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, 2014
[ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||
or
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) | 25-0464690 (IRS Employer Identification No.) |
625 Liberty Avenue Pittsburgh, Pennsylvania (Address of principal executive offices) | 15222 (Zip Code) |
Registrant’s telephone number, including area code: (412) 553-5700
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered |
Common Stock, no par value | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes X No ___
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ___ No X
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X No ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer X | Accelerated filer ___ |
Non-accelerated filer ___ | Smaller reporting company ___ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ___ No X
The aggregate market value of voting stock held by non-affiliates of the registrant as of June 30, 2014: $14.0 billion
The number of shares (in thousands) of common stock outstanding as of January 31, 2015: 151,602
DOCUMENTS INCORPORATED BY REFERENCE
The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held April 15, 2015) will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2014 and is incorporated by reference in Part III to the extent described therein.
TABLE OF CONTENTS
Glossary of Commonly Used Terms, Abbreviations and Measurements | ||
Cautionary Statements | ||
PART I | ||
Item 1 | Business | |
Item 1A | Risk Factors | |
Item 1B | Unresolved Staff Comments | |
Item 2 | Properties | |
Item 3 | Legal Proceedings | |
Item 4 | Mine Safety and Health Administration Data | |
Executive Officers of the Registrant | ||
PART II | ||
Item 5 | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | |
Item 6 | Selected Financial Data | |
Item 7 | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Item 7A | Quantitative and Qualitative Disclosures About Market Risk | |
Item 8 | Financial Statements and Supplementary Data | |
Item 9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | |
Item 9A | Controls and Procedures | |
Item 9B | Other Information | |
PART III | ||
Item 10 | Directors, Executive Officers and Corporate Governance | |
Item 11 | Executive Compensation | |
Item 12 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | |
Item 13 | Certain Relationships and Related Transactions and Director Independence | |
Item 14 | Principal Accounting Fees and Services | |
PART IV | ||
Item 15 | Exhibits and Financial Statement Schedules | |
Index to Financial Statements Covered by Report of Independent Registered Public Accounting Firm | ||
Index to Exhibits | ||
Signatures | ||
2
Glossary of Commonly Used Terms, Abbreviations and Measurements
Commonly Used Terms
AFUDC – Allowance for Funds Used During Construction – carrying costs for the construction of certain long-term regulated 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.
multiple completion well – a well equipped to produce oil and/or gas separately from more than one reservoir. Such wells contain multiple strings of tubing or other equipment that permit production from the various completions to be measured and accounted for separately.
3
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 adding 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 gas – the volume of natural gas in the storage reservoir that can be extracted during the normal operation of the storage facility.
working interest – an interest that gives the owner the right to drill, produce and conduct operating activities on a property and receive a share of any production.
4
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
WTI – West Texas Intermediate
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
5
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; technology (including drilling and completion techniques); production sales volumes (including liquids volumes); gathering and transmission volumes (including the subscription of additional capacity related to the expiration of EQT Midstream Partners, LP firm transportation contracts); the weighted average contract life of transmission and storage contracts; infrastructure programs (including the timing, cost and capacity of the transmission and gathering expansion projects); the timing, cost, capacity and expected interconnects with facilities and pipelines of the Ohio Valley Connector and Mountain Valley Pipeline (MVP) projects; the ultimate terms, partners and structure of the MVP joint venture; the Partnership’s assumption of the Company’s interest in the MVP joint venture; 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; the amount and timing of any repurchases under the Company’s share repurchase authorization; the timing of the termination of the Company’s defined benefit plan; 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, many of which are difficult to predict and 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.
6
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 10.7 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 3.4 million gross acres, including approximately 630,000 gross acres in the Marcellus play, as of December 31, 2014. 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 2014
During 2014, EQT achieved record annual production sales volumes, including a 26% increase in total sales volumes and a 38% increase in Marcellus sales volumes. EQT’s midstream business delivered record gathered volumes that were 27% higher than the previous year. During 2014, EQT Midstream Partners, LP (the Partnership) reported net income of $232.8 million, $61.7 million higher than 2013. The increase was primarily related to higher operating income driven by production development in the Marcellus Shale by EQT and third parties. EQT also completed the following transactions that were instrumental in contributing to a successful 2014:
• | On May 7, 2014, a wholly owned subsidiary of the Company, EQT Gathering, LLC (EQT Gathering), contributed a |
high-pressure gathering system to EQM Gathering Opco, LLC (EQM Gathering), a wholly owned subsidiary of the Partnership, in exchange for $1.18 billion (the Jupiter Transaction). EQM Gathering is consolidated by the Company as it is still controlled by the Company.
• | On May 7, 2014, the Partnership completed an underwritten public offering of 12,362,500 common units, which included the full exercise of the underwriters’ overallotment option, representing Partnership limited partner interests. The Partnership received net proceeds of approximately $902.5 million from the offering, after deducting the underwriters’ discount and offering expenses. |
• | In June 2014, the Company exchanged certain assets with Range Resources Corporation (Range). The Company received approximately 73,000 net acres and approximately 900 producing wells, most of which are vertical wells, in the Permian Basin of Texas. In exchange, Range received approximately 138,000 net acres in the Company’s Nora field of Virginia (Nora), the Company’s working interest in approximately 2,000 producing vertical wells in Nora, the Company’s remaining 50% ownership interest in Nora Gathering, LLC (Nora LLC), which owns the supporting gathering system in Nora, and $167.3 million in cash. |
• | In July 2014, the Partnership announced that it will construct and own the Ohio Valley Connector (OVC) pipeline. The OVC includes a 36-mile pipeline that will extend the Partnership’s transmission and storage system from northern West Virginia to Clarington, Ohio, at which point it will interconnect with the Rockies Express Pipeline and the Texas Eastern Pipeline. In December 2014, the Partnership submitted the OVC certificate application to the FERC and anticipates receiving the certificate in the second half of 2015. Subject to FERC approval, construction is scheduled to begin in the third quarter of 2015 and the pipeline is expected to be in-service by mid-year 2016. The OVC will provide approximately 850 BBtu per day of transmission capacity and the 36-mile pipeline portion is estimated to cost approximately $300 million, of which $120 million to $130 million is expected to be spent in 2015. The Partnership has entered into a 20-year precedent agreement with the Company for a total of 650 BBtu per day of firm transmission capacity on the OVC. |
• | In August 2014, the Partnership issued 4.00% Senior Notes (4.00% Senior Notes) due August 1, 2024 in the aggregate principal amount of $500.0 million. Net proceeds of the offering of $492.3 million were used to repay the outstanding borrowings under the Partnership’s credit facility and for general partnership purposes. |
• | In September 2014, the Company and an affiliate of NextEra Energy, Inc. announced the formation of a joint venture, Mountain Valley Pipeline, LLC (MVP LLC), that will construct and own the Mountain Valley Pipeline (MVP). The Company expects to transfer its interest in MVP LLC to the Partnership. The approximately 300-mile pipeline will extend from the Partnership’s existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia. The Company expects that the Partnership will own the largest interest in the joint venture and will operate the MVP, which is estimated to cost a total of approximately $2.5 billion to $3.5 billion, with the Partnership funding its |
7
proportionate share through capital contributions made to the joint venture. In 2015, the Partnership’s capital contributions are expected to be approximately $75 million to $85 million and will be primarily in support of environmental and land assessments, design work and materials. Expenditures are expected to increase substantially as construction commences, with the bulk of the expenditures expected to be made in 2017 and 2018. The joint venture has secured a total of 2.0 Bcf per day of firm capacity commitments at 20-year terms and is currently in negotiation with additional shippers who have expressed interest in the MVP project. As a result, the final project scope, including pipe diameter and total capacity, has not yet been determined; however the voluntary pre-filing process with the FERC began in October 2014. The pipeline, which is subject to FERC approval, is expected to be in-service during the fourth quarter of 2018.
EQT Production Business Segment
EQT Production is one of the largest natural gas producers in the Appalachian Basin with 10.7 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 3.4 million gross acres, including approximately 630,000 gross acres in the Marcellus play, as of December 31, 2014. 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 29% in 2014, primarily across the Marcellus shale play. The Company’s Marcellus assets, including Upper Devonian assets, contribute approximately 8.7 Tcfe in total proved reserves.
