10-K 1 a13-25494_110k.htm 10-K

Table of Contents

 

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, 2013

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

(State or other jurisdiction of incorporation or organization)

 

625 Liberty Avenue

Pittsburgh, Pennsylvania

(Address of principal executive offices)

25-0464690

(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.   [  ]

 

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, 2013: $11.9 billion

 

The number of shares (in thousands) of common stock outstanding

as of January 31, 2014: 150,893

 

DOCUMENTS INCORPORATED BY REFERENCE

 

The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held April 30, 2014) will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2013 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

 

Cautionary Statements

6

 

PART I

 

Item 1

Business

7

Item 1A

Risk Factors

17

Item 1B

Unresolved Staff Comments

22

Item 2

Properties

22

Item 3

Legal Proceedings

27

Item 4

Mine Safety and Health Administration Data

27

 

Executive Officers of the Registrant

28

 

 

 

 

 

 

PART II

 

 

 

Item 5

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

29

Item 6

Selected Financial Data

31

Item 7

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

32

Item 7A

Quantitative and Qualitative Disclosures About Market Risk

54

Item 8

Financial Statements and Supplementary Data

57

Item 9

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

113

Item 9A

Controls and Procedures

113

Item 9B

Other Information

113

 

PART III

 

Item 10

Directors, Executive Officers and Corporate Governance

114

Item 11

Executive Compensation

114

Item 12

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

115

Item 13

Certain Relationships and Related Transactions and Director Independence

115

Item 14

Principal Accounting Fees and Services

115

 

 

 

PART IV

 

 

 

Item 15

Exhibits and Financial Statement Schedules

116

 

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

116

 

Index to Exhibits

118

 

Signatures

126

 

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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.  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 composed of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie in the Appalachian Mountains.

 

basis – when referring to commodity pricing, 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, transportation capacity availability 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.

 

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.

 

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.

 

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 derivative contract to guarantee fulfillment of contract obligations.

 

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Glossary of Commonly Used Terms, Abbreviations and Measurements

 

NGL – 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 and iso-butane.

 

net – “net” natural 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 interests (equal to 100% minus all royalties on a well or property).

 

play – a proven geological formation that contains commercial amounts of hydrocarbons.

 

proved reserves –quantities of oil, natural gas, and NGLs which, by analysis of geological 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.

 

throughput – the volume of natural gas transported or passing through a pipeline, plant, terminal, or other facility during a particular period.

 

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.

 

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Glossary of Commonly Used Terms, Abbreviations and Measurements

 

Abbreviations

 

ASC – Accounting Standards Codification

CBM – Coalbed Methane

CFTC – Commodity Futures Trading Commission

EPA – U.S. Environmental Protection Agency

FASB – Financial Accounting Standards Board

FERC – Federal Energy Regulatory Commission

IPO – initial public offering

IRS – Internal Revenue Service

NYMEX – New York Mercantile Exchange

OTC – over the counter

SEC – Securities and Exchange 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, with one barrel of NGLs and crude oil

being equivalent to 6,000 cubic feet of natural gas

Dth  =  million British thermal units

Mcf  =  thousand cubic feet

Mcfe  =  thousand cubic feet of natural gas

equivalents, with one barrel of NGLs and crude oil

being equivalent to 6,000 cubic feet of natural gas

Mbbl  =  thousand barrels

MMBtu  =  million British thermal units

MMcf  =  million cubic feet

MMcfe  =  million cubic feet of natural gas

equivalents, with one barrel of NGLs and crude oil

being equivalent to 6,000 cubic feet of natural gas

TBtu = trillion British thermal units

Tcfe  =  trillion cubic feet of natural gas

equivalents, with one barrel of NGLs and crude oil

being equivalent to 6,000 cubic feet of natural gas

 

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Cautionary Statements

 

Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended.  Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,” “estimate,” “could,” “would,” “will,” “may,” “forecast,” “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 Annual Report on Form 10-K include the matters discussed in the sections captioned “Strategy” in Item 1, “Business” and “Outlook” in Item 7, “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 strategy to develop its Marcellus and other reserves; drilling plans and programs (including the number, type, feet of pay and location of wells to be drilled, the conversion of drilling rigs to utilize natural gas and the availability of capital to complete these plans and programs); the expiration of leasehold terms before production can be established; production sales volumes (including liquid volumes); gathering and transmission volumes (including the subscription of additional capacity related to the expiration of EQT Midstream Partners, LP firm transportation contracts); infrastructure programs (including the timing, cost and capacity of the transmission and gathering expansion projects); technology (including drilling and completion techniques); monetization transactions, including midstream asset sales (dropdowns) to EQT Midstream Partners, LP and other asset sales, joint ventures or other transactions involving the Company’s assets; natural gas prices and changes in basis; reserves; projected capital expenditures; liquidity and financing requirements, including funding sources and availability; hedging strategy; the effects of government regulation and litigation; operation of the Company’s fleet vehicles on natural gas; and tax position.  The forward-looking statements included in this Annual Report on Form 10-K 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 Annual Report on 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 statement, whether as a result of new information, future events or otherwise.

 

In reviewing any agreements incorporated by reference in or filed with this Annual Report on 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 to such agreements 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 of the Company or its affiliates 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 two business segments: EQT Production and EQT Midstream. EQT Production is one of the largest natural gas producers in the Appalachian Basin with 8.3 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 3.6 million gross acres, including approximately 580,000 gross acres in the Marcellus play, as of December 31, 2013. EQT Midstream provides gathering, transmission and storage services for the Company’s produced gas, as well as for independent third parties across the Appalachian Basin.

 

Key Events in 2013

 

During 2013, EQT achieved record annual production sales volumes, including a 43% increase in total sales volumes and an 82% increase in Marcellus sales volumes.  The Midstream business delivered record gathered volumes that were 39% higher than the previous year.  The Company also completed the following transactions that were instrumental in contributing to a successful 2013:

 

·                  On July 22, 2013, Sunrise Pipeline, LLC (Sunrise), a subsidiary of the Company, merged with and into Equitrans, L.P. (Equitrans), a subsidiary of EQT Midstream Partners, LP (the Partnership), with Equitrans continuing as the surviving company (the Sunrise Merger). Sunrise continues to be consolidated by the Company as it is still under common control.

 

·                  On July 22, 2013, the Partnership completed an underwritten public offering of 12,650,000 common units representing Partnership limited partner interests. Following the offering and the closing of the Sunrise Merger, the Company holds a 44.6% equity interest in the Partnership, including a 2% general partner interest. The Partnership received net proceeds of $529.4 million from the offering, after deducting the underwriters’ discount and offering expenses of $20.9 million.

 

·                  On December 17, 2013, the Company and its wholly-owned subsidiary, Distribution Holdco, LLC (Holdco), completed a previously announced transaction relating to the Company, Holdco, and PNG Companies LLC (PNG Companies), the parent company of Peoples Natural Gas Company LLC.  As part of the transaction, the Company and Holdco transferred 100% of their ownership interests in Equitable Gas Company, LLC (Equitable Gas) and Equitable Homeworks, LLC (Homeworks) to PNG Companies.  As consideration for this transaction, the Company received a $740.6 million cash payment, based on initial post-closing adjustments, select midstream assets, including an approximately 200-mile FERC-regulated natural gas transmission pipeline that interconnects with the Partnership’s transmission and storage system (the AVC facilities), and new commercial arrangements with PNG Companies and its affiliates. These events are collectively referred to in this Annual Report on Form 10-K as the Equitable Gas Transaction.

 

Equitable Gas and Homeworks comprised substantially all of the Company’s previously reported Distribution segment.  The financial information of Equitable Gas and Homeworks is reflected as discontinued operations in this Annual Report on Form 10-K with all prior periods recast to reflect the presentation of discontinued operations.

 

EQT Production Business Segment

 

EQT believes that it is a technology leader in extended lateral horizontal and completion drilling in the Appalachian Basin and continues to improve its operations through the use of new technology.  EQT Production’s strategy is to maximize shareholder value by maintaining an industry leading cost structure to profitably develop its reserves.  EQT’s proved reserves increased 39% in 2013, to a total of 8.3 Tcfe primarily across the Marcellus and Huron shale plays, and also including CBM and other vertical wells.  The Company’s Marcellus assets, including Upper Devonian assets, contribute approximately 6.2 Tcfe in total proved reserves.

 

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The following illustration depicts EQT’s acreage position within the Marcellus play:

 

 

 

 

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As of December 31, 2013, the Company’s proved reserves were as follows:

 

 

(Bcfe)

 

Marcellus

 

Huron *

 

Upper
Devonian

 

CBM/Utica/
Other

 

Total

Proved Developed

 

1,899

 

1,118

 

109

 

860

 

3,986

Proved Undeveloped

 

4,057

 

198

 

106

 

1

 

4,362

Total Proved Reserves

 

5,956

 

1,316

 

215

 

861

 

8,348

 

* Includes the Lower Huron, Cleveland, Berea sandstone and other Devonian age formations.

 

The Company’s natural gas wells are generally low-risk, having a long reserve life with relatively low development and production costs on a per unit basis.  Assuming that future annual production from these reserves is consistent with 2013, the remaining reserve life of the Company’s total proved reserves, as calculated by dividing total proved reserves by 2013 produced volumes, is 23 years.

 

The Company invested approximately $1,237 million on well development during 2013, with total production sales volumes hitting a record high of 378.2 Bcfe, an increase of 43% over the previous year.  Capital spending for EQT Production is expected to be approximately $1.9 billion in 2014 (excluding land acquisitions), the majority of which will be used to support the drilling of approximately 357 gross wells, including 186 Marcellus wells, 120 Huron wells, 30 Upper Devonian wells and 21 wells in the Utica Shale of Ohio. During the past three years, the Company’s number of wells drilled (spud) and related capital expenditures for well development were:

 

 

 

Years Ended December 31,

 

 

 

 

 

Gross wells spud:

 

2013

 

2012

 

2011

 

Horizontal Marcellus*

 

168

 

127

 

105

 

Horizontal Huron

 

50

 

7

 

115

 

Horizontal Utica

 

7

 

1

 

 

Total horizontal

 

225

 

135

 

220

 

Other

 

 

 

2

 

Total

 

225

 

135

 

222

 

 

 

Capital expenditures for well development:

 (in millions):

 

 

 

 

 

 

 

Horizontal Marcellus*

 

  $

1,103

 

  $

810

 

  $

686

 

Horizontal Huron

 

79

 

22

 

226

 

Horizontal Utica

 

46

 

4

 

 

Total horizontal

 

1,228

 

836

 

912

 

Other

 

9

 

21

 

26

 

Total

 

  $

1,237

 

  $

857

 

  $

938

 

 

* Includes Upper Devonian formations

 

EQT Midstream Business Segment

 

The Appalachian Basin has been an area of significant natural gas production growth in recent years.  The Company believes that the current footprint of its midstream assets, which spans a wide area of the Marcellus Shale in southwestern Pennsylvania and northern West Virginia, is a competitive advantage that uniquely positions it for growth.  In conjunction with the continued growth of EQT Production and other producers in the Marcellus, EQT Midstream is strategically positioned to capitalize on the rapidly increasing need for gathering and

 

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transmission infrastructure in the region.  In particular, there is a need for midstream header connectivity to interstate pipelines in Pennsylvania and West Virginia.

 

In 2012, the Company formed the Partnership to own, operate, acquire and develop midstream assets in the Appalachian Basin.  The Partnership provides midstream services to the Company and other third parties through its two primary assets: the Partnership’s transmission and storage system and the Partnership’s gathering system.  As of December 31, 2013, the Company held a 42.6% limited partner interest and a 2% general partner interest in the Partnership, whose results are consolidated in the Company’s financial statements.  Unless otherwise noted, discussions of EQT Midstream’s business, operations and results in this Annual Report on Form 10-K include the Partnership’s business, operations and results. The Company records the noncontrolling interest of the public limited partners in its financial statements.

