[X]
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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[ ]
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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PENNSYLVANIA
(State or other jurisdiction of incorporation or organization)
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25-0464690
(IRS Employer Identification No.)
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625 Liberty Avenue, Suite 1700
Pittsburgh, Pennsylvania
(Address of principal executive offices)
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15222
(Zip Code)
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Title of each class
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Name of each exchange on which registered
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Common Stock, no par value
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New York Stock Exchange
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Large accelerated filer X
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Accelerated filer ___
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Non-accelerated filer ___ (Do not check if a smaller reporting company)
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Smaller reporting company ___
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Emerging growth company ___
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Glossary of Commonly Used Terms, Abbreviations and Measurements
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Cautionary Statements
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PART I
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Item 1
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Business
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Item 1A
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Risk Factors
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Item 1B
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Unresolved Staff Comments
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Item 2
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Properties
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Item 3
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Legal Proceedings
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Item 4
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Mine Safety Disclosures
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Executive Officers of the Registrant
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PART II
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Item 5
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Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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Item 6
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Selected Financial Data
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Item 7
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
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Item 7A
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Quantitative and Qualitative Disclosures About Market Risk
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Item 8
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Financial Statements and Supplementary Data
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Item 9
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Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
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Item 9A
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Controls and Procedures
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Item 9B
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Other Information
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PART III
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Item 10
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Directors, Executive Officers and Corporate Governance
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Item 11
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Executive Compensation
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Item 12
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Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
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Item 13
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Certain Relationships and Related Transactions, and Director Independence
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Item 14
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Principal Accounting Fees and Services
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PART IV
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Item 15
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Exhibits and Financial Statement Schedules
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Signatures
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•
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EQT achieved record annual production sales volumes, including a
17%
increase in total sales volumes and a
17%
increase in Marcellus sales volumes. Average realized price increased
23%
to
$3.04
per Mcfe in
2017
from
$2.47
per Mcfe in
2016
.
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•
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On February 1, 2017, the Company acquired approximately
14,000
net Marcellus acres located in Marion, Monongalia and Wetzel Counties, West Virginia from a third party for $132.9 million.
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•
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On February 27, 2017, the Company acquired approximately
85,000
net Marcellus acres, including drilling rights on approximately
44,000
net Utica acres, from Stone Energy Corporation for $523.5 million. The acquired acres are primarily located in Wetzel, Marshall, Tyler and Marion Counties, West Virginia. The acquired assets also included
174
operated Marcellus wells and
20
miles of gathering pipeline.
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•
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On June 30, 2017, the Company acquired approximately
11,000
net Marcellus acres, and the associated Utica drilling rights, from a third party for $83.7 million. The acquired acres are primarily located in Allegheny, Washington and Westmoreland Counties, Pennsylvania.
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•
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On October 4, 2017, the Company completed the public offering of $3.0 billion principal amount of notes. The Company used the net proceeds from the sale of the notes to fund a portion of the cash consideration for the Rice Merger, to pay expenses related to the Rice Merger and related transactions, to redeem $700 million aggregate principal amount of Company indebtedness due in 2018 and for other general corporate purposes.
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•
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On October 13, 2017, the FERC issued the Certificate of Public Convenience and Necessity for Mountain Valley Pipeline, LLC (MVP Joint Venture).
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(Bcfe)
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Marcellus
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Upper
Devonian
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Ohio Utica
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Other
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Total
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|||||
Proved Developed
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8,092
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683
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757
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1,767
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11,299
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Proved Undeveloped
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8,805
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293
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1,049
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—
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10,147
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Total Proved Reserves
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16,897
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976
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1,806
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1,767
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21,446
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Years Ended December 31,
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2017
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2016
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2015
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||||||
Gross wells spud:
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Horizontal Marcellus*
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193
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130
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157
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Ohio Utica
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7
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—
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—
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Other
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1
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5
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4
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|||
Total
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201
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135
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161
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||||||
Capital expenditures for well development (in millions):
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||||||||||||
Horizontal Marcellus*
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$
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1,295
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$
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686
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$
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1,527
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Ohio Utica
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31
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—
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—
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|||
Other
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59
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97
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143
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Total
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$
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1,385
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$
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783
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$
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1,670
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•
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approximately 152 miles of high pressure gathering lines and 4 compressor stations in Belmont and Monroe County, Ohio as of December 31, 2017;
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•
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Strike Force Midstream Holdings LLC's (Strike Force Holdings) 75% membership interest in Strike Force Midstream LLC (Strike Force Midstream), which owns approximately 67 miles of high pressure gathering lines and 2 compressor stations in Belmont and Monroe County, Ohio, as of December 31, 2017; and
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•
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approximately 6,600 miles of gathering lines that primarily support the Company's and third party production operations in non-core areas of declining production.