8
The following illustration depicts EQT’s acreage position within the Marcellus play:
9
As of December 31, 2014, the Company’s proved reserves were as follows:
(Bcfe) | Marcellus | Huron (a) | Upper Devonian | Other | Total | ||||||||||
Proved Developed | 2,708 | 1,203 | 155 | 760 | 4,826 | ||||||||||
Proved Undeveloped | 5,576 | 37 | 300 | — | 5,913 | ||||||||||
Total Proved Reserves | 8,284 | 1,240 | 455 | 760 | 10,739 | ||||||||||
(a) Includes 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 2014, the remaining reserve life of the Company’s total proved reserves, as calculated by dividing total proved reserves by 2014 produced volumes, is 22 years.
The Company invested approximately $1,717 million on well development during 2014, with total production sales volumes hitting a record high of 476.3 Bcfe, an increase of 26% over the previous year. Capital spending for EQT Production is expected to be approximately $1.85 billion in 2015 (excluding land acquisitions), the majority of which will be used to support the drilling of approximately 191 gross wells, including 122 Marcellus wells, 59 Upper Devonian wells and 10 other wells. 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: | 2014 | 2013 | 2012 | |||||||||
Horizontal Marcellus* | 237 | 168 | 127 | |||||||||
Horizontal Huron | 103 | 50 | 7 | |||||||||
Other | 5 | 7 | 1 | |||||||||
Total | 345 | 225 | 135 | |||||||||
Capital expenditures for well development: | ||||||||||||
(in millions): | ||||||||||||
Horizontal Marcellus* | $ | 1,456 | $ | 1,103 | $ | 810 | ||||||
Horizontal Huron | 188 | 79 | 22 | |||||||||
Other | 73 | 55 | 25 | |||||||||
Total | $ | 1,717 | $ | 1,237 | $ | 857 | ||||||
* Includes Upper Devonian formations.
10
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 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, 2014, the Company held a 34.4% 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 8,200 miles of gathering lines, 1,500 miles of which are FERC-regulated, low-pressure gathering lines owned by the Partnership. The Partnership also owns 45 miles of high pressure gathering lines which are not subject to federal rate regulation. The left-hand map on page 12 depicts the Company’s gathering lines and compressor stations in relationship to the Marcellus Shale formation. During 2014, the Company turned in-line approximately 60 miles of pipeline and 80,000 horse power of compression capacity primarily in the Marcellus play, which added approximately 475 MMcf per day of incremental gathering capacity, resulting in year-end Marcellus gathering capacity of 1,975 MMcf per day, consisting of 1,405 MMcf per day in Pennsylvania and 570 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, L.P. (Equitrans) and is 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 December 2013 in connection with the Equitable Gas Transaction (as described in Note 2 to the Consolidated Financial Statements).
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 operated by the Partnership under a lease between the Partnership and an affiliate of the Company.
The right-hand map on page 12 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 2014 to take advantage of rapid production development in the Marcellus play. During 2014, the Company added approximately 750 MMcf per day of incremental transmission capacity, 550 MMcf per day of incremental transmission capacity through the completed Jefferson Compression Expansion project as well as 200 MMcf per day of transmission capacity through several third-party contracts. As a result of these expansion projects, EQT Midstream year-end total transmission capacity was approximately 3,450 MMcf per day.
11
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 1,400,000 Dth per day of third-party contractual pipeline capacity for the benefit of EQT Production; and has committed to an additional 850,000 Dth per day of third-party contractual capacity to come online in future periods. EQT Energy currently leases 3.7 Bcf of storage-related assets from third parties.
12
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 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. Additionally, EQT entered into a joint venture agreement with an affiliate of NextEra Energy, Inc. to construct the MVP. The proposed pipeline is expected to be approximately 300 miles long, span from Wetzel County, West Virginia to Pittsylvania County, Virginia and be designed to transport natural gas production from the Marcellus and Utica to the growing demand markets in the southeast region of the United States.
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 grow profitably and provide an ongoing source of capital to the Company.
See “Capital Resources and Liquidity” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report on 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 the Northeastern United States as well as the Permian Basin of Texas. The Company’s current transportation portfolio also enables the Company to reach markets along the Gulf Coast of the United States. Natural gas is a commodity and therefore the Company receives market-based pricing. The market price for natural gas in the Appalachian Basin continues to be lower relative to the price at Henry Hub located in Louisiana, which is the location for pricing NYMEX and natural gas futures, as a result of the increased supply of natural gas in the Northeast region. 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.
The Company is also helping to build additional demand for natural gas. In mid-2011, EQT opened a public-access natural gas fueling station in Pittsburgh, Pennsylvania and, with the growing demand for compressed natural gas for numerous fleets throughout the region, the station underwent an expansion in 2013, adding two more dispensers. In conjunction with this project, the Company is promoting the use of natural gas with its own fleet vehicles and plans to operate 14% of its light-duty vehicle fleet, more than 180 vehicles, on natural gas by the end of 2015. In addition, the Company is operating four drilling rigs that utilize natural gas with three additional expected in 2015 and one hydraulic fracturing crew with one additional crew expected in 2015.
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. In its Appalachian operations, the Company contracts with MarkWest Energy Partners, L.P. (MarkWest) to process natural gas in order to extract heavier liquid hydrocarbons (propane, iso-butane, normal butane and natural gasoline) from the natural gas stream, primarily from EQT Production’s produced gas. NGLs are recovered at the processing plants and transported to a fractionation plant owned by MarkWest for separation into commercial components. MarkWest markets these components for a fee. The Company also has contractual processing arrangements in its Permian Basin operations whereby the Company sells gas to third-party processors at a weighted average liquids component price.
13
The following table presents the average sales price on an average per Mcfe basis to EQT Corporation for sales of produced natural gas, NGLs and oil, with and without cash settled derivatives, for the years ended December 31:
2014 | 2013 | 2012 | ||||||||||
Average sales price per Mcfe sold (excluding cash settled derivatives) | $ | 4.14 | $ | 3.81 | $ | 3.06 | ||||||
Average sales price per Mcfe sold (including cash settled derivatives) | $ | 4.16 | $ | 4.20 | $ | 4.19 | ||||||
In addition, 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 2014 totaled 590.5 TBtu, of which approximately 90% related to gathering for EQT Production and other affiliates. Revenues from EQT Production and other affiliates accounted for approximately 91% of 2014 gathering revenues.
Natural Gas Transmission, Storage and Marketing: Natural gas transmission and storage operations are executed using transmission and underground storage facilities owned by the Company. EQT Energy provides marketing services and third-party contractual pipeline capacity management for the benefit of EQT Production and also leases storage capacity in order to take advantage of seasonal spreads where available through the EQT Midstream segment. EQT Energy also engages in risk management and hedging activities on behalf of EQT Production, the objective of which is to limit the Company’s exposure to shifts in market prices.
Customers of EQT Midstream’s gas transportation and storage services are affiliates and third parties primarily in the northeastern United States.
As of December 31, 2014, the weighted average remaining contract life based on total projected contracted revenues for the Partnership’s firm transmission and storage contracts was approximately 17 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 2014, approximately 57% of transportation volumes and 51% of transportation revenues were from affiliates.
One customer within the EQT Production segment accounts for approximately 12% and 11% of EQT Production’s total operating revenues in 2014 and 2013, respectively. 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.
Competition
Natural gas producers compete in the acquisition of properties, the search for and development of reserves, the production, transportation 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.
14
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, well stimulation, hydraulic fracturing 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. Kentucky, Ohio, Virginia and, for Utica or other deep wells, West Virginia allow the statutory pooling or integration of tracts to facilitate development and exploration. In West Virginia, the Company must rely on voluntary pooling of lands and leases for Marcellus and Upper Devonian acreage. In 2013, the Pennsylvania legislature enacted lease integration legislation, which authorizes joint development of existing contiguous leases, and Texas permits similar joint development. In addition, state conservation and oil and gas laws generally limit the venting or flaring of natural gas, and Texas sets production allowances on the amount of annual production permitted from a well.
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.
In 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 legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), required the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing this 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 finalized. 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 regulations on the Company’s hedging program or regulatory compliance obligations. The Company has experienced increased, and expects additional, compliance costs and changes to current market practices as participants continue to adapt to a changing regulatory environment.
Regulators periodically review or 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.
15
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.
See Note 18 to the Consolidated Financial Statements for a description of expenditures related to environmental matters.
Climate Change
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. The EPA and various states have issued a number of proposed and final laws and regulations that limit greenhouse gas emissions. Legislation or regulation that restricts carbon emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Climate change and greenhouse gas legislation or regulation could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, or impose additional monitoring and reporting requirements. Conversely, legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because the combustion of natural gas results in substantially fewer carbon emissions per Btu of heat generated than other 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 1,750 employees at the end of 2014, and none are subject to a collective bargaining agreement.