 

The Company’s gathering system includes approximately 9,450 miles of gathering lines, 1,600 miles of which are FERC-regulated, low-pressure gathering lines owned by the Partnership.  The left-hand map on page 11 depicts the Company’s gathering lines and compressor stations in relationship to the Marcellus Shale formation. During 2013, the Company completed various gathering line expansion projects that added approximately 385 MMcf per day of incremental gathering capacity and resulted in year-end Marcellus gathering capacity of 1,500 MMcf per day, 1,150 MMcf per day in Pennsylvania and 350 MMcf per day in West Virginia.  To support the ongoing production of natural gas throughout the Marcellus region, the Company plans to add approximately 440 MMcf per day of incremental gathering capacity in 2014, 120 MMcf per day in Pennsylvania and 320 MMcf per day in West Virginia.

 

EQT Midstream’s transmission and storage system includes approximately 900 miles of FERC-regulated interstate pipeline that connects to seven interstate pipelines and multiple distribution companies.  The interstate pipeline system includes approximately 700 miles of pipe owned by Equitrans and referred to as the Equitrans transmission and storage system. Equitrans is owned by the Partnership. EQT Midstream’s transmission and storage system also includes an approximately 200 mile pipeline referred to as the Allegheny Valley Connector (AVC), which was acquired by the Company in connection with the Equitable Gas Transaction.

 

The transmission and storage system is supported by eighteen natural gas storage reservoirs with approximately 660 MMcf per day of peak delivery capability and 47 Bcf of working gas capacity. Fourteen of these reservoirs, representing 400 MMcf per day of peak delivery capability and 32 Bcf of working gas capacity, are owned by the Partnership. The storage reservoirs are clustered in two geographic areas connected to the Partnership’s transmission and storage system, with ten in southwestern Pennsylvania and eight in northern West Virginia.   The AVC facilities include four storage reservoirs owned by the Company and are operated by the Partnership under a lease between the Partnership and an affiliate of the Company.

 

The right-hand map on page 11 depicts the Company’s transmission lines, storage pools and compressor stations in relationship to the Marcellus Shale formation. The Company completed a number of midstream expansion projects in 2013 to take advantage of rapid production development in the Marcellus play.  During 2013, the Company added approximately 450 MMcf per day of incremental transmission capacity in Pennsylvania through the Morris III interconnect expansion and the Low Pressure East Pipeline uprate projects.  As a result of these expansion projects and the AVC acquisition, EQT Midstream year-end total transmission capacity was 2,700 MMcf per day. During 2014, the Company expects to complete the fully subscribed Jefferson compression expansion project, which is expected to add an additional 650 BBtu per day of transmission capacity in Pennsylvania, as well as an expansion of the west-side of its northern West Virginia transmission system, referred to as the West-Side Expansion Project, that is expected to add 100 BBtu per day of capacity.

 

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EQT Midstream also has a gas marketing subsidiary, EQT Energy, LLC (EQT Energy), that provides optimization of capacity and storage assets through its NGL and natural gas sales to commercial and industrial customers within its operational footprint. EQT Energy also provides marketing services and manages approximately 1,000,000 Dth per day of third-party contractual pipeline capacity for the benefit of EQT Production; and has committed to an additional 750,000 Dth per day of contractual capacity to come online in future periods. EQT Energy currently leases 3.2 Bcf of storage-related assets from third parties.

 

Strategy

 

EQT’s strategy is to maximize shareholder value by maintaining an industry leading cost structure, profitably developing its undeveloped reserves, and effectively and efficiently utilizing its extensive gathering and

 

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transmission assets that are uniquely positioned across the Marcellus Shale and in close proximity to the northeastern United States markets.

 

EQT believes that it is a technology leader in extended-lateral horizontal drilling and completion in the Appalachian Basin and continues to improve its operations through the use of new technology.  Substantially all of the Company’s acreage is held by production or in fee; therefore, EQT Production is able to develop its acreage in the most economical manner through the use of longer laterals and multi-well pads, as opposed to being required to drill less-economical wells in order to retain acreage. The use of multi-well pads, in conjunction with a completion technique known as reduced cluster spacing, has the additional benefit of reducing the overall environmental surface footprint of the Company’s drilling operations.

 

EQT also believes that its midstream assets are strategically located in the Marcellus Shale region – spanning a large, prolific area of southwestern Pennsylvania and northern West Virginia – providing a competitive advantage that uniquely positions the Company for continued growth.  EQT Midstream intends to capitalize on the rapidly growing need for gathering and transmission infrastructure in this region, and in particular the need for midstream header connectivity to interstate pipelines in Pennsylvania and West Virginia.

 

The ongoing efforts of the Partnership are also an important support mechanism for EQT’s overall business strategy. Through pursuing accretive acquisitions from the Company, capitalizing on economically attractive organic growth opportunities, and attracting additional third-party volumes, the Partnership is expected to provide an ongoing source of capital to the Company.

 

The Company is also helping to build additional demand for natural gas. In mid-2011, with the assistance of a $700,000 grant received from the Pennsylvania Department of Environmental Protection, EQT opened a public-access natural gas fueling station in Pittsburgh, Pennsylvania.  With the growing popularity and importance of this station to numerous fleets throughout the region, the station underwent an expansion in 2013 – adding two more service bays.  In conjunction with this project, the Company is promoting the use of natural gas fleet vehicles, including its own, and plans to operate 15% of its light-duty vehicle fleet, more than 180 vehicles, on natural gas by the end of 2014.  In addition, the Company is operating four drilling rigs that utilize natural gas and one hydraulic fracturing unit, with an additional unit expected in 2014.

 

See “Capital Resources and Liquidity” in Item 7, “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:  The Company’s produced natural gas is sold to marketers, utilities and industrial customers located mainly in the Appalachian Basin and a gas processor in Kentucky and West Virginia.  Natural gas is a commodity and therefore the Company receives market-based pricing.  The market price for natural gas can be volatile as demonstrated by significant declines in late 2011 and early 2012.  In addition, the market price for natural gas in the Appalachian Basin experienced a decline relative to the price at Henry Hub, which is the location for pricing NYMEX and natural gas futures, in the second half of 2013 as a result of the increased supply of natural gas in the Northeast region.  Changes in the market price for natural gas, including basis, impact the Company’s revenues, earnings and liquidity.  The Company is unable to predict potential future movements in the market price for natural gas, including Appalachian basis, and thus cannot predict the ultimate impact of prices on its operations; however, the Company monitors the market for natural gas and adjusts strategy and operations as deemed to be appropriate.  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, most of which is hedged at NYMEX natural gas prices.  The Company’s hedging strategy and information regarding its derivative instruments is set forth in “Commodity Risk Management” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” and in Notes 1 and 5 to the Consolidated Financial Statements.

 

NGL Sales:  The Company sells NGLs from its own production through the EQT Production segment and from gas marketed for third parties by EQT Midstream.  Until February 2011, when the Company sold its Langley natural gas processing complex (Langley), the Company processed natural gas in order to extract heavier liquid

 

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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 Langley 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 Langley to MarkWest Energy Partners, L.P. in February 2011, the processing of the Company’s produced natural gas has been performed by a third-party vendor.

 

The following table presents the effective sales price on an average Mcfe basis to EQT Corporation for sales of produced natural gas, NGLs and oil, with and without hedges, for the years ended December 31:

 

 

 

2013

 

2012

 

2011

 

 

 

 

 

 

 

 

 

Average effective sales price per Mcfe sold (including hedges)

 

$

4.13

 

$

4.17

 

$

5.23

 

Average effective sales price per Mcfe sold (excluding hedges)

 

$

3.77

 

$

3.07

 

$

4.72

 

 

In addition, realized price information for all products is included in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” under the caption “Consolidated Operational Data,” and incorporated herein by reference.

 

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 four major interstate pipelines: Columbia Gas Transmission, East Tennessee Natural Gas Company, Dominion Transmission and Tennessee Gas Pipeline Company.  The gathering system also maintains interconnections with the Partnership’s transmission and storage system.

 

Gathering system transportation volumes for 2013 totaled 466.4 BBtu, of which approximately 79% related to gathering for EQT Production, 9% related to third-party volumes and 12% related to volumes for other affiliates of the Company.  Revenues from EQT Production and other affiliates accounted for approximately 88% of 2013 gathering revenues.

 

Natural Gas Transmission, Storage and Marketing: Natural gas transmission and storage operations are executed using transmission and underground storage facilities owned and/or operated by the Company or the Partnership.  EQT Energy provides marketing services and third-party contractual pipeline capacity management for the benefit of EQT Production and leases storage capacity in order to take advantage of seasonal spreads where available.   EQT Energy also engages in risk management and energy trading activities, the objective of which 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.

 

As of December 31, 2013, the weighted average remaining contract life based on total projected contracted revenues for the Partnership’s firm transmission and storage contracts was approximately 15 years.  The Company anticipates that the capacity associated with expiring contracts will be remarketed or used by affiliates such that the capacity will remain fully subscribed.  In 2013, approximately 80% of transportation volumes and revenues were from affiliates.

 

The Company had one customer within the EQT Production segment account for approximately 11% of its revenues in 2013. The Company does not believe that the loss of this customer would have a material adverse effect on its business because alternative customers for the Company’s natural gas are available.  No single customer accounted for more than 10% of revenues in 2012 or 2011.

 

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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.  Competition for natural gas gathering, transmission and storage volumes is primarily based on rates and other commercial terms, customer commitment levels, timing, performance, reliability, service levels, location, reputation and fuel efficiencies.  Key competitors in the natural gas transmission and storage market include companies that own major natural gas pipelines. Key competitors for gathering systems include independent gas gatherers and integrated energy companies. EQT competes with numerous companies when marketing natural gas and NGLs. Some of these competitors are affiliates of companies with extensive pipeline systems that are used for transportation from producers to end-users.

 

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 royalties and taxes; and the gathering of production in certain circumstances.  These regulations may affect the costs and timing 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. In 2013, the Pennsylvania legislature enacted lease integration legislation, which authorizes joint development of existing leases. In West Virginia, it is necessary to rely on voluntary pooling of lands and leases.  In addition, state conservation and oil and gas laws generally limit the venting or flaring of natural gas.

 

EQT Midstream’s transmission and gathering operations are subject to various types of federal and state environmental laws and local zoning ordinances, including air permitting requirements for compressor station and dehydration units; erosion and sediment control requirements for compressor station and pipeline construction projects; waste management requirements and spill prevention plans for compressor stations; various recordkeeping and reporting requirements for air permits and waste management practices; compliance with safety regulations; and siting and noise regulations for compressor stations. These regulations may increase the costs of operating existing pipelines and compressor stations and increase the costs of, and the time to develop, new or expanded pipelines and compressor stations.

 

The interstate natural gas transmission systems and storage operations of EQT Midstream are regulated by the FERC, and certain gathering lines are also subject to rate regulation by the FERC. For instance, the FERC approves tariffs that establish the Partnership’s rates, cost recovery mechanisms and other terms and conditions of service to the Partnership’s customers. The fees or rates established under the Partnership’s tariffs are a function of its costs of providing services to customers, including a reasonable return on invested capital. The FERC’s authority over transmission operations also extends to: storage and related services; certification and construction of new interstate transmission and storage facilities; extension or abandonment of interstate transmission and storage 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.

 

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In July 2010, the U.S. Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivative market and entities, such as the Company, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), required the CFTC and the SEC to promulgate rules and regulations implementing the new legislation. As of the filing date of this Annual Report, the CFTC had adopted and implemented many final rules that impose regulatory obligations on all market participants, including the Company, such as recordkeeping and certain reporting obligations.  Other CFTC rules that may be relevant to the Company have yet to be proposed or finalized and, in some cases, finalized rules have yet to be implemented.  Because significant CFTC rules relevant to natural gas hedging activities are still at the proposal stage, it is not possible at this time to predict the extent of the impact of the new regulations on the Company’s hedging program or regulatory compliance obligations.  The Company anticipates, however, increased compliance costs and changes to current market practices as participants continue to adapt to a changing regulatory environment.