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•
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Mountain Valley Pipeline (MVP)
. The MVP Joint Venture is a joint venture with affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc., WGL Holdings, Inc. and RGC Resources, Inc. EQM is the operator of the MVP and owned a 45.5% interest in the MVP Joint Venture as of December 31, 2017. The 42 inch diameter MVP has a targeted capacity of 2.0 Bcf per day and is estimated to span 300 miles extending from EQM Transmission's existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia providing access to the growing Southeast demand markets. As currently designed, the MVP is estimated to cost a total of approximately $3.5 billion, excluding AFUDC, with EQM funding its proportionate share through capital contributions made to the joint venture. In 2018, EQM expects to provide capital contributions of $1.0 billion to $1.2 billion to the MVP Joint Venture. The MVP Joint Venture has secured a total of 2.0 Bcf per day of firm capacity commitments at 20-year terms, including a 1.29 Bcf per day firm capacity commitment by EQT, and is currently in negotiation with additional shippers who have expressed interest in the MVP project. On October 13, 2017, the FERC issued the Certificate of Public Convenience and Necessity for the project. In January 2018, the MVP Joint Venture received multiple limited notices to proceed from the FERC to begin construction
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•
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Transmission Expansion
. In 2018, EQM Transmission estimates capital expenditures of approximately $100 million for other transmission expansion projects, primarily attributable to the Equitrans Expansion project. The Equitrans Expansion project is designed to provide north-to-south capacity on the mainline Equitrans system for deliveries to the MVP.
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2017
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2016
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2015
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Average sales price per Mcfe sold (excluding cash settled derivatives)
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$
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2.98
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$
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1.99
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$
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2.38
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Average sales price per Mcfe sold (including cash settled derivatives)
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$
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3.04
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$
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2.47
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$
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3.09
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For the Years Ended December 31,
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2017
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2016
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2015
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(Thousands)
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||||||||||
Operating Revenues:
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Sales of natural gas, oil and NGLs (a)
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$
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2,651,318
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$
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1,594,997
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$
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1,690,360
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Pipeline, water and net marketing services (b)
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336,676
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262,342
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263,640
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Gain (loss) on derivatives not designated as hedges (a)
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390,021
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(248,991
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)
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385,762
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Total operating revenues
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$
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3,378,015
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$
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1,608,348
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$
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2,339,762
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(a)
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Reported in the EQT Production segment.
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(b)
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Reported in the EQM Gathering, EQM Transmission, RMP Gathering and RMP Water segments, with the exception of
$65.0 million
,
$41.0 million
and
$55.5 million
for the years ended December 31,
2017
,
2016
and
2015
, respectively, which are reported within the EQT Production segment.
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For the Years Ended December 31,
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2017
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2016
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2015
|
||||||
Natural Gas:
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Average sales price (excluding cash settled derivatives) ($/Mcf)
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$
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2.82
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$
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1.88
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$
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2.28
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Average sales price (including cash settled derivatives) ($/Mcf)
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$
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2.89
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$
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2.41
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$
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3.06
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NGLs (excluding ethane):
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||||
Average sales price (excluding cash settled derivatives) ($/Bbl)
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$
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31.59
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$
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19.43
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$
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18.84
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Average sales price (including cash settled derivatives) ($/Bbl)
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$
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30.90
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$
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19.43
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$
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18.84
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Ethane:
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||||||
Average sales price ($/Bbl) (a)
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$
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6.32
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$
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5.08
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$
|
—
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Crude Oil:
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||||
Average sales price ($/Bbl)
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$
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40.70
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$
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34.73
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$
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38.70
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Natural Gas
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Oil
|
Total productive wells at December 31, 2017:
|
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Total gross productive wells
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14,498
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108
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Total net productive wells
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13,596
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104
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Total in-process wells at December 31, 2017:
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0
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Total gross in-process wells
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413
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—
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Total net in-process wells
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368
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—
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Natural Gas
(MMcf)
|
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Oil and NGLs
(Bbls)
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Developed
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10,152,543
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190,901
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Undeveloped
|
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9,677,693
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|
78,337
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Total proved reserves
|
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19,830,236
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269,238
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For the Years Ended December 31,
|
|||||||
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2017
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2016
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2015
|
|||
Exploratory wells:
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Productive
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—
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—
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1.0
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Dry
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1.0
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—
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1.0
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Development wells:
|
|
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Productive
|
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149.2
|
|
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140.9
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234.5
|
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Dry
|
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4.9
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|
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15.0
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3.0
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Pennsylvania
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West
Virginia
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Kentucky
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Ohio
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Other (b)
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Total
|
||||||
Natural gas, oil and NGLs production (MMcfe) – 2017 (a) (c)
|
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456,614
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|
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352,481
|
|
|
60,423
|
|
|
24,426
|
|
|
13,948
|
|
|
907,892
|
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Natural gas, oil and NGLs production (MMcfe) – 2016 (a)
|
|
426,524
|
|
|
272,529
|
|
|
61,267
|
|
|
541
|
|
|
15,502
|
|
|
776,363
|
|
Natural gas, oil and NGLs production (MMcfe) – 2015 (a)
|
|
327,616
|
|
|
208,376
|
|
|
65,726
|
|
|
859
|
|
|
16,109
|
|
|
618,686
|
|
|
|
|
|
|
|
|
|
|
|
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|
||||||
Natural gas, oil and NGLs sales (MMcfe) – 2017 (c)
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456,600
|
|
|
343,199
|
|
|
51,313
|
|
|
24,113
|
|
|
12,295
|
|
|
887,520
|
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Natural gas, oil and NGLs sales (MMcfe) – 2016
|
|
429,011
|
|
|
264,452
|
|
|
51,200
|
|
|
536
|
|
|
13,768
|
|
|
758,967
|
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Natural gas, oil and NGLs sales (MMcfe) – 2015
|
|
329,626
|
|
|
200,121
|
|
|
57,825
|
|
|
758
|
|
|
14,752
|
|
|
603,082
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
||||||
Average net revenue interest of proved reserves (%)
|
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79.7
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%
|
|
83.0
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%
|
|
92.7
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%
|
|
46.6
|
%
|
|
79.8
|
%
|
|
76.4
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%
|
|
|
|
|
|
|
|
|
|
|
|
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|
||||||
Total gross productive wells
|
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1,654
|
|
|
5,391
|
|
|
5,723
|
|
|
178
|
|
|
1,660
|
|
|
14,606
|
|
Total net productive wells
|
|
1,595
|
|
|
5,125
|
|
|
5,412
|
|
|
78
|
|
|
1,490
|
|
|
13,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Total gross productive acreage
|
|
189,302
|
|
|
329,357
|
|
|
438,598
|
|
|
40,878
|
|
|
128,471
|
|
|
1,126,606
|
|
Total gross undeveloped acreage
|
|
502,534
|
|
|
1,069,017
|
|
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1,057,288
|
|
|
49,207
|
|
|
194,422
|
|
|
2,872,468
|
|
Total gross acreage
|
|
691,836
|
|
|
1,398,374
|
|
|
1,495,886
|
|
|
90,085
|
|
|
322,893
|
|
|
3,999,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Total net productive acreage
|
|
180,714
|
|
|
321,110
|
|
|
432,007
|
|
|
22,761
|
|
|
102,241
|
|
|
1,058,833
|
|
Total net undeveloped acreage
|
|
486,232
|
|
|
898,592
|
|
|
985,424
|
|
|
49,258
|
|
|
167,080
|
|
|
2,586,586
|
|
Total net acreage
|
|
666,946
|
|
|
1,219,702
|
|
|
1,417,431
|
|
|
72,019
|
|
|
269,321
|
|
|
3,645,419
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
(Amounts in Bcfe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed producing reserves
|
|
5,569
|
|
|
3,449
|
|
|
1,226
|
|
|
700
|
|
|
162
|
|
|
11,106
|
|
Proved developed non-producing reserves
|
|
122
|
|
|
13
|
|
|
—
|
|
|
58
|
|
|
—
|
|
|
193
|
|
Proved undeveloped reserves
|
|
7,786
|
|
|
1,313
|
|
|
—
|
|
|
1,048
|
|
|
—
|
|
|
10,147
|
|
Proved developed and undeveloped reserves
|
|
13,477
|
|
|
4,775
|
|
|
1,226
|
|
|
1,806
|
|
|
162
|
|
|
21,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Gross proved undeveloped drilling locations
|
|
574
|
|
|
126
|
|
|
—
|
|
|
107
|
|
|
—
|
|
|
807
|
|
Net proved undeveloped drilling locations
|
|
539
|
|
|
124
|
|
|
—
|
|
|
70
|
|
|
—
|
|
|
733
|
|
(c)
|
For the year ended December 31, 2017, the natural gas, oil and NGLs production volumes and sales volumes includes volumes from the production operations acquired in the Rice Merger for the period of
November 13, 2017
through December 31, 2017.
|
For the Year Ended December 31,
|
|
Natural Gas (Bcf)
|
2018
|
|
1,173
|
2019
|
|
671
|
2020
|
|
459
|
2021
|
|
335
|
2022
|
|
259
|
Name and Age
|
|
Current Title (Year Initially
Elected an Executive Officer)
|
|
Business Experience
|
|
|
|
|
|
Jeremiah J. Ashcroft III (45)
|
|
Senior Vice President, EQT Corporation and President, Midstream (2017)
|
|
Elected to present position August 2017. Mr. Ashcroft is also a Director and Senior Vice President and Chief Operating Officer of each of EQT Midstream Services, LLC, the general partner of EQM, since August 2017, and Rice Midstream Management LLC, the general partner of RMP, since November 2017. Prior to joining EQT Corporation, Mr. Ashcroft served as President and Chief Executive Officer of Gulf Oil L.P., from September 2015 to June 2017; Executive Vice President and Chief Operating Officer of JP Energy Partners, LP, from May 2014 to September 2015; and President of Buckeye Partners, L.P.’s Natural Gas Storage, Development & Logistics and Energy Services business units, from January 2012 to May 2014.
|
|
|
|
|
|
Lewis B. Gardner (60)
|
|
General Counsel and Vice President, External Affairs (2008)
|
|
Elected to present position March 2008. Mr. Gardner is also a Director of each of EQT Midstream Services, LLC, the general partner of EQM, since January 2012, EQT GP Services, LLC, the general partner of EQGP, since January 2015, and Rice Midstream Management LLC, the general partner of RMP, since November 2017.
|
|
|
|
|
|
Donald M. Jenkins (45)
|
|
Chief Commercial Officer (2017)
|
|
Elected to present position March 2017. Mr. Jenkins served as Executive Vice President, Commercial, EQT Energy, LLC, from May 2014 to February 2017; and Senior Vice President, Trading and Origination, EQT Energy, LLC, from December 2012 to May 2014.
|
|
|
|
|
|
Robert J. McNally (47)
|
|
Senior Vice President and Chief Financial Officer (2016)
|
|
Elected to present position March 2016. Mr. McNally is also a Director and Senior Vice President and Chief Financial Officer of each of EQT Midstream Services, LLC, the general partner of EQM, since March 2016, EQT GP Services, LLC, the general partner of EQGP, since March 2016, and Rice Midstream Management LLC, the general partner of RMP, since November 2017. Prior to joining EQT Corporation, Mr. McNally served as Executive Vice President and Chief Financial Officer of Precision Drilling Corporation, a publicly traded drilling services company, from July 2010 to March 2016.