16
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, | ||||||
2014 | 2013 | 2012 | ||||
EQT Production: | ||||||
Natural gas sales | 66% | 61% | 55% | |||
EQT Midstream: | ||||||
Gathering revenue | 15% | 18% | 20% | |||
Regulated storage and transmission | 11% | 9% | 9% | |||
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.
17
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, NGL and oil 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, NGLs and oil. The markets for natural gas, NGLs and oil are volatile and fluctuations in prices will affect our financial results. The price of natural gas, NGLs and oil are affected by a number of factors beyond our control, which include: weather conditions and seasonal trends; the supply of and demand for natural gas, NGLs and oil; 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, NGL and oil 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, as well as downward adjustments to the value of our oil and gas properties which may cause us to incur non-cash charges to earnings. Moreover, a failure to control our development costs during periods of lower natural gas, NGL and oil prices could have significant adverse effects on our earnings, cash flows and financial position. A reduction in operating income or cash flow will reduce our funds available for capital expenditures and, correspondingly, our opportunities for profitable 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. If commodity prices continue to trend lower as they did in the latter part of 2014, it could signal a need to reduce capital spending, be an indicator of impairment of the Company’s assets, and have a substantial impact on, among other things, the Company’s revenues, earnings, liquidity, reserves, DD&A rates and development plans.
Increases in natural gas, NGL and oil 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 natural gas 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 derivative contract. 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 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 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.
18
Cyber incidents may adversely impact our operations.
Our business has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, to operate our production and midstream businesses, and the maintenance of our financial and other records has long been dependent upon such technologies. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Deliberate attacks on, or unintentional events affecting, our systems or infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery of natural gas and NGLs, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage, other operational disruptions and third-party liability. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.
Our failure to develop, obtain, access or maintain the necessary infrastructure to successfully deliver gas, NGLs and oil to market may adversely affect our earnings, cash flows and results of operations.
Our delivery of gas, NGLs and oil 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, NGL and oil price volatility, government approvals, title and property access problems, geology, compliance by third parties with their contractual obligations to us and other factors. Moreover, if our infrastructure development and maintenance programs are not successfully developed on time and within budget, we may not be able to profitably fulfill our contractual obligations to third parties, including joint venture partners.
We also deliver to and are served by third-party natural gas, NGL and oil 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, NGLs and oil. In such an event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell our production at prices lower than market prices or at prices lower 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, NGLs and oil to market.
Also, our producing properties and operations are primarily in 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 and NGLs 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 future growth rate.
Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our 2015 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 2015 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
19
affected. Moreover, economic or other circumstances may change from those contemplated by our 2015 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
We periodically engage in acquisitions, dispositions and other strategic transactions, including joint ventures. 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 the transactions. In addition, various factors including prevailing market conditions could negatively impact the benefits we receive from transactions. Joint venture arrangements may restrict our operational and corporate flexibility. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may have little control over, and our joint venture partners may not satisfy their obligations to the joint venture. 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 or regulation has been proposed or is under discussion at federal, state, and local levels. For instance, legislation or regulation banning hydraulic fracturing has been adopted in a number of jurisdictions in which we do not have drilling operations. We cannot predict whether any other such federal, state or local 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 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.
20
In 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 legislation, known as the Dodd-Frank Act, required the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing the 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 finalized. 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 regulations on the Company’s hedging program, including available counterparties, or regulatory compliance obligations. The Company has experienced increased, and anticipates additional, 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 access to capital markets and changes in the terms of and cost of capital, including increases in interest rates, 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, NGLs and oil 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 our 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 natural gas, NGLs and oil to market. Moreover, an incorrect determination of legal title to our wells could result in liability to the owner of the natural gas or oil rights and an impairment to our assets. Successfully identifying production opportunities involves a high degree of business experience, knowledge and careful evaluation of potential opportunities, along with subjective judgments and assumptions that may prove to be incorrect. In addition, any exploration projects increase the risks inherent in our production 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.
The amount and timing of actual future gas, NGL and oil 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, natural gas, NGL and oil price volatility, government approvals, title and property access problems, geology, equipment failure or accidents and other factors. Drilling for natural gas, NGLs and oil 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
21
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.
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.
22
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 Texas. This segment has approximately 3.4 million gross acres (approximately 64% 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 630,000 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, 2014, the Company estimated its total proved reserves to be 10.7 Tcfe, consisting of proved developed producing reserves of 4.7 Tcfe, proved developed non-producing reserves of 0.1 Tcfe and proved undeveloped reserves of 5.9 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 Chemical Engineering from the Pennsylvania State University and has 17 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 natural gas, NGL and oil proved reserves attributable to the Company’s interests as of December 31, 2014. Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties. This audit covered 80% of the Company’s proved developed reserves. Ryder Scott’s audit of the remaining 20% of the Company’s proved developed properties consisted of an audit of aggregated groups not exceeding 200 wells per case for operated wells and 230 wells per case for non-operated wells. For undeveloped locations, Ryder Scott determined which areas within the Company’s acreage were to be considered proven. Reserves were assigned and projected by the Company’s reserves engineers for locations within these proven areas and approved by Ryder Scott based on analogous type curves and offset production information. Ryder Scott’s audit report has been filed herewith as Exhibit 99.
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 2014, the Company commenced drilling operations (spud or drilled) on 237 gross horizontal wells with an aggregate of approximately 1.4 million feet of pay in the Marcellus, including Upper Devonian, play. Total proved reserves in the Marcellus, including Upper Devonian, play increased 42% to 8.7 Tcfe in 2014 primarily as a result of the Company’s 2014 and 2013 drilling programs. In the Huron play, the Company spud 103 gross horizontal wells during 2014 with an aggregate of approximately 605,000 feet of pay. Total proved reserves in the Huron play decreased approximately 6% to 1.2 Tcfe, as the Company ceased development of the Huron play and removed remaining proved undeveloped locations, as they are no longer in the five year development program. Production sales volumes in 2014 from the Marcellus, including Upper Devonian, and Huron plays were 378.2 Bcfe and 33.8 Bcfe, respectively. Over the past three years, the Company has experienced a 99% developmental drilling success rate.
23
Natural gas, NGLs and crude oil pricing:
For the Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Natural Gas: | ||||||||||||
Average sales price (excluding cash settled derivatives) ($/Mcf) | $ | 4.51 | $ | 4.18 | $ | 3.58 | ||||||
Average sales price (including cash settled derivatives) ($/Mcf) | $ | 4.53 | $ | 4.60 | $ | 4.80 | ||||||
Average sales price (including cash settled derivatives and third-party gathering and transmission costs) ($/Mcf) | $ | 3.98 | $ | 4.00 | $ | 3.92 | ||||||
NGLs: | ||||||||||||
Average sales price including third-party processing costs ($/Bbl) | $ | 32.44 | $ | 36.80 | $ | 40.84 | ||||||
Crude Oil: | ||||||||||||
Average sales price ($/Bbl) | $ | 78.51 | $ | 85.82 | $ | 83.95 | ||||||
NGLs and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods.
For additional information on 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 2014, 2013 and 2012 was $0.14, $0.15 and $0.17 per Mcfe, respectively. At December 31, 2014, the Company had approximately 50 multiple completion wells.
Natural Gas | Oil | |||
Total productive wells at December 31, 2014: | ||||
Total gross productive wells | 13,073 | 314 | ||
Total net productive wells | 12,413 | 264 | ||
Total in-process wells at December 31, 2014: | ||||
Total gross in-process wells | 270 | 1 | ||
Total net in-process wells | 266 | 1 | ||
Summary of proved natural gas, oil and NGL reserves as of December 31, 2014 based on average fiscal year prices:
Natural Gas (Mcf) | Oil and NGLs (Bbls) | |||
Developed | 4,257,377 | 94,835 | ||
Undeveloped | 5,518,577 | 65,664 | ||
Total proved reserves | 9,775,954 | 160,499 | ||
Total acreage at December 31, 2014: | |
Total gross productive acres | 1,220,336 |
Total net productive acres | 1,109,464 |
Total gross undeveloped acres | 2,215,922 |
Total net undeveloped acres | 2,033,302 |
24
As of December 31, 2014, the Company had a total of 15.3 Bcfe of reserves that have been classified as proved undeveloped for more than five years. These reserves are associated with two wells that were drilled in 2014 and that are scheduled to be completed and producing in 2015.
