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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, 2010

or

[   ] 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)

 

625 Liberty Avenue

Pittsburgh, Pennsylvania

(Address of principal executive offices)

 

(IRS Employer Identification No.)

 

15222

(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 ___

 

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  ___   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 ___

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes    X    No ___

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   [X]

 

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

Large accelerated filer    X  

Accelerated filer ___

Non-accelerated filer ___

Smaller reporting company ___

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes  ___   No   X

 

The aggregate market value of voting stock held by non-affiliates of the registrant

as of June 30, 2010:  $5,389,512,917

 

The number of shares of common stock outstanding

as of January 31, 2011:  149,171,339

 

DOCUMENTS INCORPORATED BY REFERENCE

 

The Company’s definitive proxy statement relating to the annual meeting of shareowners (to be held May 10, 2011) will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2010 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

20

Item 2

Properties

20

Item 3

Legal Proceedings

23

Item 4

Submission of Matters to a Vote of Security Holders

24

 

Executive Officers of the Registrant

25

 

 

 

PART II

 

 

 

Item 5

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

26

Item 6

Selected Financial Data

28

Item 7

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

28

Item 7A

Quantitative and Qualitative Disclosures About Market Risk

51

Item 8

Financial Statements and Supplementary Data

54

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 in 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 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 and benefit of fluctuation between the minimum (floor) price and the maximum (ceiling) price.

 

continuous accumulations – natural gas and oil resources that are pervasive throughout large areas, have ill-defined boundaries, and typically lack or are unaffected by hydrocarbon-water contacts near the base of the accumulation.

 

development well a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

exploratory well a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

 

farm tap – natural gas supply service in which the customer is served directly from a well or a gathering pipeline.

 

feet of pay - footage penetrated by the drill bit into the target formation.

 

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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Glossary of Commonly Used Terms, Abbreviations and Measurements

 

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.

 

margin call – a demand for additional margin deposits when forward prices move adversely to a derivative holder’s position.

 

margin deposits – funds or good faith deposits posted during the trading life of a futures contract to guarantee fulfillment of contract obligations.

 

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 iso-butane.

 

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 – quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

 

proved developed reserves – proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.

 

proved undeveloped reserves (PUDs) – proved reserves that can be estimated with reasonable certainty 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.

 

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Glossary of Commonly Used Terms, Abbreviations and Measurements

 

transportation – moving gas through pipelines on a contract basis for others.

 

throughput total volumes of natural gas sold or transported by an entity.

 

working gasthe 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

 

 

ASC - Accounting Standards Codification

CBM – Coalbed Methane

FASB – Financial Accounting Standards Board

FERC – Federal Energy Regulatory Commission

IRS – Internal Revenue Service

LDC – Local Distribution Company

NGV – Natural Gas Vehicle

NYMEX – New York Mercantile Exchange

OTC – Over the Counter

PA PUC – Pennsylvania Public Utility Commission

SEC – Securities and Exchange Commission

WV PSC – West Virginia Public Service Commission

 

 

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

MBbl   = thousand barrels

MMBtu  = million British thermal units

MMcf   = million cubic feet

MMcfe  = million cubic feet of natural gas equivalents

Tcfe = trillion cubic feet of natural gas equivalents

 

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Cautionary Statements

 

The Company’s finding and development costs are calculated from the production cost and reserve information provided in Footnote 22 to the Consolidated Financial Statements as costs of oil and gas producing activities less unproved properties divided by changes in reserves excluding production.  The Company expects that additional costs will be required to bring proved undeveloped reserves to production.  The Company provides an estimate of future development costs under the standard measure of discounted cash flows in Footnote 22.  The Company believes that finding and development costs are an important analytical measure used within the Company’s industry by investors and peers to evaluate, among other things, the profitability of drilling programs.  However, there are limitations as to the usefulness of this measure.  For instance, this measure may not be calculated consistently across the industry.

 

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,” “could,” “would,” “will,” “may,” “forecasts,” “approximate,” “expect,” “project,” “intend,” “plan,” “believe” and other words of similar meaning in connection with any discussion of future operating or financial matters.  Without limiting the generality of the foregoing, forward-looking statements contained in this report include the matters discussed in the sections captioned “Outlook” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the expectations of plans, strategies, objectives and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the Company’s drilling and infrastructure programs (including the Equitrans Marcellus expansion project) and technology, transactions, including asset sales and /or joint ventures involving the Company’s assets, the timing of construction of public-access natural gas refueling stations, production and sales volumes, well drilling plans, revenue projections, reserves (including estimated reserve life), the expected lateral length of wells, new fracturing techniques, finding and development costs, operating costs, well costs, unit costs, capital expenditures, financing requirements and availability, hedging strategy, the effects of government regulation and tax position.  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 speaks only as of the date on which such statement is made and the Company does not intend to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise.

 

In reviewing any agreements incorporated by reference in or filed with this Form 10-K, please remember such agreements are included to provide information regarding the terms of such agreements and are not intended to provide any other factual or disclosure information about the Company. The agreements may contain representations and warranties by the Company, which should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties should those statements prove to be inaccurate. The representations and warranties were made only as of the date of the relevant agreement or such other date or dates as may be specified in such agreement and are subject to more recent developments.  Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they were made or at any other time.

 

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PART I

 

Item 1.        Business

 

General

 

EQT Corporation (EQT or the Company) conducts its business through three business segments: EQT Production, EQT Midstream and Distribution. EQT Production is one of the largest natural gas producers in the Appalachian Basin with 5.2 Tcfe of proved reserves across 3.5 million acres as of December 31, 2010.  EQT Midstream provides gathering, transmission and storage services for the Company’s produced gas and to independent third parties in the Appalachian Basin. Until February 1, 2011, EQT Midstream also provided processing services. Distribution, through its regulated natural gas distribution subsidiary, Equitable Gas Company, LLC (Equitable Gas), distributes and sells natural gas to residential, commercial and industrial customers in southwestern Pennsylvania, West Virginia and eastern Kentucky, operates a small gathering system in Pennsylvania and provides off-system sales activities which include the purchase and delivery of gas to customers.

 

EQT has 5.2 Tcfe of proved reserves across three major plays: Marcellus Shale, Huron Shale and CBM, all located in the Appalachian Basin.  The Company’s strategy is to maximize value by profitably developing its extensive acreage position.  EQT Production 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 shale.

 

EQT’s proved reserves increased by 28% in 2010 and by 121% over the past five years, while the Company’s cost structure remained at an industry leading level.  EQT’s 2010 finding and development cost is among the lowest in the industry at $0.70 per Mcfe.  As of December 31, 2010, the Company’s proved reserves, including proved developed and proved undeveloped reserves, and the resource plays to which the reserves relate are as follows:

 

(Bcfe)

 

Marcellus
Shale

 

Huron *

 

Coalbed
Methane

 

Total

 

Proved Developed

 

577

 

1,797

 

161

 

2,535

 

Proved Undeveloped

 

2,302

 

383

 

 

2,685

 

Total Proved Reserves

 

2,879

 

2,180

 

161

 

5,220

 

 

*  The Company includes the Lower Huron, Cleveland, Berea sandstone and other Devonian shales, except Marcellus, in its Huron play.  Also included in the Huron play is 705 Bcfe of reserves from non-shale formations accessed through vertical wells.

 

A key assumption in booking proved undeveloped reserves is the Company’s 5-year capital investment estimate. The five-year plan used in estimating the Company’s proved reserves anticipates drilling expenditures of  $2.5 billion, which is consistent with the pace of development that the Company believes can be funded using the Production segment’s portion of internally-generated cash flows and does not require additional capital infusions or asset sales. Assuming that future annual production from these reserves is consistent with 2010, the remaining reserve life of the Company’s total proved reserves as calculated by dividing total proved reserves by current year produced volumes is in excess of 37 years.

 

The Company’s natural gas wells are generally low-risk with long lives and low development and production costs. The gas produced from these wells has a high energy content and is within close proximity to natural gas markets. Many of these wells have been producing for decades, with several in production since early in the 20th century.  Also, the gas produced from most of the Company’s Huron wells and some of its Marcellus Shale wells is liquids-rich.

 

In the Marcellus Shale play, EQT applies proprietary extended lateral horizontal drilling technology to its approximate 520,000 acres and 2.9 Tcfe of proved reserves. Marcellus Shale wells target depths ranging from 7,000 to 8,000 feet with an average lateral spacing of 1,000 feet.

 

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EQT is also focusing its highly successful horizontal drilling program in the Huron play where the Company has approximately 2.7 million acres and 2.2 Tcfe of proved reserves.  This technology has been used in fractured horizontal single lateral wells, stacked horizontal wells and extended lateral wells. Wells in the Huron play are drilled to depths ranging from 2,500 to 6,500 feet with an average lateral spacing of 1,000 feet.

 

Less than 5% of the Company’s proved reserves are attributable to CBM as of December 31, 2010. Substantially all of the Company’s CBM wells are drilled vertically and do not contain natural gas liquids.

 

Horizontal wells drilled by the Company over the past five years are as follows:

 

 

 

 

 

For the years ended December 31,

 

 

 

Gross Horizontal Wells
Drilled

 

2010

 

2009

 

2008

 

2007

 

2006

 

Marcellus Shale

 

90

 

46

 

7

 

 

 

Huron

 

236

 

356

 

381

 

88

 

5

 

Other

 

 

1

 

1

 

 

 

Total Horizontal

 

326

 

403

 

389

 

88

 

5

 

 

The Company invested approximately $888 million on well development (primarily drilling) in 2010. Sales volumes increased 34% in 2010 over 2009.

 

During 2010, the Company acquired approximately 58,000 net acres in the Marcellus Shale from a group of private operators and landowners. The acreage is located primarily in Cameron, Clearfield, Elk and Jefferson counties in Pennsylvania. The purchase included a 200 mile gathering system, with associated rights of way, and approximately 100 producing vertical wells.

 

To support the growth of the Marcellus Shale play, the Company is increasing its available gathering and transmission system capacity in the region. During 2010, the Company completed construction of the Ingram Gathering system which added 4,800 horsepower of compression and 105 MMcfe per day of delivery capacity to Equitrans L.P. (Equitrans, EQT’s interstate pipeline subsidiary) piplines for EQT production in Greene County, Pennsylvania. Equitrans has a total Pennsylvania gathering capacity of 130 MMcfe. In northern West Virginia, EQT completed the Doddridge Gathering System Expansion which is capable of delivering 60 MMcfe per day of EQT’s production from north central West Virginia into the western leg of the Equitrans system. This brings total Marcellus Shale gathering capacity in West Virginia to approximately 85 MMcfe per day. Equitrans also completed Phase 1 of the Equitrans Marcellus expansion project which added approximately 100,000 Dth per day of new delivery capacity to Equitrans’ interconnections with five interstate pipeline facilities: Texas Eastern Transmission, Columbia Gas Transmission, National Fuel Gas Supply, Tennessee Gas Pipeline and Dominion Transmission.

 

Also, the Company has approximately 10,900 miles of gathering lines and 770 miles of transmission lines. EQT’s 14 natural gas storage reservoirs provide approximately 500 MMcf per day of peak delivery capability and 63 Bcf of storage capacity, of which 32 Bcf is working gas.  EQT’s storage reservoirs are clustered in two geographic areas connected to its Equitrans pipeline, with eight in northern West Virginia and six in southwestern Pennsylvania.

 

Through EQT’s gas marketing subsidiary, EQT Energy, LLC, (EQT Energy), the Company provides optimization of capacity and storage assets, NGL sales and gas sales to commercial and industrial customers within its operational footprint through 8.2 Bcf of leased storage related assets and approximately 420,000 Dth per day of contractual pipeline capacity from third parties.