|
|
|
|
|
|
Charlene Petrelli (57)
|
|
Vice President and Chief Human Resources Officer (2003)
|
|
Elected to present position February 2007.
|
|
|
|
|
|
David L. Porges (60)
|
|
Executive Chairman (1998)
|
|
Elected to present position March 2017. Mr. Porges served as Chairman and Chief Executive Officer, EQT Corporation, from December 2015 to February 2017; Chairman, President, and Chief Executive Officer, EQT Corporation, from May 2011 to December 2015; and President and Chief Executive Officer of each of EQT Midstream Services, LLC, the general partner of EQM, from January 2012 to February 2017, and EQT GP Services, LLC, the general partner of EQGP, from January 2015 to February 2017. Mr. Porges has served as a Director of the Company since May 2002 and also Chairman of the Boards of Directors of the general partners of EQGP, EQM and RMP, since January 2015, January 2012 and November 2017, respectively. As previously disclosed in the Company’s Form 8-K filed with the SEC on January 18, 2018, Mr. Porges intends to retire from his position as Executive Chairman of the Company on February 28, 2018. Following that time, he will continue to serve as a non-executive Chairman of the Company’s Board of Directors.
|
|
|
|
|
|
David E. Schlosser, Jr. (52)
|
|
Senior Vice President, EQT Corporation and President, Exploration and Production (2017)
|
|
Elected to present position March 2017. Mr. Schlosser served as Executive Vice President, Engineering, Geology and Planning, EQT Production Company, from October 2014 to February 2017; and Senior Vice President, Engineering and Strategic Planning, EQT Production Company, from March 2012 to September 2014.
|
|
|
|
|
|
Steven T. Schlotterbeck (52)
|
|
President and Chief Executive Officer (2008)
|
|
Elected to present position March 2017. Mr. Schlotterbeck served as President, EQT Corporation and President, Exploration and Production from December 2015 to February 2017; Executive Vice President, EQT Corporation and President, Exploration and Production from December 2013 to December 2015; and Senior Vice President, EQT Corporation and President, Exploration and Production from April 2010 to December 2013. Mr. Schlotterbeck has also served as President and Chief Executive Officer of each of EQT GP Services, LLC, the general partner of EQGP, since March 2017, EQT Midstream Services, LLC, the general partner of EQM, since March 2017, and Rice Midstream Management LLC, the general partner of RMP, since November 2017. Mr. Schlotterbeck is also a Director of each of EQT Corporation, since January 2017, EQT GP Services, LLC, since January 2015, EQT Midstream Services, LLC, since January 2017, and Rice Midstream Management LLC, since November 2017.
|
|
|
|
|
|
Jimmi Sue Smith (45)
|
|
Chief Accounting Officer (2016)
|
|
Elected to present position September 2016. Ms. Smith served as Vice President and Controller of the Company's midstream and commercial businesses from March 2013 to September 2016; and Vice President and Controller of the Company's midstream business from January 2013 through March 2013. Ms. Smith is also Chief Accounting Officer of each of EQT Midstream Services, LLC, the general partner of EQM, since September 2016, EQT GP Services, LLC, the general partner of EQGP, since September 2016, and Rice Midstream Management LLC, the general partner of RMP, since November 2017.
|
|
|
2017
|
|
2016
|
||||||||||||||||||||
|
|
High
|
|
Low
|
|
Dividend
|
|
High
|
|
Low
|
|
Dividend
|
||||||||||||
1st Quarter
|
|
$
|
66.41
|
|
|
$
|
56.33
|
|
|
$
|
0.03
|
|
|
$
|
68.26
|
|
|
$
|
48.30
|
|
|
$
|
0.03
|
|
2nd Quarter
|
|
64.45
|
|
|
49.63
|
|
|
0.03
|
|
|
80.61
|
|
|
63.48
|
|
|
0.03
|
|
||||||
3rd Quarter
|
|
67.84
|
|
|
57.49
|
|
|
0.03
|
|
|
79.64
|
|
|
67.69
|
|
|
0.03
|
|
||||||
4th Quarter
|
|
66.03
|
|
|
53.43
|
|
|
0.03
|
|
|
75.74
|
|
|
63.11
|
|
|
0.03
|
|
Period
|
|
Total
number of
shares
purchased (a)
|
|
Average
price
paid per
share
|
|
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 2017 (October 1 – October 31)
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
700,000
|
|
November 2017 (November 1 – November 30)
|
|
788,066
|
|
|
65.15
|
|
|
—
|
|
|
700,000
|
|
|
December 2017 (December 1 – December 31)
|
|
53,443
|
|
|
64.62
|
|
|
—
|
|
|
700,000
|
|
|
Total
|
|
841,509
|
|
|
$
|
65.11
|
|
|
—
|
|
|
|
|
|
|
12/12
|
|
12/13
|
|
12/14
|
|
12/15
|
|
12/16
|
|
12/17
|
||||||||||||
EQT Corporation
|
|
$
|
100.00
|
|
|
$
|
152.46
|
|
|
$
|
128.71
|
|
|
$
|
88.77
|
|
|
$
|
111.58
|
|
|
$
|
97.30
|
|
S&P 500
|
|
100.00
|
|
|
132.39
|
|
|
150.51
|
|
|
152.59
|
|
|
170.84
|
|
|
208.14
|
|
||||||
2016 Self-Constructed Peer Group (a)
|
|
100.00
|
|
|
139.77
|
|
|
116.14
|
|
|
73.35
|
|
|
109.56
|
|
|
103.76
|
|
||||||
2017 Self-Constructed Peer Group (b)
|
|
100.00
|
|
|
137.94
|
|
|
115.12
|
|
|
71.23
|
|
|
105.10
|
|
|
98.82
|
|
(a)
|
The 2016 Self-Constructed Peer Group includes the following 21 companies: Cabot Oil & Gas Corp, Chesapeake Energy Corp, Cimarex Energy Co, Concho Resources Inc., CONSOL Energy Inc. (now known as CNX Resources Corp), Continental Resources Inc., Energen Corp, EOG Resources Inc., EXCO Resources Inc., Marathon Oil Corp, National Fuel Gas Co, Newfield Exploration Co, Noble Energy Inc., ONEOK Inc., Pioneer Natural Resources Co, QEP Resources Inc., Range Resources Corp, SM Energy Co, Southwestern Energy Co, Ultra Petroleum Corp and Whiting Petroleum Corp. Spectra Energy Corp was included in the self-constructed peer group that served as the basis for the stock performance chart in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 but has been excluded from the 2016 Self-Constructed Peer Group above as it was acquired.