Certain lease and acquisition agreements require the Company to drill a specific number of wells in 2015. Within the Marcellus formation, the Company is required to drill three wells in 2015. The Company intends to satisfy such requirements either directly through its 2015 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, 2014, leases associated with approximately 45,551 gross undeveloped acres expire in 2015 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, | |||||||||
2014 | 2013 | 2012 | |||||||
Exploratory wells: | |||||||||
Productive | 2.0 | — | — | ||||||
Dry | — | — | — | ||||||
Development wells: | |||||||||
Productive | 340.4 | 223.2 | 128.5 | ||||||
Dry | — | 1.0 | 1.0 | ||||||
25
Selected production, sales and acreage data by state (as of December 31, 2014 unless otherwise noted), which is substantially all from the Appalachian Basin. Refer to pages 36 and 39 for sales volumes by final product.
Pennsylvania | West Virginia | Kentucky | Other (b) | Total | |||||||||||
Natural gas, oil and NGL production (MMcfe) – 2014 (a) | 237,365 | 164,330 | 66,775 | 19,609 | 488,079 | ||||||||||
Natural gas, oil and NGL production (MMcfe) – 2013 (a) | 196,250 | 103,861 | 65,467 | 22,811 | 388,389 | ||||||||||
Natural gas, oil and NGL production (MMcfe) – 2012 (a) | 96,101 | 83,177 | 72,731 | 23,438 | 275,447 | ||||||||||
Natural gas, oil and NGL sales (MMcfe) – 2014 | 240,685 | 158,868 | 58,790 | 17,917 | 476,260 | ||||||||||
Natural gas, oil and NGL sales (MMcfe) – 2013 | 201,653 | 96,710 | 58,759 | 21,051 | 378,173 | ||||||||||
Natural gas, oil and NGL sales (MMcfe) – 2012 | 97,368 | 79,514 | 65,799 | 21,773 | 264,454 | ||||||||||
Average net revenue interest (%) | 82.9 | % | 87.9 | % | 95.8 | % | 57.2 | % | 84.4 | % | |||||
Total gross productive wells | 1,008 | 4,990 | 5,657 | 1,732 | 13,387 | ||||||||||
Total net productive wells | 996 | 4,755 | 5,405 | 1,521 | 12,677 | ||||||||||
Total gross productive acreage | 96,676 | 430,014 | 545,463 | 148,183 | 1,220,336 | ||||||||||
Total gross undeveloped acreage | 298,874 | 770,189 | 942,565 | 204,294 | 2,215,922 | ||||||||||
Total gross acreage | 395,550 | 1,200,203 | 1,488,028 | 352,477 | 3,436,258 | ||||||||||
Total net productive acreage | 88,709 | 394,576 | 500,510 | 125,669 | 1,109,464 | ||||||||||
Total net undeveloped acreage | 288,532 | 663,227 | 903,309 | 178,234 | 2,033,302 | ||||||||||
Total net acreage | 377,241 | 1,057,803 | 1,403,819 | 303,903 | 3,142,766 | ||||||||||
(Amounts in Bcfe) | |||||||||||||||
Proved developed producing reserves | 1,679 | 1,453 | 1,340 | 208 | 4,680 | ||||||||||
Proved developed non-producing reserves | 97 | 37 | 12 | — | 146 | ||||||||||
Proved undeveloped reserves | 3,471 | 2,405 | 37 | — | 5,913 | ||||||||||
Proved developed and undeveloped reserves | 5,247 | 3,895 | 1,389 | 208 | 10,739 | ||||||||||
Gross proved undeveloped drilling locations | 486 | 389 | 29 | — | 904 | ||||||||||
Net proved undeveloped drilling locations | 483 | 389 | 29 | — | 901 | ||||||||||
(a) All production information related to natural gas is reported net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs.
(b) Other includes Ohio, Virginia, Maryland and Texas.
26
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, 2014, the Company’s delivery commitments through 2019 were as follows:
For the Year Ended December 31, | Natural Gas (Bcf) | |
2015 | 470 | |
2016 | 299 | |
2017 | 238 | |
2018 | 184 | |
2019 | 14 | |
Capital expenditures at EQT Production totaled $2,441 million during 2014, including $724 million for the acquisition of properties. The Company invested approximately $1,196 million during 2014 developing proved reserves and approximately $521 million on wells still in progress at year end. During the year, the Company converted 790 Bcfe of proved undeveloped reserves to proved developed reserves. The Company had additions to proved developed reserves of 737 Bcfe, the majority of which were from wells spud that had not previously been classified as proved. New proved undeveloped reserves of 2,829 Bcfe were added during 2014. These reserve extensions and discoveries were mainly due to the addition of proved locations in the Company’s Pennsylvania and West Virginia Marcellus play. This increase was partially offset by negative revisions to proved undeveloped reserves of 489 Bcfe, which was due primarily to the removal of locations in both the Company’s Marcellus and Huron plays, the latter of which the Company announced will not be a target for drilling in its current development outlook. While the Company may develop these reserves, projected development has been delayed beyond 5 years. As of December 31, 2014, the Company’s proved undeveloped reserves totaled 5.9 Tcfe, 99% of which is associated with the development of the Marcellus, including Upper Devonian, play. All proved undeveloped drilling locations are expected to be drilled within five years.
The Company’s 2014 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 3,276 Bcfe exceeded the 2014 production of 488 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 other areas are in CBM, Utica and Permian formations with depths ranging from 2,000 feet to 7,000 feet.
EQT Production owns and leases office space in Pennsylvania, West Virginia, Kentucky and Texas.
EQT Midstream: EQT Midstream including EQT Midstream Partners, owns or operates approximately 8,200 miles of gathering lines and 176 compressor units with approximately 225,000 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 | 4,025 | 400 | 225 | 8,200 | |||||
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.
27
Headquarters: The Company’s 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.
Item 3. Legal Proceedings
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal and 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.
Environmental Proceedings
In June and August 2012, the Company received three Notices of Violation (NOVs) from the Pennsylvania Department of Environmental Protection (the PADEP). The NOVs alleged violations of the Pennsylvania Oil and Gas Act and Clean Streams Law in connection with the unintentional release in May 2012, by a Company vendor, of water from an impaired water pit at a Company well location in Tioga County, Pennsylvania. Since confirming the release, the Company has cooperated with the PADEP in remediating the affected areas.
During the second quarter of 2014, the Company received a proposed consent assessment of civil penalty (CACP) from the PADEP and the Pennsylvania Fish and Boat Commission (the PFBC). Under the CACP, the PADEP proposed a civil penalty related to the NOVs and the PFBC proposed a civil penalty related to possible violations of the Pennsylvania Fish and Boat Code. The Company entered into settlement discussions regarding the assessed penalty with the PFBC and unsuccessfully attempted to do the same with the PADEP. The Company was unable to resolve the PADEP claims due to the agency’s interpretation of the penalty provisions of the Clean Streams Law. Accordingly, on September 19, 2014, the Company filed a declaratory judgment action in the Commonwealth Court of Pennsylvania against the PADEP seeking a court ruling on the legal interpretation. The Company did not include the PFBC in the action due to ongoing settlement discussions.
On September 30, 2014, the PFBC filed a misdemeanor complaint against the Company through the Pennsylvania Attorney General’s Office in the Tioga County court; the Company has initiated settlement discussions with the Attorney General’s Office.
On October 7, 2014, the PADEP filed a complaint against the Company before the Pennsylvania Environmental Hearing Board seeking $4.5 million in civil penalties. The Company believes the PADEP’s penalty assessment is legally flawed and unsupportable under the Clean Streams Law.
While the Company expects these claims to result in penalties that exceed $100,000, the Company expects the resolution of these matters, individually and in the aggregate, will not have a material impact on the financial position, results of operations or liquidity of the Company.
Item 4. Mine Safety Disclosures
Not Applicable.
28
Executive Officers of the Registrant (as of February 12, 2015)
Name and Age | Current Title (Year Initially Elected an Executive Officer) | Business Experience | ||
Theresa Z. Bone (51) | 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, 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 (55) | 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 (52) | 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 to December 2013. | ||
Lewis B. Gardner (57) | General Counsel and Vice President, External Affairs (2008) | Elected to present position March 2008. Mr. Gardner is also a Director of EQT Midstream Services, LLC, the general partner of the Partnership, since January 2012. | ||
Charlene Petrelli (54) | Vice President and Chief Human Resources Officer (2003) | Elected to present position February 2007. | ||
David L. Porges (57) | 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 (49) | 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 elected and qualified, or until death, resignation or removal.