 

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.  Additional proposals that affect the oil and gas industry are regularly considered by the U.S. 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; pollution; site remediation; and preservation or protection of human health and safety, natural resources, wildlife and the environment. The Company must take into account environmental, health and safety regulations in, among other things, planning, designing, constructing (including drilling), operating and abandoning wells, pipelines and related facilities.

 

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 deeper formations are geologically separated and isolated from fresh ground water supplies by overlying 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.  To assess water sources near our drilling locations, the Company conducts baseline and, as appropriate, post-drilling water testing at all water wells within at least 2,500 feet of our drilling pads.  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 or limit the Company’s ability to obtain permits 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 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

 

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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 fossil 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 1,621 employees at the end of 2013, and none are subject to a collective bargaining agreement.

 

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.

 

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.

 

 

 

For the Years Ended
December 31,

 

 

 

 

2013

 

 

2012

 

 

2011

 

EQT Production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

 

61%

 

55%

 

51%

 

 

 

 

 

 

 

 

 

EQT Midstream:

 

 

 

 

 

 

 

Gathering revenue

 

18%

 

20%

 

17%

 

 

 

 

 

 

 

 

 

Natural gas liquids sales (a)

 

6%

 

8%

 

10%

 

 

(a)         NGL sales are included in the operations of both EQT Production and EQT Midstream.

 

Financial Information about Segments

 

See Note 4 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.

 

Jurisdiction and Year of Formation

 

The Company is a Pennsylvania corporation formed in 2008 in connection with a holding company reorganization of the former Equitable Resources, Inc.

 

Financial Information about Geographic Areas

 

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

 

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Environmental

 

See Note 18 to the Consolidated Financial Statements for information regarding environmental matters.

 

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 occur, 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; regional basis differentials; national and worldwide economic and political conditions; the price and availability of alternative fuels; the availability, proximity and capacity of pipelines, other transportation facilities, and gathering, processing and storage 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, operating income and cash flow for each of our businesses, a reduction in drilling activity and the construction of new transportation capacity and downward adjustments to the value of oil and gas properties 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 operating income. A reduction in operating income 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 production taxes, increased lease operating expenses, increased volatility in seasonal gas price spreads for our storage assets and increased end-user conservation or conversion to alternative fuels.  Significant price increases may 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 and storage of natural gas and NGLs, such as well site blowouts, cratering and explosions, pipe and other equipment and system failures, uncontrolled flows of natural gas or well fluids, fires, formations with abnormal pressures, pollution and environmental risks and natural disasters.  We also face various security risks, including cyber security threats to gain unauthorized access to sensitive information, render data or systems unusable or otherwise disrupt our business operations, and threats to the security of our or third parties’ facilities and infrastructure, such as processing plants and pipelines.  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, pollution or other environmental damage, disruptions to our operations and loss of sensitive confidential information.  Moreover, in

 

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the event that one or more of these hazards occur, there can be no assurance that a response will be adequate to limit or reduce damage.  As a result of these risks, we are also 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.

 

Our failure to develop, obtain or 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, proximity and capacity of pipelines, other transportation facilities and gathering and processing facilities. The capacity of transportation, gathering and processing facilities may be insufficient to accommodate potential production from existing and new wells.  Competition for pipeline infrastructure within the region is intense, and many of our competitors have substantially greater financial resources than we do, which could affect our competitive position. 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 curtailments on such pipelines. Our infrastructure development and maintenance programs can involve significant risks, including those related to timing, cost overruns and operational efficiency, and these risks can be affected by the availability of capital, materials and qualified contractors and work force, as well as weather conditions, gas price volatility, government approvals, title and property access 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 transportation, gathering, processing and storage facilities which are limited in number, geographically concentrated and subject to the same risks identified above with respect to our infrastructure development and maintenance programs.  Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. An extended interruption of access to or service from our or third-party pipelines and facilities for any reason, including cyber-attacks on such pipelines and facilities, could result in adverse consequences to us, such as delays in producing and selling our natural gas.  In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX or than we currently project.  In addition, some of our third-party contracts may involve significant long-term financial commitments on our part.  Moreover, our usage of third parties for transportation, gathering and processing services subjects us to the credit and performance risk of such third parties and may make us dependent upon those third parties to get our produced natural gas to market.

 

Also, our producing properties and operations are limited to the Appalachian Basin, making us vulnerable to risks associated with operating in limited geographic areas. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of gas produced from this area.

 

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 2014 business plan, we considered allocating capital and other resources to various aspects of our businesses, including well development (primarily drilling), reserve acquisitions, exploratory activities, midstream infrastructure, corporate items and other alternatives.  We also considered our likely sources of capital and evaluated opportunities outside of the Appalachian Basin.  Notwithstanding the determinations made in the development of our 2014 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, including the appropriate rate of reserve development, 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.  Moreover economic or other circumstances may change from those contemplated by our 2014 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

 

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We periodically engage in acquisitions, dispositions and other strategic transactions.  These transactions involve various inherent risks, such as our ability to obtain the necessary regulatory approvals; the timing of and conditions imposed upon us by regulators in connection with such approvals; and our ability to achieve benefits anticipated to result from acquisition or disposition of the assets.  In addition, various factors including prevailing market conditions could negatively impact the benefits we receive from transactions.  Our inability to complete a transaction or to achieve our strategic or financial goals in any transaction could have significant adverse effects on our earnings, cash flows and financial position.

 

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 and transmission systems and pipelines.  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; locations available for drilling and pipeline construction; environmental impact studies and assessments prior to permitting; restoration of drilling properties after drilling is completed; pipeline safety (including replacement requirements); 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 or result in delays due to the need to obtain additional or more detailed governmental approvals and permits.  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 and storage businesses are, in many cases, subject to federal regulation by the FERC, which 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 and/or expense deferrals.

 

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.  In addition to periodic changes to air, water and waste laws, as well as recent EPA initiatives to impose climate change-based air regulations on the industry, the U.S. Congress and various states have been evaluating climate-related legislation and other regulatory initiatives that would further 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 the release, capture and use of, greenhouse gases that could have an adverse effect on our operations.

 

Another area of potential regulation is hydraulic fracturing, which we utilize 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 or is under discussion at the federal and state levels.  We cannot predict whether any such federal or state legislation or regulation will be enacted and, if enacted, how it may affect our operations, but enactment of additional laws or regulations could increase our operating costs.

 

Recent discussions regarding the federal budget have included proposals which could potentially increase and accelerate the payment of federal and collaterally state income taxes of independent producers with the potential repeal of the ability to expense intangible drilling costs having the most significant potential future impact to us. 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

 

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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 earnings, cash flows and financial position.

 

In July 2010, the U.S. Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivative market and entities, such as the Company, that participate in that market. The new legislation, known as the Dodd-Frank Act, required the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing the new legislation. As of the filing date of this Annual Report, the CFTC had adopted and implemented many final rules that impose regulatory obligations on all market participants, including the Company, such as recordkeeping and certain reporting obligations.  Other rules that may be relevant to the Company or its counterparties have yet to be proposed or finalized and, in some cases, finalized rules have yet to be implemented.  Because significant rules relevant to natural gas hedging activities are still at the proposal stage, it is not possible at this time to predict the extent of the impact of the new regulations on the Company’s hedging program, including available counterparties, or regulatory compliance obligations.  The Company anticipates, however, increased compliance costs and changes to current market practices as participants continue to adapt to a changing regulatory environment.

 

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 flows 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.

 

Any downgrade of our credit ratings may increase the cost of borrowing or adversely affect our ability to raise capital through the issuance of debt or equity securities or other borrowing arrangements, which could adversely affect our business, results of operations and liquidity.  We cannot be sure that our current ratings will remain in effect for any given period of time or that our rating will not be lowered or withdrawn entirely by a rating agency.  An increase in the level of our indebtedness in the future may result in a downgrade in the ratings that are assigned to our debt.  Any downgrade in our ratings could result in an increase in our borrowing costs, which would diminish financial results.

 

Our 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 well 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, any 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 or other hydrocarbons, 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.

 

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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, equipment, a qualified work force, and adequate capacity for the treatment and recycling or disposal of waste water generated in our operations, as well as weather conditions, gas price volatility, government approvals, title and property access problems, geology, equipment failure or accidents 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.

 

We also rely on third parties for certain construction, drilling and completion services, materials and supplies.  Delays or failures to perform by such third parties could adversely impact our earnings, cash flows and financial position.

 

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 technical personnel and certain other professionals, which could increase the costs associated with attracting and retaining such personnel. 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.

 

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, oil spills, the explosion of natural gas transmission lines and concerns raised by advocacy groups about hydraulic fracturing, may lead to increased regulatory scrutiny which may, in turn, lead to new local, state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.  These actions 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.

 

The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated natural gas and oil reserves.

 

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves.  In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the twelve month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net cash flows from our properties will be affected by factors such as the actual prices we receive for natural gas, NGLs and oil and the amount, timing and cost of actual production.  In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas, NGL and oil industry in general.

 

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Our proved reserves are estimates that are based upon many assumptions that may prove to be inaccurate.  Any significant change in these underlying assumptions will greatly affect the quantities and present value of our reserves.

 

Reserve engineering is a subjective process involving estimates of underground accumulations of natural gas, NGLs and oil and assumptions concerning future prices, production levels and operating and development costs.   These estimates and assumptions are inherently imprecise.  As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.   Any significant variance from our assumptions could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas, NGLs and oil, the classifications of reserves based on risk of recovery and estimates of the future net cash flows.  Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas, NGLs and oil we ultimately recover being different from our reserve estimates.

 

See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” for further discussion regarding the Company’s exposure to market risks, including the risks associated with our use of derivative contracts to hedge commodity prices.

 

Item 1B.            Unresolved Staff Comments

 

None.

 

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 (i) 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 (ii) 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 Pennsylvania, West Virginia, Ohio, Kentucky and Virginia.  This segment has approximately 3.6 million gross acres (approximately 63% of which are considered undeveloped), which encompass substantially all of the Company’s acreage of proved developed and undeveloped natural gas and oil producing properties.  Approximately 580,000 of these gross acres are located in the Marcellus play.  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, 2013, the Company estimated its total proved reserves to be 8.3 Tcfe, consisting of proved developed producing reserves of 3.8 Tcfe, proved developed non-producing reserves of 0.2 Tcfe and proved undeveloped reserves of 4.4 Tcfe. Substantially all of the Company’s reserves reside in continuous accumulations.

 

The Company’s estimate of proved natural gas, NGL and oil reserves is prepared by Company engineers.  The engineer primarily responsible for preparing the reserve report and the technical aspects of the reserves audit received a bachelor’s degree in Petroleum and Natural Gas Engineering from the Pennsylvania State University and has 25 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, division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems, and the reserve reconciliation between prior year reserves and current year reserves is reviewed by senior management.

 

The Company’s estimate of proved natural gas, NGL 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 reviewed 100% of the total net gas, NGL and oil proved reserves attributable to the Company’s interests as of December 31, 2013.  Ryder Scott conducted a detailed, well by well,

 

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audit of the Company’s largest properties.  This audit covered 80% of the Company’s proved reserves.  Ryder Scott’s audit of the remaining 20% of the Company’s properties consisted of an audit of aggregated groups not exceeding 200 wells per group.  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, NGL and crude oil reserves and future net cash flows is provided in Note 21 (unaudited) to the Consolidated Financial Statements.

