letter of Credit Issuer, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Houston Agency, Citibank, N.A., and PNC Bank, National Association, as Co-Documentation Agents, and other lender parties thereto.

 

Filed as Exhibit 10.1 to Form 8-K filed on October 30, 2006

 

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)

 

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Exhibits

 

Description

 

Method of Filing

 

 

 

 

 

10.20(b)

 

Assignment and Assumption Agreement and Amendment to Credit Agreement, among Equitable Resources, Inc., a Pennsylvania corporation formed in 1926, Equitable Resources, Inc., a Pennsylvania corporation formed in 2008 and Bank of America, N.A.

 

Filed as Exhibit 10.23(b) to Form 8-K filed on July 1, 2008

 

 

 

 

 

10.21

 

Purchase and Sale Agreement dated as of April 13, 2007 between Equitable Production Company and Pine Mountain Oil and Gas, Inc.

 

Filed as Exhibit 10.1 to Form 8-K filed on April 16, 2007

 

 

 

 

 

10.22

 

Contribution Agreement dated as of April 13, 2007 between Equitable Production Company and Pine Mountain Oil and Gas, Inc.

 

Filed as Exhibit 10.2 to Form 8-K filed on April 16, 2007

 

 

 

 

 

10.23

 

Agreement and Plan of Merger

 

Filed as Exhibit 10.24(a) to Form 8-K filed on July 1, 2008

 

 

 

 

 

10.24

 

Assignment and Assumption Agreement (for Benefit Plans)

 

Filed as Exhibit 10.24(b) to Form 8-K filed on July 1, 2008

 

 

 

 

 

10.25

 

Master Assignment, Assumption and Acknowledgment Agreement

 

Filed as Exhibit 10.24(c) to Form 8-K filed on July 1, 2008

 

 

 

 

 

21

 

Schedule of Subsidiaries

 

Filed herewith as Exhibit 21

 

 

 

 

 

23.01

 

Consent of Independent Registered Public Accounting Firm

 

Filed herewith as Exhibit 23.01

 

 

 

 

 

23.02

 

Consent of Independent Petroleum Engineers

 

Filed herewith as Exhibit 23.02

 

 

 

 

 

31.1

 

Rule 13(a)-14(a) Certification of Principal Executive Officer

 

Filed herewith as Exhibit 31.1

 

 

 

 

 

31.2

 

Rule 13(a)-14(a) Certification of Principal Financial Officer

 

Filed herewith as Exhibit 31.2

 

 

 

 

 

32

 

Section 1350 Certification of Principal Executive Officer and Principal Financial Officer

 

Filed herewith as Exhibit 32

 

The Company agrees to furnish to the Commission, upon request, copies of instruments with respect to long-term debt, which have not previously been filed.

 

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*)

 

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SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

 

EQT CORPORATION

 

 

 

 

 

By:

/s/    MURRY S. GERBER

 

 

Murry S. Gerber

 

 

Chairman and Chief Executive Officer

 

 

February 18, 2009

 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

 

/s/   MURRY S. GERBER

 

Chairman and

 

February 18, 2009

 

Murry S. Gerber

 

Chief Executive Officer

 

 

(Principal Executive Officer)

 

 

 

 

 

 

 

 

 

 

 

/s/   PHILIP P. CONTI

 

Senior Vice President

 

February 18, 2009

 

Philip P. Conti

 

and Chief Financial Officer

 

 

(Principal Financial Officer)

 

 

 

 

 

 

 

 

 

 

 

/s/   THERESA Z. BONE

 

Vice President

 

February 18, 2009

 

Theresa Z. Bone

 

and Corporate Controller

 

 

(Principal Accounting Officer)

 

 

 

 

 

 

 

 

 

 

 

/s/   VICKY A. BAILEY

 

Director

 

February 18, 2009

 

Vicky A. Bailey

 

 

 

 

 

 

 

 

 

 

 

/s/   PHILIP G. BEHRMAN

 

Director

 

February 18, 2009

 

Philip G. Behrman

 

 

 

 

 

 

 

 

 

 

 

/s/   A. BRAY CARY, JR.

 

Director

 

February 18, 2009

 

A. Bray Cary, Jr.

 

 

 

 

 

 

 

 

 

 

 

/s/   PHYLLIS A. DOMM

 

Director

 

February 18, 2009

 

Phyllis A. Domm

 

 

 

 

 

 

 

 

 

 

 

/s/   BARBARA S. JEREMIAH

 

Director

 

February 18, 2009

 

Barbara S. Jeremiah

 

 

 

 

 

 

 

 

 

 

 

/s/   GEORGE L. MILES, JR.

 

Director

 

February 18, 2009

 

George L. Miles, Jr.

 

 

 

 

 

 

 

 

 

 

 

/s/   DAVID L. PORGES

 

President,

 

February 18, 2009

 

David L. Porges

 

Chief Operating Officer

 

 

 

 

 

and Director

 

 

 

 

 

 

 

 

 

/s/   JAMES E. ROHR

 

Director

 

February 18, 2009

 

James E. Rohr

 

 

 

 

 

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/s/   DAVID S. SHAPIRA

 

Director

 

February 18, 2009

 

David S. Shapira

 

 

 

 

 

 

 

 

 

 

 

/s/   LEE T. TODD, JR.

 

Director

 

February 18, 2009

 

Lee T. Todd, Jr.

 

 

 

 

 

 

 

 

 

 

 

/s/   JAMES W. WHALEN

 

Director

 

February 18, 2009

 

James W. Whalen

 

 

 

 

 

117