29
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 2014 and 2013 are summarized as follows (in U.S. dollars per share):
2014 | 2013 | |||||||||||||||||||||||
High | Low | Dividend | High | Low | Dividend | |||||||||||||||||||
1st Quarter | $ | 104.72 | $ | 84.25 | $ | 0.03 | $ | 68.44 | $ | 56.84 | $ | 0.03 | ||||||||||||
2nd Quarter | 111.47 | 95.78 | 0.03 | 84.00 | 64.71 | 0.03 | ||||||||||||||||||
3rd Quarter | 107.71 | 89.77 | 0.03 | 94.42 | 78.57 | 0.03 | ||||||||||||||||||
4th Quarter | 100.65 | 74.37 | 0.03 | 91.59 | 80.72 | 0.03 | ||||||||||||||||||
As of January 31, 2015, there were 2,652 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. The Board of Directors has the discretion to change the annual dividend rate at any time for any reason.
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 during the three months ended December 31, 2014:
Period | Total number of shares purchased (a) | Average price paid per share (a) | Total number of shares purchased as part of publicly announced plans or programs | Maximum number of shares that may yet be purchased under the plans or programs (b) | |||||||||
October 2014 (October 1 – October 31) | — | $ | — | — | 700,000 | ||||||||
November 2014 (November 1 – November 30) | 2,904 | 94.61 | — | 700,000 | |||||||||
December 2014 (December 1 – December 31) | — | — | — | 700,000 | |||||||||
Total | 2,904 | $ | 94.61 | — | |||||||||
(a) Reflects shares withheld by the Company to pay taxes upon vesting of restricted stock.
(b) On April 30, 2014, the Company’s Board of Directors approved a share repurchase authorization of up to 1,000,000 shares of the Company’s outstanding common stock. The Company may repurchase shares from time to time in open market or in privately negotiated transactions. The share repurchase authorization does not obligate the Company to acquire any specific number of shares, has no pre-established end date and may be discontinued by the Company at any time. As of December 31, 2014, the Company has repurchased 300,000 shares under this authorization since its inception.
30
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 a customized peer group of the 25 companies listed in footnote (a) below (the Self-Constructed Peer Group). An investment of $100 (with reinvestment of all dividends) is assumed to have been made at the close of business on December 31, 2009 in the Company’s common stock, in the S&P 500 Index and in the Self-Constructed Peer Group. Relative performance is tracked through December 31, 2014.
12/09 | 12/10 | 12/11 | 12/12 | 12/13 | 12/14 | |||||||||||||
EQT Corporation | 100.00 | 104.35 | 129.58 | 141.79 | 216.18 | 182.50 | ||||||||||||
S&P 500 | 100.00 | 115.06 | 117.49 | 136.30 | 180.44 | 205.14 | ||||||||||||
Self-Constructed Peer Group (a) | 100.00 | 115.69 | 118.76 | 121.37 | 168.90 | 149.85 | ||||||||||||
(a) The Self-Constructed Peer Group includes the following 25 companies: 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, 2014.
The Self-Constructed Peer Group is the same peer group used for the Company’s 2014 and 2015 Executive Performance Incentive Programs, each of which utilize 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.
31
Item 6. Selected Financial Data
As of and for the Years Ended December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | 2011 | 2010 | ||||||||||||||||
(Thousands, except per share amounts) | ||||||||||||||||||||
Operating revenues | $ | 2,469,710 | $ | 1,862,011 | $ | 1,377,222 | $ | 1,323,829 | $ | 1,038,240 | ||||||||||
Amounts attributable to EQT Corporation: | ||||||||||||||||||||
Income from continuing operations | $ | 385,594 | $ | 298,729 | $ | 135,902 | $ | 419,582 | $ | 164,761 | ||||||||||
Net income | $ | 386,965 | $ | 390,572 | $ | 183,395 | $ | 479,769 | $ | 227,700 | ||||||||||
Earnings per share of common stock attributable to EQT Corporation: | ||||||||||||||||||||
Basic: | ||||||||||||||||||||
Income from continuing operations | $ | 2.54 | $ | 1.98 | $ | 0.91 | $ | 2.81 | $ | 1.14 | ||||||||||
Net income | $ | 2.55 | $ | 2.59 | $ | 1.23 | $ | 3.21 | $ | 1.58 | ||||||||||
Diluted: | ||||||||||||||||||||
Income from continuing operations | $ | 2.53 | $ | 1.97 | $ | 0.90 | $ | 2.79 | $ | 1.14 | ||||||||||
Net income | $ | 2.54 | $ | 2.57 | $ | 1.22 | $ | 3.19 | $ | 1.57 | ||||||||||
Total assets | $ | 12,064,900 | $ | 9,792,053 | $ | 8,849,862 | $ | 8,772,719 | $ | 7,098,438 | ||||||||||
Long-term debt | $ | 2,988,900 | $ | 2,501,516 | $ | 2,526,173 | $ | 2,746,942 | $ | 1,949,200 | ||||||||||
Cash dividends declared per share of common stock | $ | 0.12 | $ | 0.12 | $ | 0.88 | $ | 0.88 | $ | 0.88 | ||||||||||
Refer to Note 2 to the Consolidated Financial Statements for a description of the Equitable Gas Transaction. Equitable Gas Company, LLC (Equitable Gas) and Equitable Homeworks, LLC (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.
32
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Consolidated Results of Continuing Operations
2014 EQT Overview:
•Annual production sales volumes of 476.3 Bcfe, 26% higher than 2013
•Marcellus sales volumes of 378.2 Bcfe, 38% higher than 2013
•Gathered volumes of 590.5 TBtu, 27% higher than 2013
•Increased proved reserves by 29% to 10.7 Tcfe
•The Partnership completed an underwritten public offering of common units representing limited partner interests
•The Partnership issued 4.00% Senior Notes of $500.0 million due August 1, 2024
• | Recognized impairment of proved and unproved oil and gas properties of $267.3 million (pre-tax) in the Ohio Utica and Permian Basin |
Income from continuing operations attributable to EQT Corporation for 2014 was $385.6 million, $2.53 per diluted share, compared with $298.7 million, $1.97 per diluted share, in 2013. The $86.9 million increase in income from continuing operations attributable to EQT Corporation was primarily attributable to a 26% increase in production sales volumes, favorable gains on derivatives not designated as hedges, increases in contracted transmission capacity and throughput and gathered volumes, favorable changes in hedging ineffectiveness, and lower interest expense. These factors were partially offset by impairments of long-lived assets, higher net income attributable to noncontrolling interests of the Partnership, higher transportation and processing expenses, higher income tax expense, higher selling, general and administrative (SG&A) expense and higher depreciation, depletion and amortization (DD&A) expense.
Operating income was $853.4 million in 2014 compared to $654.6 million in 2013, an increase of $198.8 million. EQT Production sales volumes increased 26% primarily as a result of increased production from the 2014 and 2013 drilling programs in the Marcellus acreage partially offset by the normal production decline in the Company’s producing wells. The average realized price to EQT Production for sales volumes was $3.23 per Mcfe in 2014 compared to $3.15 per Mcfe in 2013. EQT Production total net operating revenues for the year ended December 31, 2014 included $83.8 million of derivative gains for derivative instruments not designated as hedging instruments compared to $0.3 million of derivative losses for the year ended December 31, 2013. The $83.8 million of derivative gains for derivative instruments not designated as hedging instruments for the year ended December 31, 2014 included $36.5 million of cash settlements received, which is included in the average realized price to EQT Production of $3.23 per Mcfe in 2014. The year ended December 31, 2014 also included a $24.8 million gain for hedging ineffectiveness of financial hedges compared to a $21.3 million loss for ineffectiveness of financial hedges for the year ended December 31, 2013.
Transmission net operating revenues increased as a result of higher firm transmission contracted capacity and throughput for third parties and EQT Production, as well as higher interruptible transmission service. The increase in transmission net operating revenues is the result of increased production development in the Marcellus play. Gathering net operating revenues increased due to a 27% increase in gathered volumes, partially offset by an 11% 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 2014 were $1,650.5 million compared to $1,227.0 million in 2013, an increase of $423.5 million. Excluding the $267.3 million impairment charge (described in more detail in Business Segment Results of Operations - EQT Production) and $26.2 million increase in depreciation and depletion, operating expenses increased $130.0 million. This increase was primarily attributable to higher transportation and processing expenses and higher SG&A costs consistent with the growth in the production and midstream businesses.
On May 7, 2014, a wholly owned subsidiary of the Company, EQT Gathering contributed a high-pressure gathering system to EQM Gathering, a wholly owned subsidiary of the Partnership, in exchange for $1.18 billion (the Jupiter Transaction). EQM Gathering is consolidated by the Company as it is still controlled by the Company.