 

In 2013, the Company commenced drilling operations (spud or drilled) on 168 gross horizontal wells with an aggregate of approximately 830,000 feet of pay in the Marcellus play. Total proved reserves in the Marcellus play increased 44% to 6.2 Tcfe in 2013 primarily as a result of the Company’s 2012 and 2013 drilling programs. In the Huron play, the Company spud 50 gross horizontal wells during 2013 with an aggregate of approximately 300,000 feet of pay.  Total proved reserves in the Huron play (including vertical non-shale formations of 0.7 Tcfe) increased approximately 27% to 2.0 Tcfe, as the Company re-established development of the Huron play.  The Company spud 7 wells in the Utica Shale in 2013 with an aggregate of approximately 42,000 feet of pay.  Total proved reserves in the Utica play are less than 0.1 Tcfe. The Company did not drill any CBM wells in 2013.  The CBM play had total proved reserves of 0.2 Tcfe at December 31, 2013, a slight increase from 2012.  Production sales volumes in 2013 from the Marcellus, Huron and CBM plays were 275.0 Bcfe, 35.3 Bcfe and 12.4 Bcfe, respectively.  Over the past three years, the Company has experienced a 99% developmental drilling success rate.

 

Natural gas, BTU premium, NGL and crude oil production and pricing:

 

 

 

For the Years Ended December 31,

 

 

 

2013

 

2012

 

2011

 

Natural Gas:

 

 

 

 

 

 

 

Average effective sales price to EQT Corporation per Mcf
(including hedges)

 

 $

3.61

 

 $

3.64

 

 $

4.40

 

BTU Premium (ethane sold as natural gas):

 

 

 

 

 

 

 

Average sales price per Btu

 

 $

3.66

 

 $

2.83

 

 $

4.04

 

NGLs:

 

 

 

 

 

 

 

Average sales price per Bbl

 

 $

45.58

 

 $

49.29

 

 $

67.41

 

Crude Oil:

 

 

 

 

 

 

 

Average sales price per Bbl

 

 $

85.82

 

 $

83.95

 

 $

81.58

 

 

NGLs and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods. Information for periods prior to 2013 has been recast to reflect this conversion rate.

 

For additional information on production and pricing, see “Consolidated Operational Data” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

The Company’s average per unit production cost, excluding production taxes, of natural gas, NGLs and oil during 2013, 2012 and 2011 was $0.15, $0.17 and $0.20 per Mcfe, respectively.  At December 31, 2013, the Company had approximately 50 multiple completion wells.

 

 

 

Natural Gas

 

Oil

 

Total productive wells at December 31, 2013:

 

 

 

 

 

Total gross productive wells

 

14,622

 

5

 

Total net productive wells

 

12,822

 

5

 

Total in-process wells at December 31, 2013:

 

 

 

 

 

Total gross in-process wells

 

     147

 

 

Total net in-process wells

 

     144

 

 

 

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Summary of proved natural gas, oil and NGL reserves as of December 31, 2013 based on average fiscal year prices:

 

 

 

Natural Gas
(Mcf)

 

Oil and
NGLs
(Bbls)

 

 

 

 

 

 

 

Developed

 

3,567,313

 

69,729

 

Undeveloped

 

3,994,248

 

61,389

 

Total proved reserves

 

7,561,561

 

131,118

 

 

 

Total acreage at December 31, 2013:

 

 

 

Total gross productive acres

 

1,339,773

 

Total net productive acres

 

1,192,127

 

Total gross undeveloped acres

 

2,277,568

 

Total net undeveloped acres

 

2,026,575

 

 

As of December 31, 2013, the Company did not have any reserves that have been classified as proved undeveloped reserves for more than five years.

 

Certain lease and acquisition agreements require the Company to drill a specific number of wells in 2014.  A drilling obligation exists to drill 2 wells in the Lower Huron formation and approximately 20,000 gross undeveloped acres could expire if this obligation is not met.  Within the Marcellus formation, the Company is required to drill three wells in 2014 and could incur the potential loss of leases for approximately 6,000 gross undeveloped acres if this obligation is not met.  The Company intends to satisfy such requirements either directly through its 2014 development program or indirectly by contracting with a third party to do so, including through an assignment of the lease, farmout or other arrangement.

 

As of December 31, 2013, leases associated with approximately 28,000 gross undeveloped acres expire in 2014 if they are not renewed.  This acreage is in addition to the acreage that may be lost if drilling obligations are not met.   The Company has an active lease renewal program in areas targeted for development.

 

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

 

 

 

For the Years Ended December 31,

 

 

 

2013

 

2012

 

2011

 

Exploratory wells:

 

 

 

 

 

 

 

Productive

 

 

 

 

Dry

 

 

 

 

Development wells:

 

 

 

 

 

 

 

Productive

 

223.2

 

128.5

 

211.2

 

Dry

 

1.0

 

1.0

 

2.0

 

 

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Table of Contents

 

Selected data by state (as of December 31, 2013 unless otherwise noted):

 

 

 

 

Kentucky

 

West
Virginia

 

Virginia

 

Pennsylvania

 

Ohio

 

Total

 

Natural gas and oil production (MMcfe) – 2013

 

52,208

 

95,843

 

22,056

 

196,250

 

755

 

367,112

 

Natural gas and oil production (MMcfe) – 2012

 

59,891

 

81,534

 

23,438

 

96,100

 

 

260,963

 

Natural gas and oil production (MMcfe) – 2011

 

61,402

 

53,742

 

25,581

 

58,096

 

 

198,821

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average net revenue interest (%)

 

95.5%

 

88.0%

 

49.9%

 

82.4%

 

72.7%

 

82.5%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total gross productive wells

 

5,556

 

4,895

 

3,258

 

915

 

3

 

14,627

 

Total net productive wells

 

5,306

 

4,660

 

1,955

 

903

 

3

 

12,827

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total gross productive acreage

 

548,560

 

428,572

 

274,480

 

87,288

 

873

 

1,339,773

 

Total gross undeveloped acreage

 

924,650

 

799,409

 

246,228

 

287,998

 

19,283

 

2,277,568

 

Total gross acreage

 

1,473,210

 

1,227,981

 

520,708

 

375,286

 

20,156

 

3,617,341

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total net productive acreage

 

488,104

 

381,348

 

244,230

 

77,668

 

777

 

1,192,127

 

Total net undeveloped acreage

 

907,972

 

711,198

 

108,589

 

280,466

 

18,350

 

2,026,575

 

Total net acreage

 

1,396,076

 

1,092,546

 

352,819

 

358,134

 

19,127

 

3,218,702

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Amounts in Bcfe)

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed producing reserves

 

1,248

 

1,030

 

289

 

1,209

 

3

 

3,779

 

Proved developed non-producing reserves

 

8

 

83

 

 

116

 

 

207

 

Proved undeveloped reserves

 

198

 

1,650

 

 

2,513

 

1

 

4,362

 

Proved developed and undeveloped reserves

 

1,454

 

2,763

 

289

 

3,838

 

4

 

8,348

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross proved undeveloped drilling locations

 

131

 

293

 

 

385

 

1

 

810

 

Net proved undeveloped drilling locations

 

131

 

293

 

 

383

 

1

 

808

 

 

The Company sells natural gas primarily within the Appalachian Basin under a variety of contractual agreements, some of which specify the delivery of fixed and determinable quantities.  The Company expects to fulfill these delivery commitments with existing proved developed and proved undeveloped reserves.  As of December 31, 2013, the Company’s delivery commitments through 2018 were as follows:

 

For the Year Ended
December 31,

 

Natural Gas (Bcf)

 

2014

 

281

 

 

2015

 

150

 

 

2016

 

98

 

 

2017

 

74

 

 

2018

 

74

 

 

 

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Capital expenditures at EQT Production totaled $1,423 million during 2013, including $186 million for the acquisition of undeveloped property and Marcellus wells. The Company invested approximately $885 million during 2013 converting undeveloped reserves to developed reserves and approximately $352 million on wells still in progress at year end.  During the year, the Company converted 653 Bcfe of proved undeveloped reserves to proved developed reserves.  The Company had additions to proved developed reserves of 902 Bcfe, the majority of which were from wells spud that had not previously been classified as proved or were related to the inclusion of NGL reserves. New proved undeveloped reserves of 2,158 Bcfe were added during 2013. These reserve extensions and discoveries were mainly due to decreased lateral spacing in one of the Company’s locations in Greene County, Pennsylvania, additional proved locations in the Company’s Pennsylvania and West Virginia Marcellus play and the addition of Huron proved undeveloped reserves in Kentucky. This increase was partially offset by negative revisions of 349 Bcfe, which was primarily due to the removal of 58 undeveloped locations and their associated reserves.  While the Company still plans to develop these reserves, projected development has been delayed beyond 5 years of their booking date. As of December 31, 2013, the Company’s proved undeveloped reserves totaled 4.4 Tcfe, 95% of which is associated with the development of the Marcellus play.  All proved undeveloped drilling locations are expected to be drilled within five years.

 

The Company’s 2013 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 2,047 Bcfe exceeded the 2013 production of 367 Bcfe.

 

Wells located in Pennsylvania are primarily in Marcellus formations with depths ranging from 5,000 feet to 8,000 feet. Wells located in West Virginia are primarily in Marcellus and Huron formations with depths ranging from 2,500 feet to 6,500 feet.  Wells located in Kentucky are primarily in Huron formations with depths ranging from 2,500 feet to 6,000 feet. Wells located in Virginia are primarily in CBM formations with depths ranging from 2,000 feet to 3,000 feet.  Wells located in Ohio are in the Utica Shale formation with depths ranging from 6,500 feet to 7,000 feet.

 

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

 

EQT Midstream: EQT Midstream owns or operates approximately 9,450 miles of gathering lines and 218 compressor units with approximately 250,000 horsepower of installed capacity, as well as other general property and equipment.

 

 

 

Kentucky

 

West
Virginia

 

Virginia

 

Pennsylvania

 

Total

 

Approximate miles of gathering lines

 

3,550

 

4,100

 

1,600

 

200

 

9,450

 

 

Substantially all of the gathering operation’s 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.

 

EQT Midstream also operates a FERC-regulated transmission and storage system.  These operations consist of an approximately 900 mile FERC-regulated interstate pipeline system that connects to seven interstate pipelines and multiple distribution companies.  The system is supported by eighteen associated natural gas storage reservoirs with approximately 660 MMcf per day of peak delivery capability and 47 Bcf of working gas capacity.  The transmission and storage system stretches throughout north central West Virginia and southwestern Pennsylvania.

 

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

 

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

 

See “Capital Resources and Liquidity” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a discussion of capital expenditures.

 

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Item 3.  Legal Proceedings

 

In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company and its subsidiaries.  While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings.  The Company accrues legal or other direct costs related to loss contingencies when actually incurred.  The Company has established reserves it believes to be appropriate for pending matters 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.

 

The Company has received a number of Notices of Violation (NOVs) from environmental agencies in some of the states in which we operate alleging various violations of oil and gas, air, water and waste regulations.  The Company has responded to these NOVs and has generally corrected or remediated the areas in question.  The Company disputes a number of the alleged NOVs and cannot predict with certainty whether any or all of these NOVs will result in penalties.  If penalties are imposed, an individual penalty or the aggregate of these penalties could result in monetary sanctions in excess of $100,000.

 

Item 4.  Mine Safety and Health Administration Data

 

Not Applicable.

 

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Executive Officers of the Registrant (as of February 20, 2014)

 

Name and Age

 

Current Title (Year Initially
Elected an Executive Officer)

 

Business Experience

 

 

 

 

 

Theresa Z. Bone (50)

 

Vice President, Finance and Chief Accounting Officer (2007)

 

Elected to present position October 2013; Vice President and Corporate Controller from July 2007 to October 2013. Ms. Bone is also Vice President, Finance and Chief Accounting Officer of EQT Midstream Services, LLC, the general partner of the Partnership, the Company’s publicly-traded master limited partnership, since October 2013. Ms. Bone was Vice President and Principal Accounting Officer of EQT Midstream Services, LLC from January 2012 to October 2013.