 

At December 31, 2010, EQT also owned and operated Kentucky Hydrocarbon, a gas processing facility in Langley, Kentucky. On February 1, 2011, EQT Midstream sold the processing facility and associated NGL pipeline

 

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to MarkWest Energy Partners, L.P. (MarkWest) for $230 million subject to customary purchase price adjustments. MarkWest agreed to commence the installation of a new 60 MMcfd cryogenic processing plant to expand the Langley cryogenic processing capacity.  In conjunction with the closing of the sale of the Langley plant, EQT executed a long-term agreement with MarkWest to provide processing services for its Kentucky Huron Shale gas and extended its existing agreement with MarkWest for NGL transportation, fractionation, and marketing services until 2022. In addition, MarkWest has agreed to construct a natural gas processing facility in Logansport, WV by the second quarter of 2012. MarkWest will then provide natural gas processing services for EQT’s Marcellus Shale production in north central West Virginia, as well as NGL transportation, fractionation and marketing services.

 

In 2008, EQT 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 capacity in TGP’s 300-Line expansion project.  EQT Energy’s capacity in the project is expected to be 350,000 Dth per day, giving EQT access to consumer markets from the Gulf Coast to the Mid-Atlantic and the Northeast. TGP’s expected turn in line date for the 300-Line expansion project is late 2011.

 

Capital spending for well development (primarily drilling) in 2011 is expected to be approximately $691 million to support the drilling of up to 167 gross wells, including 86 gross Marcellus Shale wells, and approximately $244 million for midstream infrastructure. Sales volumes are expected to exceed 175 Bcfe for an anticipated natural gas sales volume growth of 30% in 2011. A substantial portion of the Company’s 2011 drilling efforts are expected to be focused on drilling extended lateral Marcellus Shale wells. The Company currently believes that the capital spending plan will not require the Company to access capital markets through the end of the year.

 

Strategy

 

EQT’s strategy is to maximize value by profitably developing the Company’s substantial acreage position enabled by the Company’s extensive gathering and transmission assets, low cost structure, close proximity to the northeastern United States markets and the high Btu content of much of its produced natural gas.  The Company is focused on continuing its significant organic reserve and production growth through its developmental drilling program, particularly in the Marcellus Shale. The Company is also investing in developmental geological and geophysical studies to optimize well placement.

 

The Company believes that it is a technological leader in drilling shale. In the Marcellus Shale play, EQT Production believes its state of the art drilling and completion techniques have produced industry leading results. In the Huron play, the use of air in horizontal drilling has proven to be a cost effective technology which the Company has efficiently deployed. In both plays, the Company has used technology to increase lateral length. Recoveries from extended laterals have been proportional to the length increase. These industry leading processes have also allowed the Company to reduce development costs.  Based on these favorable results, the Company has incorporated extended lateral wells into its preferred standard operating procedures for the Marcellus and Huron Shale plays.  The Company expects to continue increasing the average lateral length. In the Marcellus Shale, lateral lengths will be limited by lease boundaries unless the Company is able to pool acreage with neighboring leaseholders.

 

Because substantially all of the Company’s acreage is held by production or in fee, EQT Production is able to develop its acreage in the most economic manner rather than focusing on drilling less economic wells in order to retain acreage. Additionally, the Company continues to demonstrate the quality of its Marcellus Shale acreage with recent successful wells in North Central West Virginia and Central Pennsylvania.  The Company’s core development area in Greene County, Pennsylvania continues to produce industry leading Marcellus Shale results in terms of initial production rates and finding and development costs.

 

The Company believes the location of the Company’s midstream assets across a wide area of the Marcellus Shale in southwestern Pennsylvania and northern West Virginia uniquely positions the Company for growth. In support of the Marcellus Shale growth, EQT Midstream strives to increase gathering capacity and improve capital efficiency by utilizing existing high pressure assets and completing modular compression construction. In West Virginia, completion of a compression facility has added significant capacity in the core Doddridge County area that the Company expects to develop in 2011.

 

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In 2011, EQT plans to continue its investment in gathering and transmission capacity in the high-potential Marcellus Shale area. This investment includes 130 MMcfe per day of incremental gathering capacity. In addition, over the next two years, the Equitrans Marcellus expansion project is expected to add approximately 550 MMcfe per day of incremental transmission capacity. The combination of these investments with the existing assets in the Huron region provide a platform for sales growth and will help to mitigate curtailments and increase the flexibility and reliability of the Company’s gathering systems in transporting gas to market.

 

In light of the anticipated Marcellus Shale production growth, the Company is also considering partnering with third parties and other arrangements, including a potential sale of the Big Sandy Pipeline, to unlock the value of mature assets and redeploy such value into higher-growth Marcellus Shale development.

 

The Company is also helping to build demand for natural gas. As a result of the $700,000 grant received from the Pennsylvania Department of Environmental Protection, Equitable Gas will be constructing a public-access natural gas fueling station in Pittsburgh, PA. In conjunction with this project, the Company is promoting the use of NGV fleet vehicles. Distribution is actively increasing the supply of locally produced Marcellus Shale gas flowing to its customers and assisting customers to obtain incentives and rebates as a result of conversions to natural gas from other fuel sources.

 

See “Capital Resources and Liquidity” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-K for details regarding the Company’s capital expenditures.

 

Markets and Customers

 

Natural Gas Sales:  EQT’s produced natural gas is sold to marketers, utilities and industrial customers located mainly in the Appalachian area.  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 significant increase in natural gas prices in early through mid 2008 followed by decreases later in 2008 and in 2009.  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.  In order to protect cash flow from undue exposure to the risk of changing commodity prices, 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. No single customer accounted for more than 10% of revenues in 2010 or 2009.  Sales to one third-party marketer accounted for approximately 13% of revenues for EQT Production for the year ended December 31, 2008.

 

NGL Sales:  As of December 31, 2010, the Company processed 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.  NGLs were 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 marketed these components for a fee. The Company also had contractual processing arrangements whereby the Company sold gas to a third-party processor at a weighted average liquids component price. Subsequent to the closing of the sale of the Kentucky Hydrocarbon facility to MarkWest, the processing of the Company’s produced natural gas has been performed by a third-party vendor.

 

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Average well-head sales price:

 

 

 

2010

 

2009

 

2008

 

 

 

 

 

 

 

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

 

$

3.93

 

$

4.11

 

$

5.51

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

 

$

3.43

 

$

2.79

 

$

8.42

 

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 2010 totaled 195,642 BBtu, of which approximately 67% related to gathering for EQT Production, 19% related to third-party volumes and 2% related to volumes for other subsidiaries 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 other subsidiaries accounted for approximately 85% of 2010 gathering revenues.

 

Natural Gas Transmission and Storage: Services offered by EQT Energy include commodity procurement, sales, delivery, risk management and other services, including the processing of natural gas liquids for third parties.  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.  EQT Energy uses leased storage capacity and firm transportation capacity to take advantage of price differentials and arbitrage opportunities.  EQT Energy also engages in risk management and energy trading 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.

 

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.  EQT 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 expire between 2011 and 2023.  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 2010, approximately 85% of transportation volumes and approximately 89% of transportation revenues were from affiliates.

 

Natural Gas Distribution: The Company’s Distribution segment provides natural gas distribution services to approximately 276,500 customers, consisting of 257,900 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.

 

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. The cost of purchased gas is Equitable Gas’ largest operating expense and is passed through to customers utilizing mechanisms approved by the PA PUC and WV PSC. Equitable Gas is not permitted to profit from fluctuations in gas costs.

 

Because most of its customers use natural gas for heating purposes, Equitable Gas’ revenues are seasonal, with approximately 71% of calendar year 2010 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

 

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underground storage inventory during the off-peak season to accommodate higher demand during the winter heating season.

 

Competition

 

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 independent oil and gas companies, major oil and gas companies and individual producers and operators.  Key competitors for new gathering systems include independent gas gatherers and integrated 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.  As a regulated utility, the Company’s distribution operation experiences only limited competition with other local distribution companies in its operating area, but experiences usuage pressures as a result of alternative fuels and conservation.

 

Regulation

 

Regulation of the Company’s Operations

 

EQT Production’s exploration and production operations are subject to various types of federal, state and local laws and regulations, including regulations related to the location of wells; the method of drilling, well construction and casing design; water withdrawal and procurement 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 plugging and abandoning of wells; the calculation, reporting and disbursement of taxes; and the gathering of production in certain circumstances, such as safety regulations.  These regulations may impact the costs of developing the Company’s natural gas resources.

 

EQT Production’s operations are also subject to conservation and correlative rights 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 or in close proximity to other wells; drilling in the vicinity of coal mining operations and certain other structures; and the unitization or pooling of natural gas properties.  Both Kentucky and Virginia allow the statutory pooling or integration of tracts to facilitate development and exploration, while in West Virginia and Pennsylvania it is necessary to rely on voluntary pooling of lands and leases.  In addition, state conservation laws generally limit the venting or flaring of natural gas.

 

EQT Midstream has both non-regulated and regulated operations.  The interstate natural gas transmission systems and storage operations are regulated by the FERC. For instance, the FERC approves tariffs that establish Equitrans’ rates, cost recovery mechanisms, and other terms and conditions of service to Equitrans’ customers. The fees or rates established under Equitrans’ tariffs are a function of its costs of providing services to customers, including a reasonable return on invested capital. The FERC’s authority also extends to: storage and related services; certification and construction of new facilities; extension or abandonment of services and facilities; maintenance of accounts and records; relationships between pipelines and certain affiliates; terms and conditions of service; depreciation and amortization policies; acquisition and disposition of facilities; the safety of pipelines; and initiation and discontinuation of services.

 

EQT Production and EQT Midstream each engage in natural gas trading activities which are regulated by, among others, the United States Commodity Futures Trading Commission (“CFTC”).  In July 2010, federal legislation was enacted to implement various financial and governance reforms. Although many of the legislative provisions were focused on the financial and banking industries, portions of the legislation may impact the Company’s natural gas trading activities. The extent of the impact is uncertain at this time because various implementing regulations are yet to be adopted by the SEC and the CFTC.

 

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

 

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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 distribution and gathering delivery activities.  However, Equitable Gas’ regulators do not guarantee recovery and may require that certain costs of operation be recovered over an extended term.  On August 24, 2010, the WV PSC approved a settlement between Equitable Gas and certain parties with respect to a base rate increase in West Virginia. Equitable Gas implemented the new base rates in the third quarter of 2010.

 

As required by Pennsylvania law, Equitable Gas has a customer assistance program that assists low-income customers with paying their gas bills. The cost of this program is recovered through rates charged to other residential customers.

 

Regulators periodically audit the Company’s compliance with applicable regulatory requirements.  The Company anticipates that compliance with existing laws and regulations governing current operations will not have a material adverse effect upon its capital expenditures, earnings or competitive position.  However, laws and regulations applicable to the oil and gas industry are frequently amended or reinterpreted.    Moreover, the recent oil spill in the Gulf of Mexico and explosion of a natural gas transmission line in California may lead to new regulations, guidelines and enforcement interpretations. Therefore, the Company is unable to predict the future costs or impact of compliance. Additional proposals that affect the oil and gas industry are regularly considered by Congress, the states, regulatory agencies and the courts. The Company cannot predict when or whether any such proposals may become effective.

 

Environmental, Health and Safety Regulation

 

The business operations of the Company are also subject to various federal, state and local environmental, health and safety laws and regulations pertaining to, among other things, the release, emission or discharge of materials into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes), the safety of employees and the general public, or otherwise relating to pollution, preservation, remediation or protection of human health and safety, natural resources, wildlife or the environment. The Company must take into account environmental, health and safety regulations in, among other things, planning, designing, constructing, drilling, operating and abandoning wells and related surface facilities. In most instances, the regulatory frameworks relate to the handling of drilling and production materials, the disposal of drilling and production wastes, the protection of water and air and the protection of people.