On May 7, 2014, the Partnership completed an underwritten public offering of 12,362,500 common units, which included the full exercise of the underwriters’ overallotment option, representing Partnership limited partner interests. The Partnership received net proceeds of approximately $902.5 million from the offering, after deducting the underwriters’ discount and offering expenses of approximately $34.0 million. As of December 31, 2014, the Company held a 2% general partner interest, all incentive
33
distribution rights and a 34.4% limited partner interest in the Partnership. The Company’s limited partner interest in the Partnership consists of 3,959,952 common units and 17,339,718 subordinated units.
In June 2014, the Company exchanged certain assets with Range. The Company received approximately 73,000 net acres and approximately 900 producing wells, most of which are vertical wells, in the Permian Basin of Texas. In exchange, Range received approximately 138,000 net acres in the Company’s Nora field of Virginia, the Company’s working interest in approximately 2,000 producing vertical wells in the Nora field, the Company’s remaining 50% ownership interest in Nora LLC, which owns the supporting gathering system in the Nora field, and $167.3 million in cash.
In August 2014, the Partnership issued 4.00% Senior Notes (4.00% Senior Notes) due August 1, 2024 in the aggregate principal amount of $500.0 million. Net proceeds of the offering of $492.3 million were used to repay the outstanding borrowings under the Partnership’s credit facility and for general partnership purposes.
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 gain on sale of certain energy marketing contracts by EQT Energy in December 2013 and lower interest expense. These factors were partially offset by higher DD&A expense, higher income tax expense, higher 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 in 2013 compared to 2012 primarily as a result of increased production from the 2013 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 realized price to EQT Production for sales volumes was $3.15 per Mcfe in 2013 compared to $3.00 per Mcfe in 2012. 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 in 2013 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, Sunrise Pipeline, LLC (Sunrise), a subsidiary of the Company, merged with and into Equitrans, a subsidiary of the Partnership, with Equitrans continuing as the surviving company (the Sunrise Merger). Equitrans 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 retained 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.
On December 17, 2013, the Company and its wholly owned subsidiary, Distribution Holdco, LLC, completed the disposition of their ownership interests in Equitable Gas and Homeworks to PNG Companies LLC (the Equitable Gas Transaction). As consideration for the transaction, the Company received total cash proceeds of $748.0 million, select midstream assets, including the AVC facilities, with a fair value of $140.9 million and other contractual assets with a fair value of $32.5 million.
On July 2, 2012, the Partnership completed its IPO of 14,375,000 common units representing limited partner interests in the Partnership, which represented 40.6% of the Partnership’s outstanding equity. The Company retained a 59.4% equity interest in the Partnership, including 2,964,718 common units, 17,339,718 subordinated units and a 2% general partner interest.
34
See “Other Income Statement Items” for a discussion of other income, interest expense, income taxes, income from discontinued operations and net income attributable to noncontrolling interests, and “Investing Activities” in “Capital Resources and Liquidity” for a discussion of capital expenditures.
Consolidated Operational Data
Revenues earned by the Company at the wellhead from the sale of natural gas, NGLs and oil are split between EQT Production and EQT Midstream. The split is reflected in the calculation of EQT Production’s average sales price. The following operational information presents detailed gross liquid and natural gas operational information as well as midstream deductions to assist in the understanding of the Company’s consolidated operations.
Non-GAAP Financial Measures
The operational information in the table below presents an average realized price ($/Mcfe) to EQT Production and EQT Corporation, which is based on EQT Production adjusted net operating revenues, a non-GAAP supplemental financial measure. EQT Production adjusted net operating revenues are presented because it is an important measure used by the Company’s management to evaluate period-to-period comparisons of earnings. EQT Production adjusted net operating revenues should not be considered as an alternative to EQT Corporation operating revenues as reported in the Statements of Consolidated Income, the most directly comparable GAAP financial measure. See “Reconciliation of Non-GAAP Measures” for a reconciliation of EQT Production adjusted net operating revenues to EQT Corporation operating revenues, as derived from the Statements of Consolidated Income.
35
EQT Corporation
Price Reconciliation
Years Ended December 31, | |||||||||||
in thousands (unless noted) | 2014 | 2013 | 2012 | ||||||||
LIQUIDS | |||||||||||
NGLs: | |||||||||||
Sales volume (MMcfe) (a) | 40,587 | 27,860 | 18,981 | ||||||||
Sales volume (Mbbls) | 6,764 | 4,643 | 3,163 | ||||||||
Gross price ($/bbl) | $ | 41.94 | $ | 45.58 | $ | 49.29 | |||||
Gross NGL sales | $ | 283,728 | $ | 211,626 | $ | 155,926 | |||||
Third-party processing | (64,313 | ) | (40,754 | ) | (26,751 | ) | |||||
Net NGL sales | $ | 219,415 | $ | 170,872 | $ | 129,175 | |||||
Oil: | |||||||||||
Sales volume (MMcfe) (a) | 2,693 | 1,620 | 1,587 | ||||||||
Sales volume (Mbbls) | 449 | 270 | 264 | ||||||||
Net price ($/bbl) | $ | 78.51 | $ | 85.82 | $ | 83.95 | |||||
Net oil sales | $ | 35,232 | $ | 23,171 | $ | 22,161 | |||||
Net liquids sales | $ | 254,647 | $ | 194,043 | $ | 151,336 | |||||
NATURAL GAS | |||||||||||
Sales volume (MMcf) | 432,980 | 348,693 | 243,886 | ||||||||
NYMEX price ($/MMBtu) (b) | $ | 4.38 | $ | 3.67 | $ | 2.83 | |||||
Btu uplift | $ | 0.38 | $ | 0.30 | $ | 0.26 | |||||
Gross natural gas price ($/Mcf) | $ | 4.76 | $ | 3.97 | $ | 3.09 | |||||
Basis ($/Mcf) | (1.07 | ) | (0.16 | ) | (0.03 | ) | |||||
Recoveries ($/Mcf) (c) | 0.82 | 0.37 | 0.52 | ||||||||
Cash settled basis swaps (not designated as hedges) ($/Mcf) | $ | 0.06 | $ | — | $ | — | |||||
Average differential ($/Mcf) | $ | (0.19 | ) | $ | 0.21 | $ | 0.49 | ||||
Average adjusted price - unhedged ($/Mcf) | $ | 4.57 | $ | 4.18 | $ | 3.58 | |||||
Cash settled derivatives (cash flow hedges) ($/Mcf) | (0.06 | ) | 0.42 | 1.22 | |||||||
Cash settled derivatives (not designated as hedges) ($/Mcf) | 0.02 | — | — | ||||||||
Average adjusted price, including cash settled derivatives ($/Mcf) | $ | 4.53 | $ | 4.60 | $ | 4.80 | |||||
Net natural gas sales, including cash settled derivatives | $ | 1,962,667 | $ | 1,603,891 | $ | 1,171,435 | |||||
TOTAL PRODUCTION | |||||||||||
Total net natural gas & liquids sales, including cash settled derivatives | $ | 2,217,314 | $ | 1,797,934 | $ | 1,322,771 | |||||
Total sales volume (MMcfe) | 476,260 | 378,173 | 264,454 | ||||||||
Net natural gas & liquids price, including cash settled derivatives ($/Mcfe) | $ | 4.66 | $ | 4.75 | $ | 5.00 | |||||
Midstream Revenue Deductions ($/Mcfe) | |||||||||||
Gathering to EQT Midstream | $ | (0.73 | ) | $ | (0.82 | ) | $ | (1.00 | ) | ||
Transmission to EQT Midstream | (0.20 | ) | (0.23 | ) | (0.19 | ) | |||||
Third-party gathering and transmission costs | (0.50 | ) | (0.55 | ) | (0.81 | ) | |||||
Total midstream revenue deductions | $ | (1.43 | ) | $ | (1.60 | ) | $ | (2.00 | ) | ||
Average realized price to EQT Production ($/Mcfe) | $ | 3.23 | $ | 3.15 | $ | 3.00 | |||||
Gathering and transmission to EQT Midstream ($/Mcfe) | $ | 0.93 | $ | 1.05 | $ | 1.19 | |||||
Average realized price to EQT Corporation ($/Mcfe) | $ | 4.16 | $ | 4.20 | $ | 4.19 | |||||
36
(a) NGLs and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods.
(b) The Company’s volume weighted NYMEX natural gas price (actual average NYMEX natural gas price ($/MMBtu) was $4.41, $3.65 and $2.79 for the years ended December 31, 2014, 2013 and 2012, respectively).