 

 

 

 

 

Philip P. Conti (54)

 

Senior Vice President and Chief Financial Officer (2000)

 

Elected to present position February 2007. Mr. Conti is also Senior Vice President, Chief Financial Officer and a Director of EQT Midstream Services, LLC, the general partner of the Partnership, since January 2012.

 

 

 

 

 

Randall L. Crawford (51)

 

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

 

Elected to present position December 2013; Senior Vice President and President, Midstream, Distribution and Commercial from April 2010 to December 2013; Senior Vice President and President, Midstream and Distribution from January 2008 to April 2010. Mr. Crawford is also Executive Vice President, Chief Operating Officer and a Director of EQT Midstream Services, LLC, the general partner of the Partnership, since December 2013. Mr. Crawford was Executive Vice President and a Director of EQT Midstream Services, LLC from January 2012 through December 2013.

 

 

 

 

 

Lewis B. Gardner (56)

 

General Counsel and Vice President, External Affairs (2008)

 

Elected to present position March 2008; Managing Director, External Affairs and Labor Relations from January 2008 to March 2008. Mr. Gardner is also a Director of EQT Midstream Services, LLC, the general partner of the Partnership, since January 2012.

 

 

 

 

 

Charlene Petrelli (53)

 

Vice President and Chief Human Resources Officer (2003)

 

Elected to present position February 2007.

 

 

 

 

 

David L. Porges (56)

 

Chairman, President and Chief Executive Officer (1998)

 

Elected to present position May 2011; President, Chief Executive Officer and Director from April 2010 to May 2011; President, Chief Operating Officer and Director from February 2007 to April 2010. Mr. Porges is also Chairman, President and Chief Executive Officer of EQT Midstream Services, LLC, the general partner of the Partnership, since January 2012.

 

 

 

 

 

Steven T. Schlotterbeck (48)

 

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

 

Elected to present position December 2013; Senior Vice President and President, Exploration and Production from April 2010 to December 2013; Vice President and President, Production from January 2008 to April 2010.

 

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

 

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Table of Contents

 

PART II

 

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

 

The Company’s common stock is listed on the New York Stock Exchange.  The high and low sales prices reflected in the New York Stock Exchange Composite Transactions and the dividends declared and paid per share, for 2013 and 2012 are summarized as follows (in U.S. dollars per share):

 

 

 

2013

 

2012

 

 

 

High

 

Low

 

Dividend

 

High

 

Low

 

Dividend

 

1st Quarter

 

 $

68.44

 

 $

56.84

 

 $

0.03

 

 $

56.56

 

 $

46.04

 

 $

0.22

 

2nd Quarter

 

84.00

 

64.71

 

0.03

 

55.20

 

43.69

 

0.22

 

3rd Quarter

 

94.42

 

78.57

 

0.03

 

59.46

 

52.20

 

0.22

 

4th Quarter

 

91.59

 

80.72

 

0.03

 

62.74

 

56.45

 

0.22

 

 

As of January 31, 2014, there were 2,817 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 upon business conditions, such as the Company’s lines of business, results of operations and financial conditions, strategic direction and other factors.  During 2012, the Company paid a dividend at an annual rate of $0.88 per share.  In December 2012, concurrent with the announcement of entering into a definitive agreement to transfer Equitable Gas and Homeworks to PNG Companies, the Company announced a new annual dividend rate, effective January 2013, of $0.12 per share, which the Company believed better reflects the blend of the Company’s core businesses remaining after the closing of the Equitable Gas Transaction a dividend supporting midstream business and a capital-intensive, rapidly growing production business.  The Board of Directors has the discretion to change the annual dividend rate at any time for the reasons described above.

 

The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Securities Exchange Act of 1934, as amended, that have occurred in the three months ended December 31, 2013:

 

 

 

 

 

 

 

 

 

 

 

Period

 

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

 

Average
price
paid per
share (or
unit)

 

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

 

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

 

 

 

 

 

 

 

 

 

 

 

October 2013 (October  1 – October 31)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

November 2013 (November 1 – November 30)

 

1,301

 

$

85.11

 

 

 

 

 

 

 

 

 

 

 

 

 

December 2013 (December 1 – December 31)

 

7,456

 

$

85.84

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

8,757

 

$

85.73

 

 

 

 

(a)         Reflects shares withheld by the Company to pay taxes upon vesting of restricted stock.

 

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Stock Performance Graph

 

The following graph compares the most recent five-year cumulative total return attained by holders of the Company’s common stock with the cumulative total returns of the S&P 500 Index and two customized peer groups of 25 companies.  The individual companies of the prior customized peer group (the “Old Self-Constructed Peer Group”) and the new customized peer group (the “New Self-Constructed Peer Group”) are listed below in footnotes (a) and (b), respectively.  An investment of $100 (with reinvestment of all dividends) is assumed to have been made at the close of business on December 31, 2008 in the Company’s common stock, in the S&P 500 Index and in each customized peer group.  Relative performance is tracked through December 31, 2013.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

12/08

 

12/09

 

12/10

 

12/11

 

12/12

 

12/13

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EQT Corporation

 

100.00

 

133.93

 

139.76

 

173.54

 

189.90

 

289.52

 

S&P 500

 

100.00

 

126.46

 

145.51

 

148.59

 

172.37

 

228.19

 

Old Self-Constructed Peer Group (a)

 

100.00

 

154.37

 

168.84

 

177.81

 

183.02

 

249.07

 

New Self-Constructed Peer Group (b)

 

100.00

 

164.57

 

190.38

 

195.44

 

199.73

 

277.94

 

 

(a)         The Old Self-Constructed Peer Group, first used in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, includes 25 companies, which are: Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, Cimarex Energy Co., CONSOL Energy Inc., Energen Corporation, EOG Resources, Inc., EXCO Resources, Inc., MarkWest Energy Partners, L.P., MDU Resources Group, Inc., National Fuel Gas Company, NSTAR, ONEOK, Inc., Penn Virginia Corporation, Pioneer Natural Resources Company, Plains Exploration & Production Company, Questar Corporation, Quicksilver Resources Inc., Range Resources Corporation, Sempra Energy, SM Energy Company, Southwestern Energy Company, Spectra Energy Corp, Ultra Petroleum Corp., Whiting Petroleum Corporation and The Williams Companies, Inc.  NSTAR was acquired during 2012 and is included in the calculation from December 31, 2008 through December 31, 2011, at which time it was removed from the peer group calculation.  Plains Exploration & Production Company was acquired during 2013 and is included in the calculation from December 31, 2008 through December 31, 2012, at which time it was removed from the peer group calculation.

 

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(b)         The New Self-Constructed Peer Group includes 25 companies, which are: Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, Cimarex Energy Co., Concho Resources, Inc., CONSOL Energy Inc., Continental Resources, Inc., Energen Corporation, EOG Resources, Inc., EXCO Resources, Inc., MarkWest Energy Partners, L.P., National Fuel Gas Company, Newfield Exploration Company, Noble Energy, Inc., ONEOK, Inc., Pioneer Natural Resources Company, QEP Resources, Inc., Questar Corporation, Quicksilver Resources Inc., Range Resources Corporation, SM Energy Company, Southwestern Energy Company, Spectra Energy Corp, Ultra Petroleum Corp., Whiting Petroleum Corporation and The Williams Companies, Inc.  QEP Resources, Inc. completed its IPO in 2010 and is included in the calculation from July 1, 2010, the date when its common stock began trading on the New York Stock Exchange, through December 31, 2013.

 

The Company’s management selected the New Self-Constructed Peer Group because it believes these companies are better aligned with the Company’s production and midstream businesses after the transfer of Equitable Gas to PNG Companies in December 2013.  The New Self-Constructed Peer Group is also the same peer group used for the Company’s 2014 Executive Performance Incentive Program, which utilizes three-year total shareholder return against the peer group as one performance metric.

 

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

 

Item 6.   Selected Financial Data

 

 

 

As of and for the Years Ended December 31,

 

 

 

2013

 

2012

 

2011

 

2010

 

2009

 

 

 

(Thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

 $

1,862,011

 

 $

1,377,222

 

 $

1,323,829

 

 $

1,038,240

 

 $

849,006

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts attributable to EQT Corporation:

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

 $

298,729

 

 $

135,902

 

 $

419,582

 

 $

164,761

 

 $

81,153

 

Net income

 

 $

390,572

 

 $

183,395

 

 $

479,769

 

 $

227,700

 

 $

156,929

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings per share of common stock attributable to EQT Corporation:

 

 

 

 

 

 

 

Basic:

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

 $

1.98

 

 $

0.91

 

 $

2.81

 

 $

1.14

 

 $

0.62

 

Net income

 

 $

2.59

 

 $

1.23

 

 $

3.21

 

 $

1.58

 

 $

1.20

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted:

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

 $

1.97

 

 $

0.90

 

 $

2.79

 

 $

1.14

 

 $

0.62

 

Net income

 

 $

2.57

 

 $

1.22

 

 $

3.19

 

 $

1.57

 

 $

1.19

 

Total assets

 

 $

9,792,053

 

 $

8,849,862

 

 $

8,772,719

 

 $

7,098,438

 

 $

5,957,257

 

Long-term debt

 

 $

2,501,516

 

 $

2,526,173

 

 $

2,746,942

 

 $

1,949,200

 

 $

1,949,200

 

Cash dividends declared per share of common stock

 

 $

0.12

 

 $

0.88

 

 $

0.88

 

 $

0.88

 

 $

0.88

 

 

Equitable Gas and Homeworks comprised substantially all of the Company’s previously reported Distribution segment.  The financial information of Equitable Gas and Homeworks is reflected as discontinued operations in this Annual Report on Form 10-K. All prior periods presented in this Annual Report have been recast to reflect the presentation of discontinued operations. See Item 1A, “Risk Factors”, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 2, 7 and 8 to the Consolidated Financial Statements for a discussion of matters that affect the comparability of the selected financial data as well as uncertainties that might affect the Company’s future financial condition.

 

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

 

Consolidated Results of Continuing Operations

 

2013 EQT highlights included:

 

·                  Annual production sales volumes of 378.2 Bcfe, 43.0% higher than 2012

·                  Marcellus sales volumes of 275.0 Bcfe, 81.6% higher than 2012

·                  Gathered volumes of 466.4 TBtu, 39.1% higher than 2012

·                  Increased proved reserves by 39% to 8.3 Tcfe

·                  Completed an underwritten public offering of common units representing limited partner interests in the Partnership

·                  Completed the Equitable Gas Transaction

 

Income from continuing operations attributable to EQT Corporation for 2013 was $298.7 million, $1.97 per diluted share, compared with $135.9 million, $0.90 per diluted share, in 2012. The $162.8 million increase in income from continuing operations attributable to EQT Corporation between periods was primarily attributable to a 43% increase in natural gas volumes sold, increases in contracted transmission capacity and throughput and gathered volumes, the disposal of certain energy marketing contracts by EQT Energy in December 2013 and lower interest expense. These factors were partially offset by higher depreciation, depletion and amortization (DD&A) expense, higher income tax expense, higher selling, general and administrative (SG&A) expense and higher net income attributable to noncontrolling interests of the Partnership.

 

Operating income was $654.6 million in 2013 compared to $389.6 million in 2012, an increase of $265.0 million. The increase in operating income was attributable to a 43% increase in natural gas volumes sold, increased transmission pipeline revenues and gathered volumes and a $19.6 million pre-tax gain from the disposal of customer contracts by EQT Energy, partially offset by higher DD&A expense and higher SG&A expense.