|
(b)
|
The 2017 Self-Constructed Peer Group includes the following 22 companies: Antero Resources Corp, Cabot Oil & Gas Corp, Chesapeake Energy Corp, Cimarex Energy Co, Concho Resources Inc., CONSOL Energy Inc. (now known as CNX Resources Corp), Continental Resources Inc., Devon Energy Corp, Energen Corp, EOG Resources Inc., EXCO Resources Inc., Marathon Oil Corp, National Fuel Gas Co, Newfield Exploration Co, Noble Energy Inc., ONEOK Inc., Pioneer Natural Resources Co, QEP Resources Inc., Range Resources Corp, SM Energy Co, Southwestern Energy Co, and Whiting Petroleum Corp. The 2017 Self-Constructed Peer Group is the peer group that is used for the Company’s 2017 Incentive Performance Share Unit Program, which utilizes three-year total shareholder return against the peer group as one performance metric. It is also identical to the 2016 Self-Constructed Peer Group after adjusting for the removal of Spectra Energy Corp (acquired) and Ultra Petroleum Corp (filed for bankruptcy) and the addition of Antero Resources Corp and Devon Energy Corp (determined by the Company’s Management Development and Compensation Committee (the Compensation Committee) to be appropriate peers).
|
|
|
As of and for the Years Ended December 31,
|
||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
|
|
(Thousands, except per share amounts)
|
||||||||||||||||||
Total operating revenues
|
|
$
|
3,378,015
|
|
|
$
|
1,608,348
|
|
|
$
|
2,339,762
|
|
|
$
|
2,469,710
|
|
|
$
|
1,862,011
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Amounts attributable to EQT Corporation:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
|
$
|
1,508,529
|
|
|
$
|
(452,983
|
)
|
|
$
|
85,171
|
|
|
$
|
385,594
|
|
|
$
|
298,729
|
|
Net income (loss)
|
|
$
|
1,508,529
|
|
|
$
|
(452,983
|
)
|
|
$
|
85,171
|
|
|
$
|
386,965
|
|
|
$
|
390,572
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings per share of common stock attributable to EQT Corporation:
|
|
|
|
|
|
|
|
|
||||||||||||
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
|
$
|
8.05
|
|
|
$
|
(2.71
|
)
|
|
$
|
0.56
|
|
|
$
|
2.54
|
|
|
$
|
1.98
|
|
Net income (loss)
|
|
$
|
8.05
|
|
|
$
|
(2.71
|
)
|
|
$
|
0.56
|
|
|
$
|
2.55
|
|
|
$
|
2.59
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Diluted:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
|
$
|
8.04
|
|
|
$
|
(2.71
|
)
|
|
$
|
0.56
|
|
|
$
|
2.53
|
|
|
$
|
1.97
|
|
Net income (loss)
|
|
$
|
8.04
|
|
|
$
|
(2.71
|
)
|
|
$
|
0.56
|
|
|
$
|
2.54
|
|
|
$
|
2.57
|
|
Total assets
|
|
$
|
29,522,604
|
|
|
$
|
15,472,922
|
|
|
$
|
13,976,172
|
|
|
$
|
12,035,353
|
|
|
$
|
9,765,907
|
|
Long-term debt
|
|
$
|
7,331,554
|
|
|
$
|
3,289,459
|
|
|
$
|
2,793,343
|
|
|
$
|
2,959,353
|
|
|
$
|
2,475,370
|
|
Cash dividends declared per share of common stock
|
|
$
|
0.12
|
|
|
$
|
0.12
|
|
|
$
|
0.12
|
|
|
$
|
0.12
|
|
|
$
|
0.12
|
|
•
|
Closed the Rice Merger on
November 13, 2017
|
•
|
Achieved annual production sales volumes of
887.5
Bcfe,
17%
higher than
2016
|
•
|
Completed the 2017 Notes Offering (defined in Note
15
to the Consolidated Financial Statements) totaling $3.0 billion
|
•
|
Received FERC Certificate for Mountain Valley Pipeline
|
|
Years Ended December 31,
|
||||||||||
in thousands (unless noted)
|
2017 (e)
|
|
2016
|
|
2015
|
||||||
NATURAL GAS
|
|
|
|
|
|
||||||
Sales volume (MMcf)
|
774,076
|
|
|
683,495
|
|
|
547,094
|
|
|||
NYMEX price ($/MMBtu) (a)
|
$
|
3.09
|
|
|
$
|
2.47
|
|