(c) Recoveries represent differences in natural gas prices between the Appalachian Basin and the sales points of other markets reached by utilizing transportation capacity, differences in natural gas prices between Appalachian Basin and fixed price sales contracts, term sales with fixed differentials to NYMEX and other marketing activity, including capacity releases. Recoveries includes approximately $0.19, $0.23 and $0.41 per Mcf for the years ended December 31, 2014, 2013 and 2012, respectively, for the sale of unused capacity.
Reconciliation of Non-GAAP Measures
The tables below reconcile EQT Production adjusted net operating revenues, a non-GAAP supplemental financial measure, to EQT Corporation operating revenues as reported in the Statements of Consolidated Income, its most directly comparable financial measure calculated in accordance with GAAP.
The Company reports gain (loss) for hedging ineffectiveness and gain (loss) on derivatives not designated as hedges within operating revenues in the Statements of Consolidated Income.
The Company’s management reviews and reports the EQT Production segment results with third-party transportation and processing costs reflected as a deduction from operating revenues. Third-party costs incurred to gather, process and transport gas produced by EQT Production to market sales points are recorded as a portion of transportation and processing costs in the Statements of Consolidated Income. Some transportation costs incurred by the Company are marketed for resale and are not incurred to transport gas produced by EQT Production. These transportation costs are reflected as a deduction from operating revenues in the Statements of Consolidated Income.
Calculation of EQT Production adjusted net operating revenues | Years Ended December 31, | ||||||||||
$ in thousands (unless noted) | 2014 | 2013 | 2012 | ||||||||
EQT Production total net operating revenues, as reported on segment page | $ | 1,612,730 | $ | 1,168,657 | $ | 793,773 | |||||
(Deduct) add back: | |||||||||||
(Gain) loss for hedging ineffectiveness | (24,774 | ) | 21,335 | 75 | |||||||
(Gain) loss on derivatives not designated as hedges | (83,760 | ) | 301 | 317 | |||||||
Net cash settlements received (paid) on derivatives not designated as hedges | 36,453 | 728 | (317 | ) | |||||||
EQT Production adjusted net operating revenues, a non-GAAP measure | $ | 1,540,649 | $ | 1,191,021 | $ | 793,848 | |||||
Total sales volumes (MMcfe) | 476,260 | 378,173 | 264,454 | ||||||||
Average realized price to EQT Production ($/Mcfe) | $ | 3.23 | $ | 3.15 | $ | 3.00 | |||||
Add: | |||||||||||
Gathering and Transmission to EQT Midstream ($/Mcfe) | $ | 0.93 | $ | 1.05 | $ | 1.19 | |||||
Average realized price to EQT Corporation ($/Mcfe) | $ | 4.16 | $ | 4.20 | $ | 4.19 | |||||
EQT Production total net operating revenues, as reported on segment page | $ | 1,612,730 | $ | 1,168,657 | $ | 793,773 | |||||
EQT Midstream total operating revenues, as reported on segment page | 699,083 | 614,042 | 505,498 | ||||||||
Third-party transportation and processing costs | 200,562 | 142,281 | 126,783 | ||||||||
Less: intersegment revenues, net | (42,665 | ) | (62,969 | ) | (48,832 | ) | |||||
EQT Corporation operating revenues, as reported in accordance with GAAP | $ | 2,469,710 | $ | 1,862,011 | $ | 1,377,222 | |||||
37
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 $36.9 million, $45.4 million and $35.6 million were not allocated to the operating segments for the years ended December 31, 2014, 2013 and 2012, respectively. Unallocated expenses consist primarily of incentive compensation, administrative costs and for 2013 and 2012, corporate overhead charges previously allocated to the Company’s Distribution segment that were reclassified to headquarters as part of the recast of those periods 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 with third-party transportation and processing costs reflected as a deduction from operating revenues as management believes this presentation provides a more useful view of average net sales price and is consistent with industry practices. Third-party costs incurred to gather, process and transport gas produced by EQT Production to market sales points are recorded as a portion of transportation and processing costs in the Statements of Consolidated Income. Purchased gas costs at EQT Midstream include natural gas purchases, including natural gas purchases from affiliates, purchased gas costs adjustments and other gas supply expenses. These purchased gas costs are primarily with affiliates and are eliminated in consolidation. Consistent with the consolidated results, energy trading contracts recorded within storage, marketing and other are reported net within operating revenues, regardless of whether the contracts are physically or financially settled. 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.
38
EQT Production
Results of Operations
Years Ended December 31, | ||||||||||||||||||
2014 | 2013 | % change 2014 - 2013 | 2012 | % change 2013 - 2012 | ||||||||||||||
OPERATIONAL DATA | ||||||||||||||||||
Sales volume detail (MMcfe): | ||||||||||||||||||
Horizontal Marcellus Play (a) | 378,195 | 275,029 | 37.5 | 151,430 | 81.6 | |||||||||||||
Horizontal Huron Play | 33,803 | 35,255 | (4.1 | ) | 41,985 | (16.0 | ) | |||||||||||
Other | 64,262 | 67,889 | (5.3 | ) | 71,039 | (4.4 | ) | |||||||||||
Total production sales volumes (b) | 476,260 | 378,173 | 25.9 | 264,454 | 43.0 | |||||||||||||
Average daily sales volumes (MMcfe/d) | 1,305 | 1,036 | 26.0 | 723 | 43.3 | |||||||||||||
Average realized price to EQT Production ($/Mcfe) | $ | 3.23 | $ | 3.15 | 2.5 | $ | 3.00 | 5.0 | ||||||||||
Lease operating expenses (LOE), excluding production taxes ($/Mcfe) | $ | 0.14 | $ | 0.15 | (6.7 | ) | $ | 0.17 | (11.8 | ) | ||||||||
Production taxes ($/Mcfe) | $ | 0.14 | $ | 0.13 | 7.7 | $ | 0.16 | (18.8 | ) | |||||||||
Production depletion ($/Mcfe) | $ | 1.22 | $ | 1.50 | (18.7 | ) | $ | 1.52 | (1.3 | ) | ||||||||
DD&A (thousands): | ||||||||||||||||||
Production depletion | $ | 582,624 | $ | 568,990 | 2.4 | $ | 401,456 | 41.7 | ||||||||||
Other DD&A | 10,231 | 9,651 | 6.0 | 8,172 | 18.1 | |||||||||||||
Total DD&A (thousands) | $ | 592,855 | $ | 578,641 | 2.5 | $ | 409,628 | 41.3 | ||||||||||
Capital expenditures (thousands) (c) | $ | 2,441,486 | $ | 1,423,185 | 71.6 | $ | 991,775 | 43.5 | ||||||||||
FINANCIAL DATA (thousands) | ||||||||||||||||||
Revenues: | ||||||||||||||||||
Production sales | $ | 1,504,196 | $ | 1,190,293 | 26.4 | $ | 794,165 | 49.9 | ||||||||||
Gain (loss) for hedging ineffectiveness | 24,774 | (21,335 | ) | (216.1 | ) | (75 | ) | 28,346.7 | ||||||||||
Gain (loss) on derivatives not designated as hedges | 83,760 | (301 | ) | (27,927.2 | ) | (317 | ) | (5.0 | ) | |||||||||
Total net operating revenues | $ | 1,612,730 | $ | 1,168,657 | 38.0 | $ | 793,773 | 47.2 | ||||||||||
Operating expenses: | ||||||||||||||||||
LOE, excluding production taxes | 65,917 | 57,110 | 15.4 | 46,212 | 23.6 | |||||||||||||
Production taxes | 67,571 | 50,981 | 32.5 | 49,943 | 2.1 | |||||||||||||
Exploration expense | 21,665 | 18,483 | 17.2 | 10,370 | 78.2 | |||||||||||||
SG&A | 118,816 | 92,197 | 28.9 | 89,707 | 2.8 | |||||||||||||
DD&A | 592,855 | 578,641 | 2.5 | 409,628 | 41.3 | |||||||||||||
Impairment of long-lived assets | 267,339 | — | 100.0 | — | — | |||||||||||||
Total operating expenses | 1,134,163 | 797,412 | 42.2 | 605,860 | 31.6 | |||||||||||||
Gain on sale / exchange of assets | 27,383 | — | 100.0 | — | — | |||||||||||||
Operating income | $ | 505,950 | $ | 371,245 | 36.3 | $ | 187,913 | 97.6 | ||||||||||
39
(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.