 

Production sales volumes increased primarily as a result of increased production from the 2012 and 2013 drilling programs in the Marcellus acreage.  This increase was partially offset by the normal production decline in the Company’s producing wells. The average effective sales price to EQT Corporation for production sales volumes was $4.13 per Mcfe in 2013 compared to $4.17 per Mcfe in 2012. The average NYMEX natural gas index price increased to $3.65 per Mcf in 2013 from $2.79 per Mcf for 2012. Hedging activities resulted in an increase in the effective sales price of $0.36 per Mcf in 2013 compared to $1.10 per Mcf in 2012. The $0.74 per Mcf decrease in the impact of hedging activities in 2013 was the result of the differential in the NYMEX natural gas index prices between periods and the lower average hedge prices in 2013. Gathering net operating revenues increased due to a 39% increase in gathered volumes, partially offset by a 17% decrease in the average gathering fee. The gathered volume increase was driven by higher volumes gathered for EQT Production in the Marcellus play. The decrease in the average gathering fee resulted from increased gathered volumes in the Marcellus play, as the Marcellus gathering rate is lower than the rate in other areas.

 

Operating expenses for 2013 were $1,227.0 million compared to $987.6 million in 2012, an increase of $239.4 million. This increase was primarily attributable to higher DD&A charges attributable to higher production volumes at a production depletion rate of $1.50 per Mcfe compared to $1.52 per Mcfe in 2012 and higher production-related and SG&A costs consistent with the growth in the production and midstream businesses.

 

On July 22, 2013, the Partnership completed an underwritten public offering of 12,650,000 common units representing limited partner interests in the Partnership. Following the offering and the closing of the Sunrise Merger, the Company holds a 44.6% equity interest in the Partnership, which includes 3,443,902 common units, 17,339,718 subordinated units and a 2% general partner interest. The Partnership received net proceeds of $529.4 million from the offering, after deducting the underwriters’ discount and offering expenses of $20.9 million. The Company continues to consolidate the results of the Partnership.  The Company records the noncontrolling interest of the public limited partners in its financial statements.

 

On December 17, 2013, the Company and its wholly-owned subsidiary, Holdco, completed the previously announced transactions contemplated by the Master Purchase Agreement, pursuant to which the Company and Holdco

 

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transferred 100% of their ownership interests in Equitable Gas and Homeworks to PNG Companies.  As consideration for the transaction, the Company received a cash payment of $740.6 million, which is subject to certain post-closing adjustments, select midstream assets, including the AVC facilities, with a preliminary estimated fair value of approximately $141.4 million and other contractual assets with a preliminary estimated fair value of $32.5 million.

 

Income from continuing operations attributable to EQT Corporation for 2012 was $135.9 million, $0.90 per diluted share, compared with $419.6 million, $2.79 per diluted share, in 2011. In 2011, the Company recorded $202.9 million of pre-tax gains on dispositions related to the sales of the Big Sandy Pipeline (Big Sandy) and Langley. The Company was negatively impacted in 2012 by lower realized sales prices for production sales volumes, higher DD&A expense and higher interest expense partially offset by increases in both production and gathered volumes and lower income tax expense.

 

Operating income was $389.6 million in 2012 compared to $761.2 million in 2011, a decrease of $371.6 million. In addition to the $202.9 million pre-tax gain in 2011 on the dispositions of Big Sandy and Langley, the decrease from 2011 was a result of approximately 24% lower realized sales prices for production sales volumes, a 22% higher production depletion rate and higher other operating expenses, partially offset by a 33% increase in production volumes, a 30% increase in gathering volumes and higher transmission revenues.

 

Production sales volumes increased primarily as a result of increased production from the 2011 and 2012 drilling programs in the Marcellus acreage.  This increase was partially offset by the normal production decline in the Company’s producing wells. The average effective sales price to EQT Corporation including the effect of the Company’s hedging program was $4.17 per Mcfe in 2012 compared to $5.23 per Mcfe in 2011.  Hedging activities resulted in an increase in the average natural gas sales price of $1.10 per Mcf in 2012 and $0.51 per Mcf in 2011.  Gathering net operating revenues increased due to a 30% increase in gathered volumes, partially offset by a 7% decrease in the average gathering fee.  The gathered volume increase was driven by higher volumes gathered for EQT Production in the Marcellus play.

 

Operating expenses for 2012 were $987.6 million compared to $765.6 million in 2011, an increase of $222.0 million.  This increase was primarily attributable to higher DD&A charges from higher production volumes at a production depletion rate of $1.52 per Mcfe compared to $1.25 per Mcfe in 2011 and higher production-related and SG&A costs consistent with the growth in the production and midstream businesses.

 

On July 2, 2012, the Partnership completed its IPO of 14,375,000 common units representing limited partner interests in the Partnership, which represented 40.6% of the Partnership’s outstanding equity. The Company retained a 59.4% equity interest in the Partnership, including 2,964,718 common units, 17,339,718 subordinated units and a 2% general partner interest.

 

See “Other Income Statement Items” for a discussion of other income, interest expense, income taxes, income from discontinued operations and net income attributable to noncontrolling interests, and “Investing Activities” in “Capital Resources and Liquidity” for a discussion of capital expenditures.

 

Consolidated Operational Data

 

Revenues earned by the Company at the wellhead from the sale of natural gas are split between EQT Production and EQT Midstream. The split is reflected in the calculation of EQT Production’s average effective sales price.  The following operational information presents detailed gross liquid and natural gas operational information as well as midstream deductions to assist in the understanding of the Company’s consolidated operations.

 

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Table of Contents

 

 

 

Years Ended December 31,

in thousands (unless noted)

 

2013

 

 

2012

 

 

2011

 

LIQUIDS

 

 

 

 

 

 

 

 

 

NGLs:

 

 

 

 

 

 

 

 

 

Sales Volume (MMcfe) (a)

 

27,860

 

 

18,981

 

 

16,541

 

Sales Volume (Mbbls)

 

4,643

 

 

3,163

 

 

2,757

 

Gross Price ($/Bbl)

 

 

  $

45.58

 

 

  $

49.29

 

 

  $

67.41

 

Gross NGL Revenue

 

  $

211,626

 

 

  $

155,926

 

 

  $

185,845

 

BTU Premium (Ethane sold as natural gas):

 

 

 

 

 

 

 

 

 

Sales Volume (MMBtu)

 

29,185

 

 

22,494

 

 

16,124

 

Price ($/MMBtu)

 

 

  $

3.66

 

 

  $

2.83

 

 

  $

4.04

 

BTU Premium Revenue

 

  $

106,724

 

 

  $

63,668

 

 

  $

65,168

 

Oil:

 

 

 

 

 

 

 

 

 

Sales Volume (MMcfe) (a)

 

1,620

 

 

1,587

 

 

1,248

 

Sales Volume (Mbbls)

 

270

 

 

264

 

 

208

 

Net Price ($/Bbl)

 

 

  $

85.82

 

 

  $

83.95

 

 

  $

81.58

 

Net Oil Revenue

 

  $

23,171

 

 

  $

22,161

 

 

  $

16,968

 

 

 

 

 

 

 

 

 

 

 

Total Liquids Revenue

 

  $

341,521

 

 

  $

241,755

 

 

  $

267,981

 

 

 

 

 

 

 

 

 

 

 

GAS

 

 

 

 

 

 

 

 

 

Sales Volume (MMcf)

 

348,693

 

 

243,886

 

 

181,566

 

NYMEX Price ($/Mcf) (b)

 

 

  $

3.66

 

 

  $

2.83

 

 

  $

4.04

 

Gas Revenue

 

  $

1,277,847

 

 

  $

690,293

 

 

  $

733,814

 

Basis

 

 

(51,274

)

 

(960

)

 

24,047

 

Gross Gas Revenue (unhedged)

 

  $

1,226,573

 

 

  $

689,333

 

 

  $

757,861

 

 

 

 

 

 

 

 

 

 

 

Total Gross Gas & Liquids Revenue (unhedged)

 

  $

1,568,094

 

 

  $

931,088

 

 

  $

1,025,842

 

Hedge impact (c)

 

 

137,634

 

 

290,557

 

 

101,047

 

Total Gross Gas & Liquids Revenue

 

  $

1,705,728

 

 

  $

1,221,645

 

 

  $

1,126,889

 

Total Sales Volume (MMcfe)

 

 

378,173

 

 

264,454

 

 

199,355

 

Average hedge adjusted price ($/Mcfe)

 

  $

4.51

 

 

  $

4.62

 

 

  $

5.65

 

 

 

 

 

 

 

 

 

 

 

Midstream Revenue Deductions ($ / Mcfe)

 

 

 

 

 

 

 

 

 

Gathering to EQT Midstream

 

  $

(0.82

)

 

  $

(1.00

)

 

  $

(1.08

)

Transmission to EQT Midstream

 

(0.23

)

 

(0.19

)

 

(0.21

)

Third-party gathering and transmission (d)

 

(0.28

)

 

(0.35

)

 

(0.30

)

Third-party processing

 

(0.10

)

 

(0.10

)

 

(0.12

)

Total midstream revenue deductions

 

(1.43

)

 

(1.64

)

 

(1.71

)

Average effective sales price to EQT Production

 

  $

3.08

 

 

  $

2.98

 

 

  $

3.94

 

 

 

 

 

 

 

 

 

 

 

EQT Revenue ($ / Mcfe)

 

 

 

 

 

 

 

 

 

Revenues to EQT Midstream

 

  $

1.05

 

 

  $

1.19

 

 

  $

1.29

 

Revenues to EQT Production

 

3.08

 

 

2.98

 

 

3.94

 

Average effective sales price to EQT Corporation

 

  $

4.13

 

 

  $

4.17

 

 

  $

5.23

 

 

(a)           NGLs and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods. Information for periods prior to 2013 has been recast to reflect this conversion rate.

 

(b)          The Company’s volume weighted NYMEX natural gas price (actual average NYMEX natural gas price ($/Mcf) was $3.65, $2.79 and $4.04 for the years ended December 31, 2013, 2012 and 2011, respectively).

 

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(c)           Includes gains or losses related to the sale of fixed price natural gas.  The hedge impact also included a loss for hedging ineffectiveness of $21.5 million, $0.06 per Mcfe, for the year ended December 31, 2013. Hedging ineffectiveness did not impact the effective sales price for the years ended December 31, 2012 or 2011.

 

(d)          Due to the sale of unused capacity on the El Paso 300 line that was not under long-term resale agreements at prices below the capacity charge, third-party gathering and transmission rates increased by $0.05 per Mcfe and $0.04 per Mcfe for the years ended December 31, 2013 and 2012, respectively.  In 2011, the unused capacity on the El Paso 300 line not under long-term resale agreements was sold at prices above the capacity charge, decreasing third-party gathering and transmission rates by $0.03 per Mcfe.

 

Business Segment Results of Operations

 

Business segment operating results from continuing operations 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.  Other income, interest 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 totaling $45.4 million, $35.6 million and $42.5 million were not allocated to the operating segments for the years ended December 31, 2013, 2012 and 2011, respectively. Unallocated expenses consist primarily of incentive compensation, administrative costs and corporate overhead charges previously allocated to the Distribution segment that were reclassified to Headquarters as part of the recast of this Annual Report on Form 10-K to reflect the discontinued operations presentation.

 

The Company has reported the components of each segment’s operating income from continuing operations 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 provides useful information to management and investors regarding the financial condition, operations and trends of each of EQT’s business segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations of interest, income taxes and other income.  In addition, management uses these measures for budget planning purposes. The Company’s management reviews and reports the EQT Production segment results for operating revenues and purchased gas costs with transportation costs reflected as a deduction from operating revenues as management believes this presentation provides a more useful view of net effective sales price and is consistent with industry practices. Third-party transportation costs are reported as a component of purchased gas costs in the consolidated results. The Company has reconciled each segment’s operating income to the Company’s consolidated operating income and net income in Note 4 to the Consolidated Financial Statements.