 

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.  Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material to the Company’s financial position, results of operations or liquidity.

 

Vast quantities of natural gas deposits exist in shale and other formations. It is customary in the Company’s industry to recover natural gas from these shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations underground where water, sand and other additives are pumped under high pressure into a shale gas formation. These formations are geologically separated and isolated from fresh ground water supplies by protective rock layers. The Company’s well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers. Legislative and regulatory efforts at the federal level and in some states have sought to render more stringent permitting and compliance requirements for hydraulic fracturing. If passed into law, the additional permitting requirements for hydraulic fracturing may increase the cost to obtain permits for or to construct wells.

 

Climate Change

 

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. Effective January 1, 2011, the EPA began regulating greenhouse gas

 

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emissions by subjecting new facilities and major modifications to existing facilities that emit large amounts of greenhouse gases to the permitting requirements of the federal Clean Air Act.  In addition, the U.S. Congress has been considering bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. Legislation or regulation that restricts carbon emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Climate change and greenhouse gas legislation or regulation could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, or impose additional monitoring and reporting requirements. Conversely, legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because the combustion of natural gas results in substantially fewer carbon emissions per Btu of heat generated than other fuels, such as coal. The effect on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

 

Employees

 

The Company and its subsidiaries had approximately 1,815 employees at the end of 2010. As of December 31, 2010, approximately 12% of the Company’s workforce is subject to collective bargaining agreements, and the collective bargaining agreement which covers approximately 9% of the Company’s workforce is scheduled to expire during September 2011.

 

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.  These filings are also available on the internet at http://www.sec.gov.  The Company’s press releases and recent analyst presentations are also available on the Company’s website.

 

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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 2010, 2009 and 2008.

 

 

 

2010

 

2009

 

2008

EQT Production:

 

 

 

 

 

 

Natural gas sales

 

25%

 

24%

 

20%

EQT Midstream:

 

 

 

 

 

 

Gathering revenue

 

13%

 

11%

 

7%

Marketed natural gas sales

 

6%

 

5%

 

12%

Distribution:

 

 

 

 

 

 

Residential natural gas sales

 

21%

 

26%

 

23%

 

Financial Information About Segments

 

On February 1, 2011, the Company sold its natural gas processing complex in Langley, Kentucky.  Subsequent to the closing of the sale, the processing of the Company’s produced natural gas has been performed by a third-party vendor. The revenue received as a result of the fractionation of NGLs which were extracted from the Company’s produced natural gas (frac spread) was previously reported in the EQT Midstream segment in conjunction with the results of the processing activities.  As a result of the sale of the Company’s processing assets, management determined that this frac spread would be reported in the EQT Production segment as additional revenue for its produced NGL sales. The segment disclosures and discussions contained in this report have been reclassified to reflect all periods presented under the new methodology.

 

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 18 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 upon 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 revenue, margin and cash flow for each of our businesses, a reduction in the construction of new transportation capacity and downward adjustments to the value of our estimated proved reserves which may cause us to incur non-cash charges to earnings.  Moreover, if we fail to control our operating costs during periods of lower natural gas prices, we could further reduce our margin. A reduction in margin or cash flow will reduce our funds available for capital expenditures and, correspondingly, our opportunities for growth.  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.

 

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, collar and option 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.

 

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 and natural gas liquids.  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 the 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 or to cover all risks.

 

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Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

 

Negative public perception regarding us and/or our industry resulting from, among other things, the recent oil spill in the Gulf of Mexico, the explosion of a natural gas transmission line in California and concerns raised by advocacy groups about hydraulic fracturing, may lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations, which may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation.  Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

 

Strategic determinations, including the allocation of capital and other resources to strategic opportunities are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our growth rate.

 

Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our 2011 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 2011 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected.

 

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.  In addition, our exploration projects increase 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 areas, our future operating results may be difficult to forecast, and our failure to sustain high growth rates in the future could adversely affect the market price of our common stock.

 

We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all.

 

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 or other sources.  Future challenges in the global financial system, including the capital markets, may adversely affect our business and our financial condition.  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. Adverse economic and market conditions could adversely affect the collectability of our trade receivables and cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection.  Future challenges in the economy could also 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.

 

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.  Our drilling and subsequent maintenance of wells 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, 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 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.

 

Our operations are regulated extensively at the federal, state and local levels.  Laws, regulations and other legal requirements have increased the cost to plan, design, drill, install, operate and abandon wells, gathering systems, pipelines and distribution systems.  Environmental, health and safety legal requirements 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.  Compliance with the laws, regulations and other legal requirements applicable to our businesses may increase our cost of doing business.   These requirements could also subject us to claims for personal injuries, property damage and other damages.  Our failure to comply with the laws, regulations and other legal requirements applicable to our businesses, even if as a result of factors beyond our control, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages.

 

The rates charged to customers by our gathering, transportation, storage and distribution businesses are, in many cases, subject to state or federal regulation.  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.

 

Laws, regulations and other legal requirements are constantly changing and implementation of compliant processes in response to such changes could be costly and time consuming.  For instance, effective January 1, 2011, the EPA began regulating greenhouse gas emission by subjecting new facilities and major modifications to existing facilities that emit large emissions of greenhouse gas emissions to the permitting requirements of the Federal Clean Air Act.

 

In addition, the U.S. Congress and various states have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of burning natural gas). Such restrictions may result in additional compliance obligations with respect to, or taxes on and the release, capture and use of greenhouse gases that could have an adverse effect on our operations.

 

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In addition, hydraulic fracturing is utilized to complete most of our natural gas wells. Certain environmental and other groups have suggested that additional laws and regulations may be needed to more closely regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation. We cannot predict whether any such federal or state legislation or regulation will be enacted and if enacted how they may impact our operations, but enactment of additional laws or regulations could increase our operating costs.

 

Recent federal budget proposals have included provisions which could potentially increase and accelerate the payment of federal income taxes of independent producers of natural gas and oil. Proposals that would significantly affect us would repeal the expensing of intangible drilling costs, repeal the percentage depletion allowance and increase the amortization period of geological and geophysical expenses. These changes, if enacted, will make it more costly for us to explore for and develop our natural gas resources.

 

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, such as the imposition of a new severance tax (a tax on the extraction of natural resources) in states in which we produce gas, could change. Any such increase or change could adversely impact our cash flows and profitability.

 

In July 2010, federal legislation was enacted to implement various financial and governance reforms. Although many of the legislative provisions were focused on the financial and banking industries, portions of the legislation will impact our businesses. The extent of the impact is uncertain at this time, due to the requirement that various implementing regulations must be adopted by the SEC and the United States Commodity Futures Trading Commission.

 

Our failure to develop or obtain, 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.  The Company’s 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.  The lack of midstream infrastructure could become more important in the geographic area in which the Marcellus Shale is being developed.  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.  In addition, some of our third-party contracts may involve significant financial commitments on our part and may make us dependent upon others to get our produced natural gas to market.

 

The loss of key personnel could adversely affect our ability to execute our strategic, operational and financial plans.

 

Our operations are dependent upon key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, the success of our operations will depend, in part, on our ability to attract, develop and retain experienced personnel. There is competition within our industry for experienced personnel and certain other professionals. If we cannot attract, develop and retain our technical and professional personnel or attract additional experienced technical and professional personnel, our ability to compete could be harmed.

 

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 or, in the case of certain office locations, warehouse buildings and equipment, leased, by the Company’s business segments. 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, West Virginia, Virginia and Pennsylvania. This segment currently has approximately 3.5 million gross acres (approximately 63% of which are considered undeveloped), which encompasses substantially 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 8,000 feet below the surface), the Company retains what are normally considered “deep rights” on the majority of its acreage. As of December 31, 2010, the Company estimated its total proved reserves to be 5,220 Bcfe, consisting of proved developed producing reserves of 2,177 Bcfe, proved developed non-producing reserves of 358 Bcfe and proved undeveloped reserves of 2,685 Bcfe. Substantially all of the Company’s reserves reside in continuous accumulations.

 

The Company’s estimate of proved natural gas and oil reserves are prepared by Company engineers. The engineer primarily responsible for the technical aspects of the reserves audit has received a bachelor’s degree in Engineering from the Pennsylvania State University and has thirteen years of experience in the oil and gas industry.  To ensure that the reserves are materially accurate, management reviews the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves. Additionally, production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems and the reserve roll forward between prior year reserves and current year reserves is reviewed by senior management.

 

The Company’s estimate of proved natural gas and oil reserves is audited by the independent consulting firm of Ryder Scott Company L.P. (Ryder Scott), which is hired by the Company’s management. Since 1937, Ryder Scott has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally. Ryder Scott’s audit report has been filed herewith as Exhibit 99.01.

 

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 22 (unaudited) to the Consolidated Financial Statements.

 

In 2010, the Company commenced drilling operations (“spud” or “drilled”) on 90 gross horizontal wells with an aggregate of approximately 300,000 feet of pay in the Marcellus Shale play. Total proved reserves in the Marcellus Shale play increased 171% to 2.9 Tcfe. Proved reserves increased in the Marcellus Shale play as a result of the Company’s 2010 drilling program. In the Huron play, the Company drilled 236 gross horizontal wells with an aggregate of approximately 1.0 million feet of pay during 2010. Total proved reserves in the Huron play (including vertical non-shale formations) decreased 22% to 2.2 Tcfe. The Company drilled 95 gross CBM wells in 2010. The CBM play had total proved reserves of 0.2 Tcfe at December 31, 2010, down 25% from 2009. Proved reserves decreased in the Huron and CBM plays as the Company plans to focus its capital expenditures during the next five years on developing the Marcellus Shale play. Sales of produced natural gas in 2010 from the Marcellus Shale, Huron and CBM plays were 25.5 Bcfe, 95.6 Bcfe and 13.5 Bcfe, respectively. Over the past three years, the Company has experienced a 99.6% developmental drilling success rate.

 

 

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Natural gas, NGL and crude oil production and pricing:

 

 

 

2010

 

2009

 

2008

 

Natural Gas:

 

 

 

 

 

 

 

MMcf produced

 

127,847

 

95,779

 

84,080

 

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

 

$      3.14

 

$     3.61

 

$     4.76

 

NGLs:

 

 

 

 

 

 

 

Thousands of Bbls produced

 

2,712

 

2,219

 

1,525

 

Average sales price per Bbl

 

$    48.76

 

$   35.21

 

$   55.35

 

Crude Oil:

 

 

 

 

 

 

 

Thousands of Bbls produced

 

120

 

99

 

104

 

Average sales price per Bbl

 

$    70.23

 

$   49.62

 

$   96.11

 

 

The Company’s average per unit production cost, excluding severance taxes, of natural gas and crude oil during 2010, 2009 and 2008 was $0.24, $0.30 and $0.35 per Mcfe, respectively.