|
$
|
2.66
|
|
Btu uplift
|
$
|
0.27
|
|
|
$
|
0.22
|
|
|
$
|
0.25
|
|
Natural gas price ($/Mcf)
|
$
|
3.36
|
|
|
$
|
2.69
|
|
|
$
|
2.91
|
|
|
|
|
|
|
|
||||||
Basis ($/Mcf) (b)
|
(0.54
|
)
|
|
(0.81
|
)
|
|
(0.63
|
)
|
|||
Cash settled basis swaps (not designated as hedges) ($/Mcf)
|
$
|
0.01
|
|
|
$
|
0.09
|
|
|
$
|
0.03
|
|
Average differential, including cash settled basis swaps ($/Mcf)
|
$
|
(0.53
|
)
|
|
$
|
(0.72
|
)
|
|
$
|
(0.60
|
)
|
|
|
|
|
|
|
||||||
Average adjusted price ($/Mcf)
|
$
|
2.83
|
|
|
$
|
1.97
|
|
|
$
|
2.31
|
|
Cash settled derivatives (cash flow hedges) ($/Mcf)
|
0.01
|
|
|
0.13
|
|
|
0.47
|
|
|||
Cash settled derivatives (not designated as hedges) ($/Mcf)
|
0.05
|
|
|
0.31
|
|
|
0.28
|
|
|||
Average natural gas price, including cash settled derivatives ($/Mcf)
|
$
|
2.89
|
|
|
$
|
2.41
|
|
|
$
|
3.06
|
|
|
|
|
|
|
|
||||||
Natural gas sales, including cash settled derivatives
|
$
|
2,237,234
|
|
|
$
|
1,649,831
|
|
|
$
|
1,671,562
|
|
|
|
|
|
|
|
||||||
LIQUIDS
|
|
|
|
|
|
||||||
NGLs (excluding ethane):
|
|
|
|
|
|
||||||
Sales volume (MMcfe) (c)
|
74,060
|
|
|
57,243
|
|
|
51,530
|
|
|||
Sales volume (Mbbls)
|
12,343
|
|
|
9,540
|
|
|
8,588
|
|
|||
Price ($/Bbl)
|
$
|
31.59
|
|
|
$
|
19.43
|
|
|
$
|
18.84
|
|
Cash settled derivatives (not designated as hedges) ($/Bbl)
|
(0.69
|
)
|
|
—
|
|
|
—
|
|
|||
Average NGL price, including cash settled derivatives ($/Bbl)
|
$
|
30.90
|
|
|
$
|
19.43
|
|
|
$
|
18.84
|
|
NGLs sales
|
$
|
381,327
|
|
|
$
|
185,405
|
|
|
$
|
161,775
|
|
Ethane:
|
|
|
|
|
|
||||||
Sales volume (MMcfe) (c)
|
33,432
|
|
|
13,856
|
|
|
—
|
|
|||
Sales volume (Mbbls)
|
5,572
|
|
|
2,309
|
|
|
—
|
|
|||
Price ($/Bbl)
|
$
|
6.32
|
|
|
$
|
5.08
|
|
|
$
|
—
|
|
Ethane sales
|
$
|
35,241
|
|
|
$
|
11,742
|
|
|
$
|
—
|
|
Oil:
|
|
|
|
|
|
||||||
Sales volume (MMcfe) (c)
|
5,952
|
|
|
4,373
|
|
|
4,458
|
|
|||
Sales volume (Mbbls)
|
992
|
|
|
729
|
|
|
743
|
|
|||
Price ($/Bbl)
|
$
|
40.70
|
|
|
$
|
34.73
|
|
|
$
|
38.70
|
|
Oil sales
|
$
|
40,376
|
|
|
$
|
25,312
|
|
|
$
|
28,752
|
|
|
|
|
|
|
|
||||||
Total liquids sales volume (MMcfe) (c)
|
113,444
|
|
|
75,472
|
|
|
55,988
|
|
|||
Total liquids sales volume (Mbbls)
|
18,907
|
|
|
12,578
|
|
|
9,331
|
|
|||
|
|
|
|
|
|
||||||
Liquids sales
|
$
|
456,944
|
|
|
$
|
222,459
|
|
|
$
|
190,527
|
|
|
|
|
|
|
|
||||||
TOTAL PRODUCTION
|
|
|
|
|
|
||||||
Total natural gas & liquids sales, including cash settled derivatives (d)
|
$
|
2,694,178
|
|
|
$
|
1,872,290
|
|
|
$
|
1,862,089
|
|
Total sales volume (MMcfe)
|
887,520
|
|
|
758,967
|
|
|
603,082
|
|
|||
|
|
|
|
|
|
||||||
Average realized price ($/Mcfe)
|
$
|
3.04
|
|
|
$
|
2.47
|
|
|
$
|
3.09
|
|
Calculation of EQT Production adjusted operating revenues
|
Years Ended December 31,
|
||||||||||
$ in thousands (unless noted)
|
2017
|
|
2016
|
|
2015
|
||||||
EQT Production total operating revenues
|
$
|
3,106,337
|
|
|
$
|
1,387,054
|
|
|
$
|
2,131,664
|
|
(Deduct) add back:
|
|
|
|
|
|
||||||
(Gain) loss on derivatives not designated as hedges
|
(390,021
|
)
|
|
248,991
|
|
|
(385,762
|
)
|
|||
Net cash settlements received on derivatives not designated as hedges
|
40,728
|
|
|
279,425
|
|
|
172,093
|
|
|||
Premiums received (paid) for derivatives that settled during the year
|
2,132
|
|
|
(2,132
|
)
|
|
(364
|
)
|
|||
Pipeline and net marketing services
|
(64,998
|
)
|
|
(41,048
|
)
|
|
(55,542
|
)
|
|||
EQT Production adjusted operating revenues, a non-GAAP financial measure