 

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EQT Production

 

Results of Operations

 

 

 

Years Ended December 31,

 

 

 

2013

 

2012

 

%
change
2013 -
2012

 

2011

 

%
change
2012 -
2011

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATIONAL DATA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales volume detail (MMcfe):

 

 

 

 

 

 

 

 

 

 

 

Horizontal Marcellus Play (a)

 

275,029

 

151,430

 

81.6

 

81,908

 

84.9

 

Horizontal Huron Play

 

35,255

 

41,985

 

(16.0)

 

44,737

 

(6.2)

 

CBM Play

 

12,429

 

13,084

 

(5.0)

 

13,682

 

(4.4)

 

Other

 

55,460

 

57,955

 

(4.3)

 

59,028

 

(1.8)

 

Total production sales volumes (b)

 

378,173

 

264,454

 

43.0

 

199,355

 

32.7

 

 

 

 

 

 

 

 

 

 

 

 

 

Average daily sales volumes (MMcfe/d)

 

1,036

 

723

 

43.3

 

546

 

32.4

 

 

 

 

 

 

 

 

 

 

 

 

 

Average effective sales price to EQT Production ($/Mcfe)

 

  $

3.08

 

  $

2.98

 

3.4

 

  $

3.94

 

(24.4)

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

  $

0.15

 

  $

0.17

 

(11.8)

 

  $

0.20

 

(15.0)

 

Production taxes ($/Mcfe) (c)

 

  $

0.13

 

  $

0.16

 

(18.8)

 

  $

0.20

 

(20.0)

 

Production depletion ($/Mcfe)

 

  $

1.50

 

  $

1.52

 

(1.3)

 

  $

1.25

 

21.6

 

 

 

 

 

 

 

 

 

 

 

 

 

DD&A (thousands):

 

 

 

 

 

 

 

 

 

 

 

Production depletion

 

  $

568,990

 

  $

401,456

 

41.7

 

  $

248,286

 

61.7

 

Other DD&A

 

9,651

 

8,172

 

18.1

 

8,858

 

(7.7)

 

Total DD&A (thousands)

 

  $

578,641

 

  $

409,628

 

41.3

 

  $

257,144

 

59.3

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures (thousands) (d)

 

  $

1,423,185

 

  $

991,775

 

43.5

 

  $

1,087,840

 

(8.8)

 

 

 

 

 

 

 

 

 

 

 

 

 

FINANCIAL DATA (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total net operating revenues

 

  $

1,168,657

 

  $

793,773

 

47.2

 

  $

791,285

 

0.3

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

LOE, excluding production taxes

 

57,110

 

46,212

 

23.6

 

40,369

 

14.5

 

Production taxes (c)

 

50,981

 

49,943

 

2.1

 

40,542

 

23.2

 

Exploration expense

 

18,483

 

10,370

 

78.2

 

4,932

 

110.3

 

SG&A

 

92,197

 

89,707

 

2.8

 

61,200

 

46.6

 

DD&A

 

578,641

 

409,628

 

41.3

 

257,144

 

59.3

 

Total operating expenses

 

797,412

 

605,860

 

31.6

 

404,187

 

49.9

 

Operating income

 

  $

371,245

 

  $

187,913

 

97.6

 

  $

387,098

 

(51.5)

 

 

(a)         Includes Upper Devonian wells.

 

(b)         NGLs and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods. Information for periods prior to 2013 has been recast to reflect this conversion rate.

 

(c)          Production taxes include severance and production-related ad valorem and other property taxes and the Pennsylvania impact fee.  The Pennsylvania impact fee for the year ended December 31, 2012 totaled

 

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$15.3 million, of which $6.7 million represented the retroactive fee for pre-2012 Marcellus wells.  The production taxes unit rate for the year ended December 31, 2012 excludes the impact of the accrual for pre-2012 Marcellus wells.

 

(d)         Includes $114.2 million of capital expenditures for the purchase of acreage and Marcellus wells from Chesapeake Energy Corporation and its partners (Chesapeake) during the year ended December 31, 2013 and $92.6 million of liabilities assumed in exchange for producing properties as part of the Appalachian NPI, LLC (ANPI) transaction described in Note 8 to the Consolidated Financial Statements during the year ended December 31, 2011.

 

Year Ended December 31, 2013 vs. December 31, 2012

 

EQT Production’s operating income totaled $371.2 million for 2013 compared to $187.9 million for 2012.  The $183.3 million increase in operating income was primarily due to increased sales of produced natural gas and NGLs and a higher average effective sales price partially offset by an increase in operating expenses.

 

Total operating revenues were $1,168.7 million for 2013 compared to $793.8 million for 2012. The $374.9 million increase in operating revenues was primarily due to a 43% increase in production sales volumes and a 3% increase in the average effective sales price to EQT Production.  The increase in production sales volumes was the result of increased production from the 2011 and 2012 drilling programs, primarily in the Marcellus play. This increase was partially offset by the normal production decline in the Company’s producing wells. The $0.10 per Mcfe increase in the average effective sales price to EQT Production was the net result of a 31% increase in the average NYMEX natural gas price, an increase in margins from fixed priced sales and lower midstream charges and gathering rates substantially offset by a smaller hedge gain and lower NGL and basis prices compared to 2012.  The average effective sales price was impacted unfavorably in 2013 by $0.06 per Mcfe as a result of a loss on ineffectiveness of financial hedges of $21.5 million which was caused by the change in basis. The average effective sales price was impacted unfavorably in 2012 by $0.03 per Mcfe as a result of an $8.2 million adjustment to recognize financial instrument put premiums which should have been recorded ratably over 2010 and 2011.

 

Operating expenses totaled $797.4 million for 2013 compared to $605.9 million for 2012. The increase in operating expenses was the result of increases in DD&A, LOE, exploration expenses, SG&A and production taxes. Depletion expense increased as a result of higher production sales volumes in 2013 partially offset by a slightly lower overall depletion rate. The increase in LOE was mainly a result of increased Marcellus activity in 2013, including a $6.5 million increase in salt water disposal expenses and a $3.1 million increase in labor expenses in that region. The increase in exploration expense was due to increased impairments of unproved lease acreage of $8.7 million resulting from lease expirations during 2013, slightly offset by a reduction in geophysical activity compared to the prior year. SG&A expense increased in 2013 primarily as a result of higher personnel costs of $4.6 million, including incentive compensation expenses, and higher environmental reserves of $1.9 million partially offset by a decrease in franchise taxes of $2.2 million.

 

Production taxes increased primarily due to an increase in severance and property taxes related to higher market sales prices and higher production sales volumes. Severance and property taxes were offset by a $3.1 million decrease in the Pennsylvania impact fee. During 2013, the Pennsylvania impact fee was $12.2 million compared to $15.3 million in 2012, of which $6.7 million represented a retroactive fee for pre-2012 Marcellus wells.

 

Year Ended December 31, 2012 vs. December 31, 2011

 

EQT Production’s operating income totaled $187.9 million for 2012 compared to $387.1 million for 2011.  The $199.2 million decrease in operating income was primarily due to a lower average effective sales price and an increase in operating expenses partially offset by increased sales of produced natural gas and NGLs.

 

Total operating revenues were $793.8 million for 2012 compared to $791.3 million for 2011. The $2.5 million increase in operating revenues was primarily due to a 33% increase in production sales volumes which offset a 24% decrease in the average effective sales price to EQT Production.  The increase in production sales volumes was primarily the result of increased production from the 2011 and 2012 drilling programs in the Marcellus play, as

 

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well as the acquisition of producing properties associated with the ANPI transaction in May 2011 which added 2.6 Bcfe of sales volumes in 2012. This increase was partially offset by the normal production decline in the Company’s producing wells.  The $0.96 per Mcfe decrease in the average effective sales price to EQT Production was primarily due to a 31% decrease in the average NYMEX gas price as well as lower basis and NGL prices, partially offset by higher hedging gains and lower affiliated gathering rates compared to 2011.  The average effective sales price was also impacted unfavorably in 2012 by $0.03 per Mcfe as a result of an $8.2 million adjustment to recognize financial instrument put premiums which should have been recorded ratably over 2010 and 2011 and by $0.04 per Mcfe for the cost of transmission capacity on the El Paso 300 line, including long-term resale agreements.  Management evaluated the size and nature of the put premium adjustment and concluded that the adjustment was not material to the financial statements.

 

Operating expenses totaled $605.9 million for 2012 compared to $404.2 million for 2011. The increase in operating expenses was the result of increases in DD&A, SG&A, production taxes, LOE and exploration expense. Depletion expense increased as a result of a higher overall depletion rate and higher produced volumes in 2012.  The increase in the depletion rate was primarily due to an increase in costs to complete wells, higher capitalized overhead and interest costs and the removal of proved reserves due to lower natural gas prices and the suspension of drilling activity in the Huron play.  The increase in SG&A was primarily a result of higher corporate overhead and commercial services allocations of $22.0 million, increased labor and relocation expenses of $4.0 million associated with increased Marcellus drilling and an increase in franchise taxes of $1.9 million.

 

In February 2012, the Commonwealth of Pennsylvania passed legislation imposing a natural gas impact fee.  The legislation, which covers a significant portion of EQT’s Marcellus Shale acreage, imposes an annual fee for a period of fifteen years on each well spud in Pennsylvania.  The impact fee adjusts annually based on three factors: age of the well, changes in the Consumer Price Index and the average monthly NYMEX gas price.  Production taxes increased primarily due to the Pennsylvania impact fee in 2012 of $15.3 million, of which $6.7 million represents the retroactive fee for pre-2012 Marcellus wells, as well as an increase in property taxes partially offset by a decrease in severance taxes due to the decrease in average effective sales price in 2012.

 

The increase in LOE was mainly a result of increased Marcellus activity in 2012 primarily related to a $3.0 million increase in salt water disposal expenses and a $2.1 million increase in labor expenses, as well as the elimination of $2.3 million of third-party operating expense reimbursements, as part of the ANPI transaction. Exploration expense increased in 2012 primarily due to increased impairments of unproved lease acreage of $3.0 million and also an increase in geophysical activity in 2012 related to the Ohio Utica formation.

 

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EQT Midstream

 

Results of Operations

 

 

 

Years Ended December 31,

 

 

 

2013

 

2012

 

%
change
2013 -
2012

 

2011

 

%
change
2012 –
2011

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATIONAL DATA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathered volumes (BBtu)

 

466,405

 

335,407

 

39.1

 

258,179

 

29.9

 

Average gathering fee ($/MMBtu)

 

  $

0.75

 

  $

0.90

 

(16.7)

 

  $

0.97

 

(7.2)

 

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

 

  $

0.18

 

  $

0.24

 

(25.0)

 

  $

0.30

 

(20.0)

 

Transmission pipeline throughput (BBtu)

 

418,360

 

221,944

 

88.5

 

159,384

 

39.3

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating revenues (thousands):

 

 

 

 

 

 

 

 

 

 

 

Gathering

 

  $

351,410

 

  $

302,255

 

16.3

 

  $

249,607

 

21.1

 

Transmission

 

160,621

 

104,501

 

53.7

 

90,405

 

15.6

 

Storage, marketing and other

 

33,555

 

42,693

 

(21.4)

 

64,614

 

(33.9)

 

Total net operating revenues

 

  $

545,586

 

  $

449,449

 

21.4

 

  $

404,626

 

11.1

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures (thousands)

 

  $

369,399

 

  $

375,731

 

(1.7)

 

  $

242,886

 

54.7

 

 

 

 

 

 

 

 

 

 

 

 

 

FINANCIAL DATA (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

  $

614,042

 

  $

505,498

 

21.5

 

  $

525,345

 

(3.8)

 

Purchased gas costs

 

68,456

 

56,049

 

22.1

 

120,719

 

(53.6)

 

Total net operating revenues

 

545,586

 

449,449

 

21.4

 

404,626

 

11.1

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

Operating and maintenance

 

97,540

 

97,400

 

0.1

 

83,907

 

16.1

 

SG&A

 

63,850

 

49,943

 

27.8

 

49,901

 

0.1

 

DD&A

 

75,032

 

64,782

 

15.8

 

57,135

 

13.4

 

Total operating expenses

 

236,422

 

212,125

 

11.5

 

190,943

 

11.1

 

Gain on dispositions

 

19,618

 

 

100.0

 

202,928

 

(100.0)

 

Operating income

 

  $

328,782

 

  $

237,324

 

38.5

 

  $

416,611

 

(43.0)

 

 

(a)         Gathering and compression expense per unit for the year ended December 31, 2011 excludes $7.1 million of favorable adjustments for certain non-income tax reserves.