 

 

 

Natural Gas

 

Oil

 

Total productive wells at December 31, 2010:

 

 

 

 

 

Total gross productive wells

 

14,305

 

20

 

Total net productive wells

 

10,389

 

17

 

Total in-process wells at December 31, 2010:

 

 

 

 

 

Total gross in-process wells

 

129

 

 

Total net in-process wells

 

110

 

 

 

 

 

 

 

 

 

 

(MMcf)

 

(MBbls)

 

Summary of proved oil and gas reserves as of December 31, 2010 based on average fiscal-year prices:

 

 

 

 

 

 

 

 

 

 

 

Developed

 

2,520,569

 

2,307

 

Undeveloped

 

2,685,123

 

 

 

Total acreage at December 31, 2010:

 

 

 

Total gross productive acres

 

1,267,324

 

Total net productive acres

 

1,104,980

 

Total gross undeveloped acres

 

2,190,885

 

Total net undeveloped acres

 

1,910,234

 

 

Certain lease acquisition agreements require the Company to drill 5 wells drilled to 250’ above the top of the Tully formation or deeper plus 4 wells to any depth or formation in 2011 and 5 wells drilled to 250’ above the top of the Tully formation or deeper plus 2 wells to any depth or formation in 2012; each of these wells must be drilled within specified acreage. The Company intends to satisfy these requirements as part of its Marcellus Shale development program. As of December 31, 2010, leases associated with 16,431 gross undeveloped acres expire in 2011 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:

 

 

 

2010

 

2009

 

2008

 

Exploratory wells:

 

 

 

 

 

 

 

Productive

 

 

 

1.0

 

Dry

 

 

1.0

 

 

Development wells:

 

 

 

 

 

 

 

Productive

 

392.1

 

535.6

 

531.2

 

Dry

 

3.0

 

2.0

 

1.0

 

 

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Selected data by state (at December 31, 2010 unless otherwise noted):

 

 

 

Kentucky

 

West
Virginia

 

Virginia

 

Pennsylvania

 

Ohio

 

Total

 

Natural gas and oil production (MMcfe) –2010

 

58,592

 

35,199

 

25,985

 

19,245

 

 

139,021

 

Natural gas and oil production (MMcfe) – 2009

 

50,959

 

27,069

 

24,624

 

2,276

 

 

104,928

 

Natural gas and oil production (MMcfe) – 2008

 

42,798

 

23,054

 

23,192

 

1,541

 

 

90,585

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average net revenue interest (%)

 

90.1%

 

74.1%

 

50.2%

 

87.0%

 

 

75.8%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total gross productive wells

 

5,508

 

4,873

 

3,230

 

714

 

 

14,325

 

Total net productive wells

 

4,640

 

3,118

 

1,938

 

710

 

 

10,406

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total gross productive acreage

 

520,240

 

417,404

 

267,680

 

62,000

 

 

1,267,324

 

Total gross undeveloped acreage

 

932,414

 

785,489

 

276,758

 

193,921

 

2,303

 

2,190,885

 

Total gross acreage

 

1,452,654

 

1,202,893

 

544,438

 

255,921

 

2,303

 

3,458,209

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total net productive acreage

 

453,597

 

363,945

 

226,316

 

61,122

 

 

1,104,980

 

Total net undeveloped acreage

 

930,497

 

658,743

 

125,323

 

193,368

 

2,303

 

1,910,234

 

Total net acreage

 

1,384,094

 

1,022,688

 

351,639

 

254,490

 

2,303

 

3,015,214

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed producing reserves (Bcfe)

 

1,097

 

575

 

323

 

182

 

 

2,177

 

Proved developed non-producing reserves (Bcfe)

 

19

 

198

 

5

 

136

 

 

358

 

Proved undeveloped reserves (Bcfe)

 

384

 

832

 

 

1,469

 

 

2,685

 

Proved developed and undeveloped reserves (Bcfe)

 

1,500

 

1,605

 

328

 

1,787

 

 

5,220

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross proved undeveloped drilling locations

 

311

 

201

 

 

265

 

 

777

 

Net proved undeveloped drilling locations

 

311

 

201

 

 

265

 

 

777

 

 

During 2010, the Company converted 249 Bcfe of proved undeveloped reserves to proved developed reserves and 362 Bcfe of non-proved undeveloped reserves to proved developed reserves. The five-year plan used in estimating proved reserves anticipates drilling expenditures of $2.5 billion to convert proved undeveloped reserves to proved developed reserves. This level of spending is consistent with the pace of development that the Company believes can be funded using the Production segment’s portion of internally-generated cash flows and does not require additional capital infusions or asset sales. Capital expenditures at EQT Production totaled $1,246 million during 2010, including $357.7 million for the acquisition of undeveloped property. As a result of the Company’s 2010 drilling program, the increase in proved reserves was primarily due to increases in the Marcellus Shale play offset by decreases in the Huron and CBM plays.

 

The Company’s 2010 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 1,893 Bcfe exceeded the 2010 production of 139.0 Bcfe.

 

During 2010, the Company recorded downward revisions of 604 Bcfe to the December 31, 2009 estimate of proved reserves due to removing PUD locations in the Huron play in order to focus more capital and resources in the Marcellus Shale play over the five-year time horizon included in the PUD development plan. These downward

 

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revisions were partially offset by increased prices. The reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2010. Although proved reserves are sensitive to price volatility, the impact to the Company should be minimal due to the Company’s low cost structure. Instead, proved reserve quantities are confined by the capital available for the development program within the next 5 years.

 

Wells located in Kentucky are primarily in Huron Shale formation with depths ranging from 2,500 feet to 6,000 feet. Wells located in West Virginia are primarily in Huron and Marcellus Shale formations with depths ranging from 2,500 feet to 6,500 feet. Wells located in Virginia are primarily in coalbed methane formations with depths ranging from 2,000 feet to 3,000 feet. Wells located in Pennsylvania are primarily in Marcellus Shale formations with depths ranging from 7,000 feet to 8,000 feet.

 

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

 

EQT Midstream. EQT Midstream owns or operates approximately 10,900 miles of gathering line and 243 compressor units comprising 125 compressor stations with approximately 228,000 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 and other customers lease capacity. These pipelines are subject to periodic curtailments for maintenance and repairs.

 

 

 

 

Kentucky

 

West
Virginia

 

Virginia

 

Pennsylvania

 

Total

 

Approximate miles of gathering line

 

3,850

 

4,850

 

1,700

 

500

 

10,900

 

 

EQT Midstream also owns and operates regulated underground storage and transmission facilities in Pennsylvania, West Virginia and Kentucky. These operations consist of approximately 770 miles of regulated transmission with daily capacity of 830,000 Dth per day and storage lines with approximately 28,000 horsepower of installed capacity and interconnections with five major interstate pipelines. The interstate pipeline system stretches throughout north central West Virginia and southwestern Pennsylvania. Equitrans has 14 natural gas storage reservoirs with approximately 500 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.

 

As of December 31, 2010, the Midstream business also owned a hydrocarbon processing plant and gas compression facilities located in Langley, Kentucky (Kentucky Hydrocarbon). On February 1, 2011, EQT sold Kentucky Hydrocarbon to MarkWest.

 

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

 

Equitable Distribution. This segment owns and operates natural gas distribution and gathering 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. During the third quarter of 2009, the Company completed the relocation of its corporate headquarters and certain other operations to downtown Pittsburgh.

 

Item 3.       Legal Proceedings

 

In the ordinary course of business various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict

 

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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, results of operations or liquidity 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, 2010.

 

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Table of Contents

 

Executive Officers of the Registrant (as of February 24, 2011)

 

Name and Age

 

Current Title (Year Initially
Elected an Executive Officer)

 

Business Experience

 

 

 

 

 

Theresa Z. Bone (47)

 

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.

 

 

 

 

 

Philip P. Conti (51)

 

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.

 

 

 

 

 

Randall L. Crawford (48)

 

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

 

Elected to present position in April 2010; Senior Vice President Midstream and Distribution from January 2008 to April 2010. 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.

 

 

 

 

 

Martin A. Fritz (46)

 

Vice President and President, Midstream Operations (2006)

 

Elected to current position April 2010; Vice President and President Midstream from January 2008 to April 2010. 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.

 

 

 

 

 

Lewis B. Gardner (53)

 

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.

 

 

 

 

 

Murry S. Gerber (57)

 

Executive Chairman (1998)

 

Elected to present position April 2010. Chairman and Chief Executive Officer from February 2007 to April 2010; Chairman, President and Chief Executive Officer from May 2000 to February 2007.

 

 

 

 

 

M. Elise Hyland (51)

 

Vice President and President, Commercial Operations (2008)

 

Elected to present position April 2010; Vice President and President, Equitable Gas from February 2008 to April 2010; President Equitable Gas from July 2007 to January 2008; Senior Vice President, Customer Operations Equitable Gas Company from March 2004 to June 2007.

 

 

 

 

 

Charlene Petrelli (50)

 

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 (53)

 

President and Chief Executive Officer (1998)

 

Elected to present position April 2010; President and Chief Operating Officer from February 2007 to April 2010; Vice Chairman and Executive Vice President, Finance and Administration from January 2005 to February 2007.

 

 

 

 

 

Steven T. Schlotterbeck (45)

 

Senior Vice President and President, Exploration and Production (2008)

 

Elected to present position April 2010; Vice President and President, Production from January 2008 to April 2010; 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.

 

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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.

 

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):

 

 

 

2010

 

2009

 

 

 

High

 

Low

 

Dividend

 

High

 

Low

 

Dividend

 

1st Quarter

 

$

47.43

 

$

39.78

 

$

0.22

 

$

38.63

 

$

27.77

 

$

0.22

 

2nd Quarter

 

46.06

 

35.80

 

0.22

 

38.95

 

31.38

 

0.22

 

3rd Quarter

 

39.50

 

32.23

 

0.22

 

42.90

 

31.94

 

0.22

 

4th Quarter

 

45.23

 

36.01

 

0.22

 

45.74

 

40.54

 

0.22

 

 

As of January 31, 2011, there were 3,402 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 conditions, strategic direction and other factors.

 

Stock Performance Graph

 

The following graph compares the most recent five-year cumulative total return attained by shareholders on the Company’s common stock with the cumulative total returns of the S&P 500 index and a customized peer group of twenty companies (the “Self-Constructed Peer Group”) whose individual companies are listed in footnote (1) below.  An investment of $100 (with reinvestment of all dividends) is assumed to have been made at the close of business on December 31, 2005 in the Company’s common stock, in the S&P 500 index, and in the peer group. Relative performance is tracked through December 31, 2010.

 

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Table of Contents

 

 

 

 

12/05

 

12/06

 

12/07

 

12/08

 

12/09

 

12/10

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EQT Corporation

 

100.00

 

116.51

 

151.30

 

97.01

 

129.92

 

135.58

 

S&P 500

 

100.00

 

115.80

 

122.16

 

76.96

 

   97.33

 

111.99

 

Self-Constructed Peer Group

 

100.00

 

116.13

 

143.62

 

89.70

 

129.18

 

139.58

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)         The twenty companies included in the self constructed peer group are: Atlas Energy Resources LLC, Cabot Oil & Gas Corp., Chesapeake Energy Corp., CNX Gas Corporation, El Paso Corp., Enbridge Inc., Energen Corp., Markwest Energy Partners LP, MDU Resources Group Inc, National Fuel Gas Company, Oneok Inc., Penn Virginia Corp., Questar Corp., Range Resources Corp., Sempra Energy, Southern Union Company, Southwestern Energy Company, Spectra Energy Corp., Transcanada Corp. and The Williams Companies, Inc.   Atlas Energy Resources LLC was acquired during 2009 and is included in the calculation from December 31, 2005 through December 31, 2008, at which time it is removed from the peer group calculation.  CNX Gas Corporation was acquired during 2010 and is included in the calculation from December 31, 2005 through December 31, 2009, at which time it is removed from the peer group calculation.  Questar Corp. was calculated using historical split adjusted pricing data.

 

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.

 

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Table of Contents

 

Item 6.    Selected Financial Data

 

 

 

As of and for the years ended December 31,

 

 

 

2010

 

2009

 

2008

 

2007

 

2006

 

 

 

(Thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

1,322,708

 

$

1,269,827

 

$

1,576,488

 

$

1,361,406

 

$

1,267,910

 

Net income

 

$

227,700

 

$

156,929

 

$

255,604

 

$

257,483

 

$

216,025

 

Earnings per share

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

1.58

 

$

1.20

 

$

2.01

 

$

2.12

 

$

1.79

 

Diluted

 

$

1.57

 

$

1.19

 

$

2.00

 

$

2.10

 

$

1.77

 

Total assets

 

$

7,098,438

 

$

5,957,257

 

$

5,329,662

 

$

3,936,971

 

$

3,282,255

 

Long-term debt

 

$

1,949,200

 

$

1,949,200

 

$

1,249,200

 

$

753,500

 

$

763,500

 

Cash dividends declared per share of common stock

 

$

0.880

 

$

0.880

 

$

0.880

 

$

0.880

 

$

0.870

 

 

See Item 1A, “Risk Factors” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 5 and 6 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.