|
$
|
2,694,178
|
|
|
$
|
1,872,290
|
|
|
$
|
1,862,089
|
|
|
|
|
|
|
|
||||||
Total sales volumes (MMcfe)
|
887,520
|
|
|
758,967
|
|
|
603,082
|
|
|||
|
|
|
|
|
|
||||||
Average realized price ($/Mcfe)
|
$
|
3.04
|
|
|
$
|
2.47
|
|
|
$
|
3.09
|
|
|
|
Years Ended December 31,
|
||||||||||||||||
|
|
2017 (d)
|
|
2016
|
|
% change 2017 - 2016
|
|
2015
|
|
% change 2016 - 2015
|
||||||||
OPERATIONAL DATA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volume detail (MMcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Marcellus (a)
|
|
770,620
|
|
|
660,146
|
|
|
16.7
|
|
|
505,102
|
|
|
30.7
|
|
|||
Ohio Utica
|
|
24,266
|
|
|
536
|
|
|
4,427.2
|
|
|
758
|
|
|
(29.3
|
)
|
|||
Other
|
|
92,634
|
|
|
98,285
|
|
|
(5.7
|
)
|
|
97,222
|
|
|
1.1
|
|
|||
Total production sales volumes (b)
|
|
887,520
|
|
|
758,967
|
|
|
16.9
|
|
|
603,082
|
|
|
25.8
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average daily sales volumes (MMcfe/d)
|
|
2,432
|
|
|
2,074
|
|
|
17.3
|
|
|
1,652
|
|
|
25.5
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average realized price ($/Mcfe)
|
|
$
|
3.04
|
|
|
$
|
2.47
|
|
|
23.1
|
|
|
$
|
3.09
|
|
|
(20.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Gathering to EQM Gathering and RMP Gathering ($/Mcfe)
|
|
$
|
0.47
|
|
|
$
|
0.48
|
|
|
(2.1
|
)
|
|
$
|
0.51
|
|
|
(5.9
|
)
|
Transmission to EQM Transmission ($/Mcfe)
|
|
$
|
0.20
|
|
|
$
|
0.20
|
|
|
—
|
|
|
$
|
0.20
|
|
|
—
|
|
Third-party gathering and transmission ($/Mcfe)
|
|
$
|
0.42
|
|
|
$
|
0.32
|
|
|
31.3
|
|
|
$
|
0.29
|
|
|
10.3
|
|
Processing ($/Mcfe)
|
|
$
|
0.20
|
|
|
$
|
0.16
|
|
|
25.0
|
|
|
$
|
0.17
|
|
|
(5.9
|
)
|
Lease operating expenses (LOE), excluding production taxes ($/Mcfe)
|
|
$
|
0.13
|
|
|
$
|
0.15
|
|
|
(13.3
|
)
|
|
$
|
0.19
|
|
|
(21.1
|
)
|
Production taxes ($/Mcfe)
|
|
$
|
0.08
|
|
|
$
|
0.08
|
|
|
—
|
|
|
$
|
0.10
|
|
|
(20.0
|
)
|
Production depletion ($/Mcfe)
|
|
$
|
1.04
|
|
|
$
|
1.06
|
|
|
(1.9
|
)
|
|
$
|
1.18
|
|
|
(10.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Depreciation, depletion and amortization (DD&A) (thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Production depletion
|
|
$
|
924,430
|
|
|
$
|
803,883
|
|
|
15.0
|
|
|
$
|
713,651
|
|
|
12.6
|
|
Other DD&A
|
|
57,673
|
|
|
55,135
|
|
|
4.6
|
|
|
51,647
|
|
|
6.8
|
|
|||
Total DD&A
|
|
$
|
982,103
|
|
|
$
|
859,018
|
|
|
14.3
|
|
|
$
|
765,298
|
|
|
12.2
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Capital expenditures (thousands) (c)
|
|
$
|
2,430,094
|
|
|
$
|
2,073,907
|
|
|
17.2
|
|
|
$
|
1,893,750
|
|
|
9.5
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
FINANCIAL DATA (thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Sales of natural gas, oil and NGLs
|
|
$
|
2,651,318
|
|
|
$
|
1,594,997
|
|
|
66.2
|
|
|
$
|
1,690,360
|
|
|
(5.6
|
)
|
Pipeline and net marketing services
|
|
64,998
|
|
|
41,048
|
|
|
58.3
|
|
|
55,542
|
|
|
(26.1
|
)
|
|||
Gain (loss) on derivatives not designated as hedges
|
|
390,021
|
|
|
(248,991
|
)
|
|
(256.6
|
)
|
|
385,762
|
|
|
(164.5
|
)
|
|||
Total operating revenues
|
|
3,106,337
|
|
|
1,387,054
|
|
|
124.0
|
|
|
2,131,664
|
|
|
(34.9
|
)
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Gathering
|
|
480,111
|
|
|
413,758
|
|
|
16.0
|
|
|
330,562
|
|
|
25.2
|
|
|||
Transmission
|
|
495,635
|
|
|
341,569
|
|
|
45.1
|
|
|
268,368
|
|
|
27.3
|
|
|||
Processing
|
|
179,538
|
|
|
124,864