 

Year Ended December 31, 2013 vs. December 31, 2012

 

EQT Midstream’s operating income totaled $328.8 million for 2013 compared to $237.3 million for 2012. The increase in operating income was primarily the result of increased transmission and gathering net operating revenues and gains on dispositions, partly offset by increased operating expenses and a decrease in storage, marketing and other net operating revenues.

 

The $96.1 million increase in total net operating revenues was due to a $56.1 million increase in transmission net operating revenues and $49.2 million increase in gathering net operating revenues, partially offset by a decrease in storage, marketing and other net operating revenues.

 

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Transmission net operating revenues increased from the prior year primarily as a result of $44.0 million of additional firm capacity reservation revenues and usage charges, $10.1 million of fees associated with transported volumes in excess of firm capacity and increased pipeline safety revenues.

 

Gathering net operating revenues increased due to a 39% increase in gathered volumes, partly offset by a 17% decrease in the average gathering fee.  The gathered volume increase was driven by higher volumes gathered for EQT Production in the Marcellus play.  The average gathering fee decreased due to the mix of gathered volumes as Marcellus volumes increased while Huron and other volumes, which have a higher gathering fee, decreased.

 

Storage, marketing and other net operating revenues decreased from the prior year primarily as a result of lower realized margins and reduced activity due to lower price spreads. In addition, revenues on NGLs marketed for non-affiliated producers decreased by $2.8 million primarily as a result of lower liquids pricing partially offset by slightly higher liquids volumes.

 

On December 31, 2013, the Company sold certain energy marketing contracts to a third party for $20.0 million.  These contracts were natural gas sales agreements with approximately 1,000 end use customers with total volumes of approximately 12 Bcf in 2013.  In conjunction with this transaction, the Company recognized a pre-tax gain of $19.6 million in 2013, which is included in gains on dispositions in the Statements of Consolidated Income.

 

Total operating revenues increased $108.5 million primarily as a result of the increase in gathered volumes and increased transmission revenue, partly offset by the lower gathering rate. Total purchased gas costs increased $12.4 million primarily as a result of an increase in commodity prices.

 

Operating expenses totaled $236.4 million for 2013 compared to $212.1 million for 2012.  The increase in SG&A was primarily the result of increased personnel costs of $5.9 million including incentive compensation expenses, $2.2 million of increased overhead allocated from affiliates, a $2.1 million unfavorable change in bad debt expense primarily as a result of lower recoveries from the Lehman Brothers settlement in 2013 and $2.0 million of lower reserve reductions in 2013, primarily related to the expected recovery of a long-term, volume-based regulatory asset.  DD&A increased as a result of additional assets placed in-service.  Operating and maintenance (O&M) expenses were flat to the prior year as increases in personnel and other gathering and transmission business expenses in 2013 were offset by reduced compressor operating expenses.

 

Year Ended December 31, 2012 vs. December 31, 2011

 

EQT Midstream’s operating income totaled $237.3 million for 2012 compared to $416.6 million for 2011. The decrease in operating income was primarily the result of the $202.9 million pre-tax gain on the sales of Langley and Big Sandy in 2011 and increased operating expenses in 2012 partly offset by an increase in 2012 net operating revenues.

 

Total net operating revenues were $449.4 million for 2012 compared to $404.6 million for 2011.  The increase in total net operating revenues was due to a $52.6 million increase in gathering net operating revenues and a $14.1 million increase in transmission net operating revenues, partly offset by a $21.9 million decrease in storage, marketing and other net operating revenues.

 

Gathering net operating revenues increased due to a 30% increase in gathered volumes, partly offset by a 7% decrease in the average gathering fee.  The gathered volume increase was driven by higher volumes gathered for EQT Production in the Marcellus play.  The average gathering fee decreased due to the mix of gathered volumes as Marcellus volumes increased while Huron and other volumes, which have a higher gathering fee, decreased.

 

Transmission net operating revenues in 2012 increased from the prior year primarily as a result of $15.8 million of increased capacity reservation revenues resulting from the Sunrise Pipeline project and the Equitrans 2010 Marcellus expansion project and higher firm transportation activity from affiliated shippers due to increased Marcellus volumes.  These revenues were negatively impacted year over year by the absence of $16.0 million of revenues recorded on Big Sandy in the first half of 2011.

 

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Storage, marketing and other net operating revenues decreased from the prior year primarily as a result of unrealized losses on derivatives and inventory, lower margins and activity due to lower price spreads and volatility, and a $4.3 million decrease in net operating revenue from NGLs marketed for non-affiliated producers primarily as a result of lower liquids pricing.

 

Total operating revenues decreased $19.8 million primarily as a result of lower sales prices on decreased commercial activity and a lower gathering rate partly offset by an increase in gathered volumes and increased transmission revenue.  Total purchased gas costs decreased $64.7 million primarily as a result of lower commodity prices on decreased commercial activity.

 

Operating expenses totaled $212.1 million for 2012 compared to $190.9 million for 2011.  The increase in O&M was primarily the result of a $13.3 million decrease in 2011 of non-income taxes largely as a result of favorable property tax settlements recorded in 2011 combined with increases in 2012 in line with the growth of the business. In addition, personnel cost increases in 2012 were partly offset by the absence of $2.8 million in operating costs for Langley and Big Sandy in 2011.  SG&A was flat year over year as the EQT Midstream segment recovered approximately $2.9 million from the Lehman Brothers bankruptcy, reversed $2.5 million in reserves for the recovery of a long-term, volume-based regulatory asset and allocated $5.2 million more in expenses to affiliates, offsetting increases in personnel costs and $1.2 million of increased expenses related to the Partnership’s IPO and subsequent operation as a public company.  DD&A increased as a result of higher assets placed in service.

 

Other Income Statement Items

 

Other Income

 

 

 

Years Ended December 31,

 

 

 

2013

 

2012

 

2011

 

 

 

 (Thousands)

 

Other income

 

$

9,242

 

$

15,536

 

$

33,276

 

 

Other income includes equity in earnings of nonconsolidated investments, primarily the Company’s investments in Nora Gathering, LLC, of $7.6 million, $6.1 million and $7.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

 

Other income for the year ended December 31, 2013 also included $1.2 million of AFUDC compared to $6.8 million of AFUDC in 2012, a $5.6 million decrease as a result of the Sunrise Pipeline being placed into service during the third quarter of 2012. The Company also recognized a gain on the sale of leases of $0.4 million in 2013 compared to a gain on the sale of leases of $2.0 million in 2012.

 

Other income for the year ended December 31, 2012 included $6.8 million of AFUDC compared to $3.8 million in 2011, a $3.0 million increase as a result of further construction on the Equitrans Sunrise Pipeline project, which was placed into service during 2012. Other income for the year ended December 31, 2011 also included a $10.1 million pre-tax gain on the ANPI transaction and an $8.5 million gain on sales of available-for-sale securities.

 

Interest Expense

 

 

 

Years Ended December 31,

 

 

 

2013

 

2012

 

2011

 

 

 

 

 

(Thousands)

 

 

 

Interest expense

 

  $

142,688

 

  $

184,786

 

  $

136,328

 

 

Interest expense decreased $42.1 million in 2013 compared to 2012 as a result of a $23.3 million payment to settle a forward-starting interest rate swap recorded as expense in 2012 and the Company’s repayment of $200 million of 5.15% senior notes that matured in the fourth quarter of 2012 and $23.2 million of debentures that matured in 2013. This decrease was also attributable to higher capitalized interest of $22.9 million on increased Marcellus well development in 2013 compared to $15.6 million in 2012.

 

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Interest expense increased $48.5 million from 2011 to 2012 as a result of additional expense from the Company’s November 2011 issuance of $750 million 4.875% notes due in 2021 and the $23.3 million payment to settle a forward-starting interest rate swap in 2012. These increases were partially offset by higher capitalized interest on increased Marcellus well development and midstream pipeline construction in 2012.

 

During the third quarter of 2011, the Company entered into an interest rate hedge in anticipation of refinancing $200 million of long-term debt scheduled to mature in November 2012.  Given the Company’s strong liquidity position, the Company retired the debt using cash on hand and recognized a $23.3 million expense in the year ended December 31, 2012 to close the interest rate hedge.

 

Weighted average annual interest rates on the Company’s long-term debt were 6.4% for 2013 and 2012 and 6.8% for 2011.  The weighted average annual interest rate on the Company’s short-term debt was 1.7% and 1.8% for 2013 and 2011, respectively.  The Company had no short-term debt in 2012.

 

Income Taxes

 

 

 

Years Ended December 31,

 

 

 

 

2013

 

2012

 

2011

 

 

 

 

(Thousands)

 

 

Income taxes

 

  $

175,186

 

  $

71,461

 

  $

238,537

 

 

 

Income tax expense increased by $103.7 million from 2012 to 2013 as a result of higher pre-tax income and an increase in the Company’s effective income tax rate from 32.4% to 33.6%.  The increase in the rate from 2012 to 2013 was primarily due to an increase in pre-tax book income on state tax paying entities as well as a shift in the Company’s business to states with higher income tax rates partially offset by state tax benefits realized in 2013 related to the Sunrise Merger and the Equitable Gas Transaction.  The effective tax rate was also favorably impacted by the Partnership ownership structure whereby the Company consolidates the pre-tax income related to the noncontrolling public limited partners’ share of partnership earnings but does not record an income tax provision with respect to the portion of the Partnership’s earnings allocated to its noncontrolling public limited partners.  Both items were higher in 2013 than they were in the prior year.

 

Income tax expense decreased by $167.1 million from 2011 to 2012 as a result of lower pre-tax income and a decrease in the Company’s effective income tax rate from 36.2% to 32.4%.  The decrease in the rate from 2011 to 2012 was primarily due to a reduction in pre-tax book income on state tax paying entities.  The effective tax rate was also favorably impacted in 2012 by the Partnership ownership structure whereby the Company consolidates the pre-tax income related to the noncontrolling public limited partners’ share of partnership earnings but does not record an income tax provision with respect to the portion of the Partnership’s earnings allocated to its noncontrolling public limited partners. Other rate reconciling items had a larger percentage impact on the effective tax rate in 2012 than 2011 due to significantly higher pre-tax income in 2011.

 

The Company was in a cumulative federal taxable income position for 2013 primarily as a result of the taxable gains generated from the Sunrise Merger and the Equitable Gas Transaction.  The Company was in an overall federal tax net operating loss (NOL) position for 2012 and 2011.  In 2013, the Company began to utilize the NOLs it generated in previous years.  For federal income tax purposes, the Company deducts approximately 83% of drilling costs as intangible drilling costs (IDCs) in the year incurred.  IDCs, however, are sometimes limited for purposes of the alternative minimum tax (AMT) and can result in the Company paying AMT even when utilizing a regular tax NOL.  See Note 9 to the Consolidated Financial Statements for further discussion of the Company’s income taxes.

 

Income from Discontinued Operations, Net of Tax

 

 

 

Years Ended December 31,