 

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

 

Consolidated Results of Operations

 

In 2010 EQT achieved record results.  Highlights for 2010 include:

 

·      Record annual sales of produced natural gas of 134.6 Bcfe, more than 34% higher than 2009;

·      A 28% increase in proved reserves to 5.2 Tcfe;

·      The Company drilled 489 gross wells during 2010, of which 326 were horizontal wells, 90 targeting the Marcellus Shale play and 236 targeting the Huron play;

·      The Company was successful on more than 99.6% of the wells drilled in 2010;

·      Achieved 20% decrease in unit lease operating expense (LOE), excluding production taxes, to $0.24 per Mcfe. Including production taxes, LOE was $0.48 per Mcfe;

·      Record EQT Midstream throughput and operating income; and

·      Record Distribution operating income of $83.2 million, 5% higher than 2009.

 

EQT’s consolidated net income for 2010 was $227.7 million, $1.57 per diluted share, compared with $156.9 million, $1.19 per diluted share, for 2009 and $255.6 million, $2.00 per diluted share, for 2008.

 

The $70.8 million increase in net income from 2009 to 2010 was primarily attributable to increased produced natural gas sales volumes, higher gathering revenues, increased net revenues for NGLs, lower long-term incentive compensation expense and lower exploration expense. These favorable variances were partially offset by increased depreciation, depletion and amortization, lower average well-head sales prices, lower storage and marketing revenues and higher interest expense.

 

EQT revenues for 2010 increased approximately 4% compared to 2009 revenues.  Gas sales volumes increased more than 34% from 2009 primarily as a result of increased production from the 2009 and 2010 drilling programs partially offset by the normal production decline in the Company’s producing wells. Gathered volumes increased due to the Company’s production growth and infrastructure expansion, and NGL sales revenues increased as a result of an increase in NGL sales price as well as an increase in NGLs sold. Residential revenues increased as a result of the Company’s base rate increases in February 2009 and August 2010. These increases were partially offset by a 4% decline in the average well-head sales price as a result of lower hedge prices year-over-year which more than offset slightly increased commodity market prices and a 7% decline in storage and marketing revenues primarily resulting from lower margins on pipeline capacity.

 

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Operating expenses for 2010 decreased approximately 7% compared to 2009. This decline was primarily attributable to a $118.2 million decrease in purchased gas costs due to lower recoverable commodity costs, a $39.3 million decrease in long-term incentive compensation expense primarily due to the Company’s share price and performance in relation to its peer group which resulted in $61.8 million of expense in 2009 and a $12.5 million decrease in the Company’s exploration program. The decrease in exploration expense is primarily a result of a reduction in the level of purchase and interpretation of seismic data for unproved properties.  These decreases were partially offset by higher depletion resulting from increased investment in oil and gas producing properties.

 

The $98.7 million decrease in net income from 2008 to 2009 was primarily attributable to a lower average well-head sales price, increased incentive compensation expense, increased depletion expense and higher interest expense partially offset by increased gas and NGL sales volumes at EQT Production, increased gathering revenues, Big Sandy Pipeline activity at EQT Midstream and an increase in base rates in the Distribution segment.

 

Incentive compensation expense increased from 2008 to 2009 and decreased from 2009 to 2010 as a result of expenses related to the Company’s 2009 Shareholder Value Plan recorded in 2009 and a reversal of previously recorded expense on the Company’s 2005 Executive Performance Incentive Program in 2008 primarily as a result of the decline in the Company’s stock price in 2008.  Incentive compensation is primarily reported in selling, general and administrative expenses in the Statements of Consolidated Income.  A significant portion of the 2009 expense and 2008 reversal are reported as unallocated expenses in the information by business segment in Note 2 of the Company’s Consolidated Financial Statements.

 

Interest expense increased from 2008 to 2009 and from 2009 to 2010 primarily due to the Company’s continued investment in drilling and midstream infrastructure. This investment was partially funded by the issuance of $700 million of 8.125% notes in May 2009.

 

See Investing Activities in Capital Resources and Liquidity for a discussion of capital expenditures.

 

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 compensation expenses (income) and administrative expenses totaling $15.1 million, $62.2 million and ($17.4) million in 2010, 2009 and 2008, respectively, were not allocated to business segments.  The unallocated expenses in 2010 and 2009 primarily relate to performance-related incentive compensation expenses, while the unallocated income in 2008 primarily relates to the reversal of previously recorded performance-related incentive compensation expenses.

 

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.

 

On February 1, 2011, the Company sold its natural gas processing complex in Langley, Kentucky.  Subsequent to the closing of this sale, the processing of the Company’s produced natural gas has been performed by a third-party vendor. The revenue received as a result of the fractionation of NGLs which were extracted from

 

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the Company’s produced natural gas (frac spread) was previously reported in the EQT Midstream segment in conjunction with the results of the processing activities.  As a result of the sale of the Company’s processing assets, management determined that this frac spread would be reported in the EQT Production segment as additional revenue for its produced NGL sales. The segment disclosures and discussions contained in this report have been reclassified to reflect all periods presented under the new methodology. In conjunction with the closing of the sale, the Company executed a long-term agreement to receive processing services for its Kentucky Huron Shale gas and extended its existing agreement for NGL transportation, fractionation and marketing services until 2022. Expenses incurred during 2010 to operate the Langley processing complex, excluding DD&A, were $20.2 million. If the natural gas volumes processed by the Langley facility in 2010 would have been processed by a third-party, the Company would have incurred approximately $35.1 million in processing fees and expenses.

 

EQT Production

 

Results of Operations

 

 

 

Years Ended December 31,

 

 

 

2010

 

2009

 

%
change
2010 -
2009

 

2008

 

%
change
2009 -
2008

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATIONAL DATA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production:

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas, NGL and crude oil production (MMcfe) (a)

 

139,021

 

104,928

 

32.5

 

 

90,585

 

15.8

 

 

Company usage, line loss (MMcfe)

 

(4,407

)

 

(4,828

)

 

(8.7

)

 

(6,577

)

(26.6

)

 

Total sales volumes (MMcfe)

 

134,614

 

100,100

 

34.5

 

 

84,008

 

19.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales volumes (MMcf)

 

123,440

 

90,951

 

35.7

 

 

77,503

 

17.4

 

 

NGL sales volumes (Mbbls)

 

2,712

 

2,219

 

22.2

 

 

1,525

 

45.5

 

 

Crude oil sales volumes (Mbbls)

 

120

 

99

 

21.2

 

 

104

 

(4.8

)

 

Total sales volumes (MMcfe) (b)

 

134,614

 

100,100

 

34.5

 

 

84,008

 

19.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average (well-head) sales price (c)

 

$

3.93

 

$

4.11

 

(4.4

)

 

$

5.51

 

(25.4

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

0.24

 

$

0.30

 

(20.0

)

 

$

0.35

 

(14.3

)

 

Production taxes ($/Mcfe)

 

$

0.24

 

$

0.30

 

(20.0

)

 

$

0.53

 

(43.4

)

 

Production depletion ($/Mcfe)

 

$

1.26

 

$

1.06

 

18.9

 

 

$

0.81

 

30.9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production depletion (thousands)

 

$

175,629

 

$

111,371

 

57.7

 

 

$

73,362

 

51.8

 

 

Other depreciation, depletion and amortization (DD&A) (thousands)

 

8,070

 

 

6,053

 

 

33.3

 

 

4,872

 

24.2

 

 

Total DD&A (thousands)

 

$

183,699

 

$

117,424

 

56.4

 

 

$

78,234

 

50.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures (thousands) (d)

 

$

1,245,914

 

$

717,356

 

73.7

 

 

$

700,745

 

2.4

 

 

 

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Years Ended December 31,

 

 

 

2010

 

2009

 

%
change
2010 -
2009

 

2008

 

%
change
2009 -
2008

 

 

 

 

 

 

 

 

 

 

 

 

 

FINANCIAL DATA (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

 $

537,657

 

 $

420,990

 

27.7

 

 

 $

472,961

 

(11.0)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

LOE, excluding production taxes

 

33,784

 

31,228

 

8.2

 

 

31,719

 

(1.5)

 

 

Production taxes (e)

 

33,630

 

31,750

 

5.9

 

 

48,139

 

(34.0

)

 

Exploration expense

 

5,368

 

17,905

 

(70.0

)

 

9,064

 

97.5

 

 

Selling, general and administrative (SG&A)

 

57,689

 

36,815

 

56.7

 

 

38,185

 

(3.6)

 

 

DD&A

 

183,699

 

117,424

 

56.4

 

 

78,234

 

50.1

 

 

Total operating expenses

 

314,170

 

235,122

 

33.6

 

 

205,341

 

14.5

 

 

Operating income

 

 $

223,487

 

 $

185,868

 

20.2

 

 

 $

267,620

 

(30.5

)

 

 

(a)

Natural gas, NGL and oil production represents the Company’s interest in natural gas, NGL and oil production measured at the well-head. It is equal to the sum of total sales volumes, Company usage and line loss.

 

 

 

 

(b)

NGLs are converted to Mcfe at the rate of 3.86 Mcf per barrel and crude oil is converted to Mcfe at the rate of six Mcf per barrel.

 

 

 

 

(c)

Average well-head sales price is calculated as market price adjusted for hedging activities less deductions for gathering, processing and transmission included in EQT Midstream revenues. These deductions totaled $1.69/Mcfe, $1.69/Mcfe and $1.50/Mcfe for 2010, 2009 and 2008, respectively. Additionally, third-party gathering, processing and transportation deductions totaled $0.42/Mcfe, $0.36/Mcfe and $0.43/Mcfe for 2010, 2009 and 2008, respectively.

 

 

 

 

(d)

Capital expenditures in 2010, 2009 and 2008 include $357.7 million, $31.0 million and $85.5 million, respectively, for undeveloped property acquisitions. The amount for 2010 includes $230.7 million of undeveloped property which was acquired with EQT stock.

 

 

 

 

(e)

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

 

 

 

Fiscal Year Ended December 31, 2010 vs. December 31, 2009

 

EQT Production’s operating income totaled $223.5 million for 2010 compared to $185.9 million for 2009, an increase of $37.6 million between years, primarily due to increased sales volumes of produced natural gas, NGL and crude oil, partially offset by a lower average well-head sales price and an increase in depletion and SG&A expenses.

 

Total operating revenues were $537.7 million for 2010 compared to $421.0 million for 2009.  The $116.7 million increase in operating revenues was due to increased sales volumes which more than offset lower realized prices.  The increase in produced natural gas sales volumes was the result of increased production from the 2009 and 2010 drilling programs, primarily in the Marcellus and Huron Shale plays. This increase was partially offset by the normal production decline in the Company’s wells. The $0.18 per Mcfe decrease in the average well-head sales price was primarily due to lower hedging gains and lower hedged gas sales compared to 2009, partially offset by a 10% increase in the average NYMEX price and a higher sales price for NGLs.