(c) Includes $167.3 million of cash capital expenditures and $349.2 million of non-cash capital expenditures for the exchange of assets with Range during the year ended December 31, 2014; $114.2 million of cash 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 certain labor overhead costs including a portion of non-cash stock-based compensation expense and non-cash capital expense accruals that were not paid at the applicable year-end.
Year Ended December 31, 2014 vs. December 31, 2013
EQT Production’s operating income totaled $506.0 million for 2014 compared to $371.2 million for 2013. The $134.8 million increase in operating income was primarily due to increased sales of produced natural gas and NGLs and a higher average realized price partially offset by an increase in operating expenses, which includes $267.3 million of noncash impairment charges. Impairment charges consist of $105.2 million associated with proved properties in the Permian Basin of Texas related to the 2014 decline in commodity prices. Impairment charges also include $86.6 million associated with undeveloped properties and $75.5 million associated with proved properties in the Utica Shale of Ohio as a result of insufficient recovery of hydrocarbons to support continued development along with the decline in commodity prices.
Total net operating revenues were $1,612.7 million for 2014 compared to $1,168.7 million for 2013. The $444.0 million increase in total net operating revenues was primarily due to a 26% increase in production sales volumes, a favorable gain on derivatives not designated as hedges, a favorable change in hedging ineffectiveness and a 3% increase in the average realized price to EQT Production. The increase in production sales volumes was the result of increased production from the 2014 and 2013 drilling programs, primarily in the Marcellus play. This increase was partially offset by the normal production decline in the Company’s producing wells.
Total net operating revenues for the year ended December 31, 2014 included a $24.8 million gain for hedging ineffectiveness of financial hedges compared to a $21.3 million loss for ineffectiveness of financial hedges for the year ended December 31, 2013. The year ended December 31, 2014 also included $83.8 million of derivative gains for derivative instruments not designated as hedging instruments compared to $0.3 million of derivative losses for the year ended December 31, 2013. The gains for the year ended December 31, 2014 relate to favorable changes in the fair market value of basis swaps and NYMEX collars that were not designated as hedging instruments, due to decreased NYMEX and basis prices as of December 31, 2014. The $83.8 million of derivative gains for derivative instruments not designated as hedging instruments for the year ended December 31, 2014 included $36.5 million of cash settlements received, which is included in the average price discussion above.
The $0.08 per Mcfe increase in the average realized price to EQT Production was the net result of an increase in the average NYMEX natural gas price net of cash settled derivatives combined with a per unit decrease in midstream revenue deductions, partly offset by a lower average natural gas differential of $0.40 per Mcf. The average differential includes lower Appalachian Basin basis of $0.91 per Mcf, favorable recoveries of $0.45 per Mcf and favorable settlements of basis swaps of $0.06 per Mcf. Recoveries represent differences in natural gas prices between the Appalachian Basin and the sales points of other markets reached by utilizing transportation capacity, differences in natural gas prices between Appalachian Basin and fixed price sales contracts, term sales with fixed differentials to NYMEX and other marketing activity, including capacity releases. For the year ended December 31, 2014, EQT Production recognized higher recoveries compared to 2013 primarily by using its contracted transportation capacity to sell gas in higher priced markets, particularly during the winter months when market prices in the United States Northeast region were significantly higher than the Appalachian Basin prices. Much of these higher revenues resulted from sales off of the Company’s Texas Eastern Transmission (TETCO) and Tennessee Gas Pipeline capacity, including additional TETCO capacity that came online in 2014. Effective February 2014, the Company acquired new TETCO capacity of 245,000 MMBtu per day that enables the Company to reach markets in eastern Pennsylvania. Effective November 2014, additional TETCO capacity of 300,000 MMBtu per day came online that enables the Company to reach markets in New Jersey as well as markets along the Gulf coast. Additionally, the Company executed natural gas sales with fixed differentials to NYMEX for the 2014 summer term during the fourth quarter of 2013 and first quarter of 2014 when market prices were favorable compared to actual Appalachian Basin basis during the summer of 2014.
Operating expenses totaled $1,134.2 million for 2014 compared to $797.4 million for 2013. The increase in operating expenses was the result of impairments of long-lived assets of $267.3 million, as previously mentioned, and increases in SG&A, production taxes, DD&A, LOE and exploration expenses. SG&A expense increased in 2014 primarily as a result of higher personnel costs of $12.4 million, including incentive compensation expenses, higher litigation and environmental reserves of $6.2 million,
40
and an increase in professional services of $4.9 million. Production taxes increased due to an $11.6 million increase in severance taxes and property taxes as a result of higher market sales prices and higher production sales volumes in certain jurisdictions subject to these taxes. Production taxes also increased due to a $5.1 million increase in the Pennsylvania impact fee, primarily as a result of an increase in the number of wells drilled in Pennsylvania. Depletion expense increased as a result of higher production sales volumes in 2014 partially offset by a lower overall depletion rate. The increase in LOE was mainly a result of increased Marcellus activity in 2014, including a $2.8 million increase in salt water disposal expenses and a $2.7 million increase in labor expenses, along with expenses related to the exchange of properties with Range. Exploration expense increased in 2014 primarily as a result of increased geophysical activity compared to the prior year.
In connection with an asset exchange with Range during the second quarter of 2014, the Company received acreage and producing wells in the Permian Basin of Texas in exchange for acreage, producing wells, the Company’s 50% ownership interest in a supporting gathering system in the Nora fields of Virginia and cash of $167.3 million. In conjunction with the transaction, EQT Production recognized a pre-tax gain of $27.4 million in 2014, which is included in gain on sale / exchange of assets in the Statements of Consolidated Income. The $27.4 million pre-tax gain included a $28.0 million pre-tax gain related to the de-designation of certain derivative instruments that were previously designated as cash flow hedges because it was probable that the forecasted transactions would not occur. Any subsequent changes in fair value of these derivative instruments will be recognized within the results of operations for EQT Production.
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 realized price partially offset by an increase in operating expenses.
Total net operating revenues were $1,168.7 million for 2013 compared to $793.8 million for 2012. The $374.9 million increase in total net operating revenues was primarily due to a 43% increase in production sales volumes and a 5% increase in the average realized price to EQT Production. The increase in production sales volumes was the result of increased production from the 2012 and 2011 drilling programs, primarily in the Marcellus play. This increase was partially offset by the normal production decline in the Company’s producing wells.
The $0.15 per Mcfe increase in the average realized price to EQT Production was the net result of a per unit decrease in midstream revenue deductions and an increase in the average NYMEX natural gas price net of cash settled derivatives, partly offset by a lower average natural gas differential of $0.28 per Mcf and lower NGL prices. The average differential includes lower Appalachian Basin basis of $0.13 per Mcf and lower recoveries of $0.15 per Mcf. The lower recoveries primarily related to decreases in the sales of unused capacity.
Total net operating revenues for the year ended December 31, 2013 included a $21.3 million loss for hedging ineffectiveness of financial hedges compared to a $0.1 million loss for ineffectiveness of financial hedges in the year ended December 31, 2012.
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 $6.7 million represented a retroactive fee for pre-2012 Marcellus wells.
41
EQT Midstream
Results of Operations
Years Ended December 31, | ||||||||||||||||||
2014 | 2013 | % change 2014 - 2013 | 2012 | % change 2013 - 2012 | ||||||||||||||
OPERATIONAL DATA | ||||||||||||||||||
Gathered volumes (BBtu) | 590,492 | 466,405 | 26.6 | 335,407 | 39.1 | |||||||||||||
Average gathering fee ($/MMBtu) | $ | 0.67 | $ | 0.75 | (10.7 | ) | $ | 0.90 | (16.7 | ) | ||||||||
Gathering and compression expense ($/MMBtu) | $ | 0.14 | $ | 0.18 | (22.2 | ) | $ | 0.24 | (25.0 | ) | ||||||||
Transmission pipeline throughput (BBtu) | 654,785 | 418,360 | 56.5 | 221,944 | 88.5 | |||||||||||||
Net operating revenues (thousands): | ||||||||||||||||||
Gathering | $ | 397,878 | $ | 351,410 | 13.2 | $ | 302,255 | 16.3 | ||||||||||
Transmission | 226,497 | 160,621 | 41.0 | 104,501 | 53.7 | |||||||||||||
Storage, marketing and other | 30,729 | 33,555 | (8.4 | ) | 42,693 | (21.4 | ) | |||||||||||
Total net operating revenues | $ | 655,104 | $ | 545,586 | 20.1 | $ | 449,449 | 21.4 | ||||||||||