 

Operating expenses totaled $314.2 million for 2010 compared to $235.1 million for 2009.  The 34% increase in operating expenses was primarily the result of increases of $66.3 million in DD&A, $20.9 million in SG&A, $2.6

 

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million in LOE partially offset by a decrease of $12.5 million in exploration expense. The increase in DD&A was primarily due to increased depletion expense resulting from both increases in the unit rate ($25.6 million) and volume ($38.2 million).  The $0.20 per Mcfe increase in the depletion rate is primarily attributable to the increased investment in oil and gas producing properties. The increase in SG&A was primarily due to the reversal of reserves in the prior year for certain legal disputes; higher personnel costs including incentive compensation and hiring and relocation costs, a portion of which were recorded at headquarters in prior years; a charge for the buy-out of excess contractual capacity for the processing and disposal of salt water; and an increase in professional fees. Despite the 20% decrease in the average LOE per Mcfe, total LOE increased as a result of increased activity in the Marcellus Shale play in the current year. These factors were partially offset by a decrease in exploration expense due to a reduction in geophysical activity compared to the prior year as well as an impairment charge in 2009 on an exploratory Utica well.

 

Fiscal Year Ended December 31, 2009 vs. December 31, 2008

 

EQT Production’s operating income totaled $185.9 million for 2009 compared to $267.6 million for 2008, a decrease of 31% between years, primarily due to a lower average well-head sales price and an increase in depletion expense partially offset by increased sales volumes.

 

Total operating revenues were $421.0 million for 2009 compared to $473.0 million for 2008.  The decrease in operating revenues was due to lower realized prices which more than offset increased sales volumes.  The average well-head sales price decreased by $1.40 per Mcfe, primarily as a result of a 56% decrease in NYMEX natural gas prices, a 36% lower sales price for NGLs and a lower percentage of hedged gas sales, partially offset by a higher realized hedge price.  The decrease in prices was partially offset by increased sales volumes of more than 19% as a result of the 2008 and 2009 drilling programs, net of the normal production decline in the Company’s wells, and a decrease in Company usage and line loss.

 

Operating expenses totaled $235.1 million for 2009 compared to $205.3 million for 2008.  The $29.8 million increase in operating expenses was a result of increases of $39.2 million in DD&A partially offset by decreases of $16.4 million in production taxes, $1.4 million in SG&A, and $0.5 million in LOE.  In addition, 2009 includes an $8.8 million increase in exploration expense due to the purchase and interpretation of seismic data in support of the Company’s examination of emerging plays and the impairment charge on an exploratory Utica well.  The increase in DD&A was primarily due to increased depletion expense resulting from both increases in the unit rate ($26.3 million) and volume ($11.0 million).  The $0.25 per Mcfe increase in the depletion rate is primarily attributable to the increased investment in oil and gas producing properties. The decrease in production taxes was primarily due to a $17.8 million decrease in severance taxes partially offset by a $1.4 million increase in property taxes. The decrease in severance taxes (a production tax imposed on the value of gas extracted) was primarily due to lower gas commodity prices partially offset by 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 decrease in SG&A was primarily due to the reversal of reserves for certain legal disputes partially offset by higher overhead costs associated with the growth of the Company, increased franchise and gross receipts taxes attributable to increased receipts and costs associated with the amendment of a contract to secure capacity for the processing and disposal of salt water.  The decrease in LOE was primarily attributable to the 2008 program to test the re-fracturing of existing wells.

 

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Table of Contents

 

EQT Midstream

 

Results of Operations

 

 

 

Years Ended December 31,

 

 

 

2010

 

2009

 

%
change
2010 - 
2009

 

2008

 

%
change
2008 - 
2007

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATIONAL DATA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering and processing:

 

 

 

 

 

 

 

 

 

 

 

Gathered volumes (BBtu)

 

195,642

 

161,480

 

21.2

 

145,031

 

11.3

 

Average gathering fee ($/MMBtu)

 

  $

1.11

 

  $

1.04

 

6.7

 

  $

0.98

 

6.1

 

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

 

  $

0.37

 

  $

0.42

 

(11.9)

 

  $

0.37

 

13.5

 

Transmission pipeline throughput (BBtu)

 

109,165

 

84,132

 

29.8

 

76,270

 

10.3

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating revenues (thousands):

 

 

 

 

 

 

 

 

 

 

 

Gathering

 

  $

212,170

 

  $

165,519

 

28.2

 

  $

140,118

 

18.1

 

Transmission

 

84,190

 

76,749

 

9.7

 

51,563

 

48.8

 

Storage, marketing and other

 

100,097

 

107,530

 

(6.9)

 

95,842

 

12.2

 

Total net operating revenues

 

  $

396,457

 

  $

349,798

 

13.3

 

  $

287,523

 

21.7

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures (thousands)

 

  $

193,128

 

  $

201,082

 

(4.0)

 

  $

593,564

 

(66.1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

FINANCIAL DATA (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

  $

580,698

 

  $

465,444

 

24.8

 

  $

597,073

 

(22.0)

 

Purchased gas costs

 

184,241

 

115,646

 

59.3

 

309,550

 

(62.6)

 

Total net operating revenues

 

396,457

 

349,798

 

13.3

 

287,523

 

21.7

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

Operating and maintenance (O&M)

 

107,601

 

95,164

 

13.1

 

83,577

 

13.9

 

SG&A

 

48,127

 

47,146

 

2.1

 

49,208

 

(4.2)

 

DD&A

 

61,863

 

53,291

 

16.1

 

34,802

 

53.1

 

Total operating expenses

 

217,591

 

195,601

 

11.2

 

167,587

 

16.7

 

Operating income

 

  $

178,866

 

  $

154,197

 

16.0

 

  $

119,936

 

28.6

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income, net

 

  $

509

 

  $

1,357

 

(62.5)

 

  $

5,678

 

(76.1)

 

Equity in earnings of nonconsolidated investments

 

  $

9,532

 

  $

6,376

 

49.5

 

  $

5,053

 

26.2

 

 

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

 

Fiscal Year Ended December 31, 2010  vs. December 31, 2009

 

EQT Midstream’s operating income totaled $178.9 million for 2010 compared to $154.2 million for 2009. The $24.7 million increase in operating income was primarily the result of increased gathering volumes and

 

33



Table of Contents

 

gathering rates, partially offset by decreased storage, marketing and other net operating revenues and increased operating expenses.

 

Total net operating revenues were $396.5 million for 2010 compared to $349.8 million for 2009.  The $46.7 million increase in total net operating revenues was due to a $46.7 million increase in gathering net operating revenues and a $7.4 million increase in transmission net operating revenues, partially offset by a $7.4 million decrease in storage, marketing and other net operating revenues.

 

Gathering net operating revenues increased due to a 21% increase in gathered volumes as well as a 7% increase in the average gathering fee.  This increase was driven primarily by higher Marcellus Shale volumes from EQT Production.

 

Transmission net revenues in 2010 increased from the prior year primarily as a result of higher firm transportation activity from affiliated shippers due to the increased Marcellus Shale volumes and increased capacity from Phase 1 of the Equitrans Marcellus expansion project, which came on-line during the fourth quarter of 2010.

 

The decrease in storage, marketing and other net revenues was primarily due to decreased margins and volumes of third-party marketing that utilized pipeline capacity, less volatility in seasonal price spreads and decreased basis differentials which in 2009 had a positive impact on the Company. This decrease was partially offset by an increase in NGL processing net revenues primarily due to an increase in average NGL sales price.

 

Total operating revenues increased by $115.3 million, or 25%, primarily as a result of increased marketed volumes due to higher Marcellus Shale activity and higher gathered volumes.  Total purchased gas costs also increased as a result of higher Marcellus Shale activity.

 

Operating expenses totaled $217.6 million for 2010 compared to $195.6 million for 2009.  The increase in operating expenses was primarily due to increases of $12.4 million in O&M and $8.6 million in DD&A. The increase in O&M is primarily due to higher electricity, labor, and non-income taxes associated with the growth of the business as well as a $2.6 million loss on compressor decommissioning at the Kentucky Hydrocarbon processing facility. The increase in DD&A was primarily due to the increased investment in gathering and transmission infrastructure.

 

Equity in earnings of nonconsolidated investments totaled $9.5 million for 2010 compared to $6.4 million for 2009.  This increase is related to equity earnings recorded for EQT Midstream’s investment in Nora Gathering, LLC. The higher net income was driven by increases in the average gathering fee and gathered volumes partially offset by increased operating expenses for the Nora operations in 2010.

 

Fiscal Year Ended December 31, 2009 vs. December 31, 2008

 

EQT Midstream’s operating income totaled $154.2 million for 2009 compared to $119.9 million for 2008. The $34.3 million increase in operating income was primarily the result of increased gathering volumes and rates and increased Big Sandy Pipeline activity, partially offset by increased operating expenses.

 

Total net operating revenues were $349.8 million for 2009 compared to $287.5 million for 2008.  The $62.3 million increase in total net operating revenues was due to a $25.4 million increase in gathering net operating revenues, a $25.2 million increase in transmission net operating revenues, and an $11.7 million increase in storage, marketing and other net operating revenues.

 

Gathering net operating revenues increased due to an 11% increase in gathered volumes as well as a 6% increase in the average gathering fee.  This increase was driven by more volumes gathered for EQT Production, as well as increased third-party customer volume due to increased available capacity with the Big Sandy Pipeline being operational for a full year in 2009.

 

Transmission net revenues in 2009 increased from the prior year primarily due to increased capacity from the Big Sandy Pipeline, which came on-line in the second quarter of 2008.

 

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Table of Contents

 

The increase in storage, marketing and other net revenues was primarily due to increased third-party marketing that utilized Big Sandy Pipeline capacity as well as increased margins on third-party NGLs sold.

 

Total operating revenues decreased by $131.6 million, or 22%, primarily as a result of lower sales prices on decreased commercial activity related to contractual transmission and storage assets partially offset by an increase in gathering volumes and rates and increased transmission revenues from the Big Sandy Pipeline. Total purchased gas costs decreased 63% as a result of lower gas costs on decreased commercial activity related to contractual transmission and storage assets.

 

Operating expenses totaled $195.6 million for 2009 compared to $167.6 million for 2008. The increase in operating expenses was primarily due to increases of $11.6 million in O&M and $18.5 million in DD&A, offset by a decrease of $2.1 million in SG&A. The increase in O&M resulted mainly from higher electricity, labor, non-income taxes and compressor maintenance expenses for the gathering business due to new compressors and processing facilities put in operation in the second half of 2008, partially offset by a decrease of $9.5 million relating to pension and other post-retirement benefit charges recorded in 2008. The increase in DD&A was primarily due to the increased investment in infrastructure during 2008 and 2009.

 

Other income represents allowance for equity funds used during construction.  The $4.3 million decrease from 2008 to 2009 was primarily caused by AFUDC recorded on the construction of the Big Sandy Pipeline in 2008.  AFUDC was no longer recorded once Big Sandy was placed into service in the second quarter of 2008.

 

Equity in earnings of nonconsolidated investments totaled $6.4 million for 2009 compared to $5.1 million for 2008.  This increase is related to equity earnings recorded for EQT Midstream’s investment in Nora Gathering, LLC.  Earnings increased in 2009 as a result of higher net income for Nora Gathering, LLC in 2009 compared to 2008.  The higher net income was driven by increases in the average gathering fee and gathered volumes partially offset by increased operating expenses for the Nora operations in 2009.

 

35



Table of Contents

 

Distribution

 

Results of Operations

 

 

 

Years Ended December 31,

 

 

 

2010

 

2009

 

%
change
2010 - 
2009

 

2008

 

%
change
2009 - 
2008

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATIONAL DATA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

5,516

 

5,474

 

0.8

 

5,622

 

(2.6)

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential sales and transportation volume (MMcf)

 

23,132

 

23,098

 

0.1

 

23,824

 

(3.0)

 

Commercial and industrial volume (MMcf)

 

27,124

 

30,521

 

(11.1)

 

27,503

 

11.0

 

Total throughput (MMcf)

 

50,256

 

53,619

 

(6.3)

 

51,327

 

4.5

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating revenues (thousands):

 

 

 

 

 

 

 

 

 

 

 

Residential

 

$

117,418

 

$

111,007

 

5.8

 

$

105,059

 

5.7

 

Commercial & industrial

 

48,614

 

47,432

 

2.5

 

46,394

 

2.2

 

Off-system and energy services

 

21,365

 

21,545

 

(0.8)

 

19,415

 

11.0

 

Total net operating revenues

 

187,397

 

179,984

 

4.1

 

170,868

 

5.3

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures (thousands)

 

$

36,619

 

$

33,707

 

8.6

 

$

45,770

 

(26.4)

 

 

 

 

 

 

 

 

 

 

 

 

 

FINANCIAL DATA (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

$

474,143

 

$

560,283

 

(15.4)

 

$

698,385

 

(19.8)

 

Purchased gas costs

 

286,746

 

380,299

 

(24.6)

 

527,517

 

(27.9)

 

Net operating revenues

 

187,397

 

179,984

 

4.1

 

170,868

 

5.3

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

O & M

 

44,047

 

43,663

 

0.9

 

44,161

 

(1.1)

 

SG&A

 

35,994

 

35,028

 

2.8

 

44,793

 

(21.8)

 

DD&A

 

24,174

 

22,375

 

8.0

 

22,055

 

1.5

 

Total operating expenses

 

104,215

 

101,066

 

3.1

 

111,009

 

(9.0)

 

Operating income

 

$

83,182

 

$

78,918

 

5.4

 

$

59,859

 

31.8

 

 

Fiscal Year Ended December 31, 2010 vs. December 31, 2009

 

Distribution’s operating income totaled $83.2 million for 2010 compared to $78.9 million for 2009.  The increase in operating income was primarily due to an increase in base rates which was partially offset by higher operating expenses.

 

Net operating revenues were $187.4 million for 2010 compared to $180.0 million for 2009.  The $7.4 million increase in net operating revenues was primarily the result of an increase in residential net operating revenues.  Net operating revenues from residential customers increased $6.4 million as a result of the approval of the Company’s Pennsylvania base rate increase in late February 2009 as well as the approval of the Company’s West Virginia base rate increase in August 2010. Commercial and industrial net revenues increased $1.2 million due to higher base rates and an increase in performance-based revenues, partially offset by a decrease in usage by one industrial customer. High volume sales to this industrial customer had low unit margins and the decrease in sales did not significantly impact total net operating revenues.  Off-system and energy services net operating revenues decreased due to lower

 

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margins in asset optimization activities, partially offset by increased gathering revenue as a result of higher rates. A decrease in the commodity component of residential tariff rates and a decrease in gas costs associated with asset optimization transactions resulted in a decrease in both total operating revenues and purchased gas costs.

 

Operating expenses totaled $104.2 million for 2010 compared to $101.1 million for 2009.  The $3.1 million increase in operating expenses was primarily the result of higher bad debt and depreciation and amortization expense. The increase in bad debt expense from 2009 to 2010 was primarily the result of a favorable one-time adjustment in the allowance for uncollectible accounts in 2009 due to the recovery of CAP costs associated with the approval of the Pennsylvania rate case settlement. These increases were partially offset by an increase in accruals for certain non-income tax reserves in 2009 and a decrease in incentive compensation costs in 2010. The increase in DD&A expense was primarily the result of increased capital expenditures.

 

Fiscal Year Ended December 31, 2009 vs. December 31, 2008

 

Distribution’s operating income totaled $78.9 million for 2009 compared to $59.9 million for 2008.  The increase in operating income was primarily due to an increase in base rates and lower operating expenses.

 

Net operating revenues were $180.0 million for 2009 compared to $170.9 million for 2008.  The $9.1 million increase in net operating revenues was primarily the result of the approval of the Company’s base rate increase in 2009.  Net revenues from residential customers increased $5.9 million as a result of an increase in base rates which was partially offset by the absence of a 2008 non-recurring increase in CAP activities, as well as customer conservation and slightly warmer weather.  Off-system and energy services net operating revenues increased $2.1 million due to higher revenues from gathering activities resulting primarily from increased rates.  Commercial and industrial net revenues increased $1.0 million due to higher base rates and an increase in usage by one industrial customer, partially offset by lower performance-based revenues.  The high volume sales from the industrial customer have low unit margins and did not significantly impact total net operating revenues.  A decrease in gas costs associated with asset optimization transactions and a decrease in the commodity component of residential tariff rates resulted in a decrease in both total operating revenues and purchased gas costs.

 

Operating expenses totaled $101.1 million for 2009 compared to $111.0 million for 2008.  The $9.9 million decrease in operating expenses was primarily the result of lower bad debt, general overhead and labor and fringe benefit expenses in 2009 and the absence of the holding company reorganization costs that were incurred in 2008.  The reduction in bad debt expense from 2008 to 2009 was the result of favorable adjustments in the allowance for uncollectible accounts in 2009 due to increased customer participation in programs assisting low-income customers in paying their bills, the recovery of CAP costs associated with the approval of the rate case settlement and a decrease in the commodity component of residential tariff rates.  These decreases were partially offset by an increase in accruals for certain non-income tax reserves and an increase in incentive compensation costs.

 

Other Income Statement Items

 

 

 

Years Ended December 31,

 

 

2010

 

2009

 

2008

 

 

 

 

(Thousands)

 

 

Other than temporary impairment on available-for-sale securities

 

$

 

$

 

$

(7,835)

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

 

2,079

 

 

– 

Other income

 

1,147

 

2,076

 

6,233 

 

As discussed in Note 9 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 and the nature of the underlying assets.  Although the Company holds these investments to fund long-term liabilities, based on the extent and duration of the impairment, combined with then 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.

 

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During 2010, the Company sold available-for-sale securities for $12.3 million which resulted in gross realized gains of $2.1 million, $1.4 million of which was reclassified from accumulated other comprehensive income (OCI).

 

In 2010, 2009 and 2008, other income primarily relates to contributions in aid of construction and the equity portion of AFUDC on various projects.  The decrease in other income from 2008 to 2009 reflects the completion of the construction of the Big Sandy Pipeline in the second quarter of 2008.

 

Interest Expense

 

 

 

Years Ended December 31,

 

 

 

2010

 

2009

 

2008

 

 

 

 

 

(Thousands)

 

 

 

Interest expense

 

$128,157

 

$111,779

 

$58,394

 

 

Interest expense increased by $16.4 million from 2009 to 2010 primarily due to the full year of expense incurred on the $700 million of 8.125% notes issued in May 2009. This increase was partially offset by a $4.4 million increase in capitalized interest primarily due to the capitalization of interest on Marcellus Shale well development beginning in 2010 reflecting the longer time to flow gas and increased investment associated with the multi-well pads.

 

Interest expense increased by $53.4 million from 2008 to 2009 primarily due to the Company’s continued investment in drilling and midstream infrastructure during 2009.  This investment was partially funded by the issuance of $700 million of 8.125% notes in May 2009.  The interest expense associated with these notes was partially offset by a 2.8% decrease in the average short-term interest rate during 2009.

 

Weighted average annual interest rates on the Company’s long-term debt were 6.8%, 6.5% and 6.1% for 2010, 2009 and 2008, respectively.  Weighted average annual interest rates on the Company’s short-term debt were 0.7%, 0.7% and 3.5% for 2010, 2009 and 2008, respectively.

 

Income Taxes

 

 

 

Years Ended December 31,

 

 

 

2010

 

2009

 

2008

 

 

 

 

 

(Thousands)

 

 

 

Income Taxes

 

$127,520

 

$96,668

 

$154,920

 

 

Income tax expense increased by $30.9 million from 2009 to 2010 as a result of higher pre-tax income partially offset by a lower effective tax rate. During 2010, the Company’s effective income tax rate decreased from 38.1% to 35.9%.  The higher tax rate in 2009 is primarily the result of the impact in 2009 of certain nondeductible expenses and the loss of certain prior year deductions as a result of carrying 2009 losses back to receive a cash refund of taxes paid. These higher rates in 2009 were partially mitigated by a regulatory asset recorded to recover deferred taxes caused by an accounting method change that deducts as repairs certain costs capitalized for financial accounting purposes in 2009. Rates were also lower in 2010 due to the reduction of the reserve for uncertain tax positions due to the expiration of applicable statutes of limitation in 2010.

 

Income tax expense decreased by $58.3 million from 2008 to 2009 despite a higher effective tax rate as a result of lower pre-tax income.   During 2009, the Company’s effective income tax rate increased from 37.7% to 38.1%.  The higher tax rate in 2009 is primarily the result of nondeductible compensation expense partially offset by a regulatory asset recorded to recover deferred taxes caused by an accounting method change that deducts as repairs certain costs capitalized for financial accounting purposes.  The Company recorded a tax benefit in 2008 for a change in the West Virginia state tax law that primarily provides for a reduction in future corporate income tax rates which was partially offset by additional tax expense recorded as a result of the completion of the IRS audit through the 2005 tax year.

 

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The Company was in an overall federal tax net operating loss position for 2008, 2009 and 2010 and expects to pay minimal federal income taxes for the next few years as the Company’s drilling program in Appalachia continues to generate intangible drilling cost deductions, unless tax laws change or the Company incurs an unexpected taxable gain from a transaction.  For federal income tax purposes, the Company currently deducts approximately 80% of drilling costs as intangible drilling costs (IDC) in the year incurred.  The primary reasons for the Company’s net operating loss are the IDC deduction resulting from the Company’s drilling program and the accelerated tax deprecation for expansion of gathering infrastructure which provide tax deductions in excess of book deductions. In addition, tax legislation was passed in 2008, 2009 and 2010 that allowed companies to deduct 50% of the cost of qualified assets placed in service for those years. Under the Tax Relief, Unemployment Insurance Reauthorization, and Job Create Act of 2010 (2010 Tax Relief Act), companies may deduct 100% of the cost of qualified assets placed in service after September 8, 2010 and before January 1, 2012.

 

See Note 7 to the Consolidated Financial Statements for further discussion of the Company’s income taxes.

 

Outlook

 

The Company is committed to profitably expanding its production and developing its reserves through cost-effective, technologically-advanced horizontal drilling in its existing plays.  A substantial portion of the Company’s drilling efforts in 2011 are expected to be focused on drilling horizontal wells in shale formations in Pennsylvania, West Virginia and Kentucky. The Company expects natural gas sales volume growth of 30% in 2011. Gathering, transmission and marketed volumes are also expected to increase as the Company expands its infrastructure to support its expected growth of produced gas sales. Specifically, in 2011 the Company will focus on:

 

·                  Marcellus Shale. The Marcellus Shale is the Company’s fastest growing and most profitable play. The Company expects to access significantly more reserves for less than a proportional amount of development costs through extended lateral drilling and experimenting with new hydraulic fracturing techniques. The Company also plans to spend $12.0 million on seismic data to determine optimal placement for future Marcellus Shale wells.

 

To support the Marcellus Shale drilling growth, the Company plans to add 130 MMcfe per day of incremental gathering capacity. The Company will also strive to optimize its contractual capacity and storage assets, which include 350,000 Dth per day of capacity in TGP’s 300-Line expansion project, which is expected to turn in line late in 2011.

 

Also, the Company expects to continue to invest in its Equitrans Marcellus expansion project. The project is underway and, given its significant scope, is progressing in stages.  Equitrans placed Phase 1 into service on October 1, 2010. Equitrans filed the certificate application for Phase 2 with the FERC on January 27, 2011, anticipates obtaining final approval in the summer of 2011 and expects to have Phase 2 in service by the end of 2012. Over the course of the next two years, the Equitrans Marcellus expansion project will add approximately 550 MMcfe per day of incremental transmission capacity. Equitrans entered into firm capacity agreements of approximately 530 MMcfe per day with both third-parties and affiliates in support of the Marcellus expansion project.

 

Finally, to continue the accelerated development of the Marcellus Shale play, the Company is also considering partnering with third parties, as well as other arrangements, including a potential sale of the Big Sandy Pipeline, to monetize the value of mature assets to redeploy into higher-growth Marcellus Shale development.

 

·                  Huron Shale. The Company plans to continue developing its highly successful horizontal drilling program in the Huron Shale play, where it drills horizontal wells and, where possible, extends the lateral length.  As many of the Huron wells produce wet gas (with significant NGL content), and NGLs receive higher prices per Btu than natural gas, the Company expects to continue benefiting from the improved economics over an equivalent dry gas well.  The Company has significant midstream capacity in the Huron play and is concentrating its drilling near this capacity to further enhance the return on investment.

 

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Capital Resources and Liquidity

 

Overview

 

The Company’s primary sources of cash for 2010 were cash flows from operating activities and proceeds from an offering of common stock. The Company’s primary uses of cash for 2010 were for capital expenditures and interest and dividend payments.

 

Operating Activities

 

The Company’s net cash provided by operating activities during 2010 was $789.7 million compared to $725.7 million for the same period of 2009.  The increase in cash flows provided by operating activities is primarily attributable to higher earnings resulting from increased production volumes and higher NGL prices partially offset by lower realized natural gas prices. In addition, EQT received income tax refunds of $129.5 million in 2010 primarily relating to the 2009 net operating loss carryback.

 

The Company’s net cash provided by operating activities during 2009 was $725.7 million compared to $509.2 million for the same period of 2008.  EQT received an income tax refund of $115.2 million in 2009 relating to the 2008 net operating loss carryback.  The remaining increase in cash flows provided by operating activities is primarily the result of lower inventory, accounts receivable, unbilled revenues and margin deposits due to lower average natural gas commodity prices in 2009 compared to 2008.  These were partially offset by a corresponding decrease in accounts payable at December 31, 2009 as compared to December 31, 2008.

 

Investing Activities

 

Cash flows used in investing activities totaled $1,239.4 million for 2010 as compared to $985.5 million for 2009.  The increase in cash flows used in investing activities was primarily attributable to an increase in capital expenditures to $1,246.9 million in 2010 from $963.9 million in 2009.  See discussion of capital expenditures below. This increase was partially offset by proceeds from the sale of available for sale securities and reduced capital contributions to Nora Gathering, LLC.

 

Cash flows used in investing activities totaled $985.5 million for 2009 as compared to $1,376.0 million for 2008.  The decrease in cash flows used in investing activities was primarily attributable to the following:

 

·                  a decrease in capital expenditures to $963.9 million in 2009 from $1,344.0 million in 2008 due to the completion of the construction of the Big Sandy Pipeline and Kentucky Hydrocarbon processing plant upgrade in 2008;

 

·                  a decrease in capital contributions to Nora Gathering, LLC for use in midstream infrastructure projects to $6.4 million in 2009 from $29.0 million in 2008;

 

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Capital Expenditures

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2011 Plan

 

 

2010 Actual

 

 

2009 Actual

 

 

2008 Actual

 

 

 

 

 

 

 

 

 

 

 

 

 

Well development (primarily drilling)

 

 

$

691 million

 

 

$

888 million

 

 

$

686 million

 

 

$

615 million

Undeveloped property acquisitions

 

 

$

        –

 

 

$

358 million

 

 

$

31 million

 

 

$

86 million

Midstream infrastructure

 

 

$

244 million

 

 

$

193 million

 

 

$

201 million

 

 

$

594 million

Distribution infrastructure and other corporate items

 

 

$

35 million

 

 

$

39 million

 

 

$

46 million

 

 

$

49 million

Total

 

 

$

970 million

 

 

$

1,478 million

 

 

$

964 million

 

 

$

1,344 million

Less: non-cash

 

 

$

        –

 

 

$

231 million

 

 

$

        –

 

 

$

        –

Total cash capital expenditures

 

 

$

970 million

 

 

$

1,247 million

 

 

$

964 million

 

 

$

1,344 million

 

Capital expenditures for drilling and development totaled $888 million and $686 million during 2010 and 2009, respectively.  The Company drilled 489 gross wells (395 net wells) in 2010, including 90 horizontal Marcellus Shale wells with approximately 300,000 feet of pay and 236 horizontal Huron wells with approximately 1.0 million feet of pay, compared to 702 gross wells (536 net wells) in 2009, including 46 horizontal Marcellus Shale wells with approximately 100,000 feet of pay and 356 horizontal Huron wells with approximately 1.0 million feet of pay.  Capital expenditures for 2010 also included $358 million for undeveloped property acquisitions, primarily within the Marcellus Shale play.  Capital expenditures for 2009 included $31 million for undeveloped property acquisitions.

 

During 2010, the Company acquired approximately 58,000 net acres in the Marcellus Shale from a group of private operators and landowners. The acreage is located primarily in Cameron, Clearfield, Elk and Jefferson counties in Pennsylvania. The purchase included a 200 mile gathering system, with associated rights of way, and approximately 100 producing vertical wells. The Company paid $282.2 million for these assets, $230.7 million in EQT stock and $51.5 million in cash. Following the closing of the acquisition, the Company holds approximately 520,000 net acres in the high pressure Marcellus Shale fairway.

 

Capital expenditures for the midstream operations totaled $193 million for 2010. During the year, EQT Midstream turned in-line 132 miles of pipeline and 21,000 horse power of compression primarily within the Marcellus and Huron Shale plays.  During 2009, midstream capital expenditures were $201 million. EQT Midstream turned in-line 274 miles of pipeline and 21,850 horse power of compression primarily within the Huron play in that year.

 

Capital expenditures at Distribution totaled $37 million and $34 million during 2010 and 2009, respectively, principally for pipeline replacement and metering.  The increase in capital expenditures was due to increased gathering-related infrastructure spending in 2010 as compared to 2009.

 

The Company is committed to profitably expanding its production and reserves through horizontal drilling, exploiting additional reserve potential through key emerging development plays and expanding its infrastructure in the Appalachian Basin through, among other projects, the Equitrans Marcellus expansion project.  Capital expenditures for 2011 are expected to be concentrated on drilling in areas that already benefit from the Company’s substantial Appalachian midstream infrastructure.  The Company’s planned 2011 capital expenditures are designed to achieve annual gas sales volume growth of 30% in 2011, without requiring access to the capital markets.  The Company believes it has sufficient liquidity to finance its planned capital expenditures with cash generated from operating activities as well as the proceeds from the sale of the Kentucky natural gas processing facility.

 

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Financing Activities

 

Cash flows provided by financing activities totaled $449.7 million for 2010 as compared to $259.8 million for 2009 as a result of the proceeds from the 2010 equity offering exceeding the proceeds of the 2009 debt offering, net of repayment of short-term loans.  On March 16, 2010, the Company completed a common stock offering of 12,500,000 shares.  The underwriters in this transaction also exercised their over-allotment option to purchase 225,000 additional shares of the Company’s Common Stock on April 14, 2010. The Company is using the net proceeds of $537.2 million from the offering to accelerate development of its Marcellus and Huron Shale plays.

 

Cash flows provided by financing activities totaled $259.8 million for 2009 as compared to $785.1 million for 2008.  During 2009, the Company received $700 million from the public sale of 8.125% Senior Notes due June 1, 2019.  By comparison, during 2008, the Company received $560.7 million from the public sale of 8.625 million shares of common stock and $500 million from the public sale of 6.50% Senior Notes due April 1, 2018.  A portion of the 2009 and 2008 debt offerings were used to repay short-term borrowings under the Company’s revolving credit facility during the periods.  The Company repaid $314.9 million in short-term borrowing during 2009 and $130.1 million in short-term borrowings during the same period in 2008.  The Company also repaid $4.3 million in long-term debt during 2009.

 

Short-term Borrowings

 

EQT primarily utilizes short-term borrowings to fund capital expenditures in excess of cash flow from operating activities until they can be permanently financed, to ensure sufficient levels of inventory and to fund required margin deposits on derivative commodity instruments. The amount of short-term borrowings used for inventory transactions is driven by the seasonal nature of the Company’s natural gas distribution and marketing operations. Margin deposit requirements vary based on natural gas commodity prices and the amount and type of derivative commodity instruments executed.

 

The Company has a $1.5 billion revolving credit facility that matures on December 8, 2014.  The facility may be used for working capital, capital expenditures, share repurchases and any other lawful corporate purposes, including support of any commercial paper program maintained by the Company from time to time.  The credit facility is underwritten by a syndicate of 20 financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by the Company.  The Company’s large syndicate group and relatively low percentage of participation by each lender is expected to limit the Company’s exposure if problems or consolidation occur in the banking industry.

 

As of December 31, 2010, the Company had outstanding under the revolving credit facility loans of $53.7 million, and an irrevocable standby letter of credit of $23.5 million. The weighted average interest rate for short-term loans outstanding as of December 31, 2010 was 1.8% and the maximum amount of outstanding short-term loans at any time during 2010 was $139.7 million. The average daily balance of short-term loans outstanding over the course of the year was approximately $24.9 million and the weighted average interest rate on the Company’s short-term borrowings was 0.7% for 2010.  Under the terms of the revolving credit facility, the Company may obtain loans, which are base rate loans or fixed period Eurodollar rate loans. Base rate loans are denominated in dollars and bear interest at a base rate plus a margin determined on the basis of the Company’s then current credit rating. Fixed period Eurodollar rate loans bear interest on a Eurodollar rate plus a margin determined on the basis of the Company’s then current credit rating.

 

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 credit ratings for the outstanding debt instruments of the Company at December 31, 2010.  Changes in credit ratings may affect the Company’s cost of short-term and long-term debt (including interest rates and fees under its lines of credit), collateral requirements under derivative instruments and its access to the credit markets.

 

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Table of Contents

 

 

 

Unsecured

 

 

 

 

 

Medium-Term

 

Commercial

 

Rating Service

 

Notes

 

Paper

 

Moody’s Investors Service

 

Baa1

 

P-2

 

Standard & Poor’s Ratings Services

 

BBB

 

A-3

 

Fitch Ratings Service

 

BBB+

 

F2

 

 

On September 30, 2010 Moody’s Investors Services (Moody’s) reaffirmed its ratings on EQT.  The outlook is negative.  Moody’s stated that the “ratings reflect 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 operations.”

 

On September 20, 2010, Standard & Poor’s Ratings Services (S&P) reaffirmed its ratings on EQT.  The outlook is negative.  S&P stated that the ratings and outlook reflect the Company’s “competitive operating cost structure in its exploration and production (E&P) segment, long reserve life” and the Company’s “aggressive spending in its more volatile E&P and midstream businesses.”

 

On March 26, 2010, Fitch affirmed its ratings on EQT stating that the “ratings are supported by the strong performance of its upstream segment, the relatively predictable cash flows from its midstream and distribution segments, a significant use of equity to help finance its growth strategy, and management’s continued maintenance of a strong liquidity position.”

 

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 on derivative contracts 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, 2010, the Company was in compliance with all existing debt provisions and covenants.

 

Commodity Risk Management

 

The Company’s overall objective in its hedging program is to protect cash flow 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, collars and options.

 

The approximate volumes and prices of the Company’s total hedge position for 2011 through 2013 production are:

 

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2011

 

2012

 

2013

 

Swaps

 

 

 

 

 

 

 

Total Volume (Bcf)

 

56

 

24

 

 

Average Price per Mcf (NYMEX)*

 

$

4.86

 

$

5.27

 

$

 

 

 

 

 

 

 

 

 

Puts

 

 

 

 

 

 

 

Total Volume (Bcf)

 

3

 </