|
|
|
43.8
|
|
|
100,329
|
|
|
24.5
|
|
|||
LOE, excluding production taxes
|
|
113,937
|
|
|
112,509
|
|
|
1.3
|
|
|
116,527
|
|
|
(3.4
|
)
|
|||
Production taxes
|
|
68,848
|
|
|
62,317
|
|
|
10.5
|
|
|
61,408
|
|
|
1.5
|
|
|||
Exploration
|
|
25,117
|
|
|
13,410
|
|
|
87.3
|
|
|
61,970
|
|
|
(78.4
|
)
|
|||
Selling, general and administrative (SG&A)
|
|
165,792
|
|
|
180,426
|
|
|
(8.1
|
)
|
|
172,725
|
|
|
4.5
|
|
|||
DD&A
|
|
982,103
|
|
|
859,018
|
|
|
14.3
|
|
|
765,298
|
|
|
12.2
|
|
|||
Amortization of intangible assets
|
|
5,540
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
Impairment of long-lived assets
|
|
—
|
|
|
6,939
|
|
|
(100.0
|
)
|
|
122,469
|
|
|
(94.3
|
)
|
|||
Total operating expenses
|
|
2,516,621
|
|
|
2,114,810
|
|
|
19.0
|
|
|
1,999,656
|
|
|
5.8
|
|
|||
Gain on sale / exchange of assets
|
|
—
|
|
|
8,025
|
|
|
(100.0
|
)
|
|
—
|
|
|
100.0
|
|
|||
Operating income (loss)
|
|
$
|
589,716
|
|
|
$
|
(719,731
|
)
|
|
(181.9
|
)
|
|
$
|
132,008
|
|
|
(645.2
|
)
|
(a)
|
Includes Upper Devonian wells.
|
(b)
|
NGLs, ethane and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods.
|
(c)
|
Includes cash capital expenditures of
$819.0 million
, non-cash capital expenditures of
$10.0 million
and measurement period adjustments of
$(14.3) million
for acquisitions during the year ended December 31, 2017. Includes cash capital expenditures of
$1,051.2 million
and non-cash capital expenditures of
$87.6 million
related to acquisitions during the year ended December 31, 2016. See Note
10
to the Consolidated Financial Statements for additional information related to these transactions.
|
(d)
|
For the year ended December 31, 2017, the operating income for EQT Production includes the results of operations for the production operations and retained midstream operations acquired in the Rice Merger for the period of
November 13, 2017
through December 31, 2017. See Note
2
for a discussion of the Rice Merger.
|
|
|
Years Ended December 31,
|
||||||||||||||||
|
|
2017
|
|
2016
|
|
% change 2017 - 2016
|
|
2015
|
|
% change 2016 - 2015
|
||||||||
FINANCIAL DATA
|
|
|
|
|
(Thousands, other than per day amounts)
|
|
|
|
|
|||||||||
Firm reservation fee revenues
|
|
$
|
407,355
|
|
|
$
|
339,237
|
|
|
20.1
|
|
|
$
|
267,517
|
|
|
26.8
|
|
Volumetric based fee revenues:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Usage fees under firm contracts (a)
|
|
32,206
|
|
|
38,408
|
|
|
(16.1
|
)
|
|
33,021
|
|
|
16.3
|
|
|||
Usage fees under interruptible contracts
|
|
14,975
|
|
|
19,849
|
|
|
(24.6
|
)
|
|
34,567
|
|
|
(42.6
|
)
|
|||
Total volumetric based fee revenues
|
|
47,181
|
|
|
58,257
|
|
|
(19.0
|
)
|
|
67,588
|
|
|
(13.8
|
)
|
|||
Total operating revenues
|
|
454,536
|
|
|
397,494
|
|
|
14.4
|
|
|
335,105
|
|
|
18.6
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operating and maintenance
|
|
43,235
|
|
|
38,367
|
|
|
12.7
|
|
|
37,011
|
|
|
3.7
|
|
|||
Selling, general and administrative
|
|
38,942
|
|
|
39,678
|
|
|
(1.9
|
)
|
|
30,477
|
|
|
30.2
|
|
|||
Depreciation and amortization
|
|
38,796
|
|
|
30,422
|
|
|
27.5
|
|
|
24,360
|
|
|
24.9
|
|
|||
Total operating expenses
|
|
120,973
|
|
|
108,467
|
|
|
11.5
|
|
|
91,848
|
|
|
18.1
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operating income
|
|
$
|
333,563
|
|
|
$
|
289,027
|
|
|
15.4
|
|
|
$
|
243,257
|
|
|
18.8
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
OPERATIONAL DATA
|
|
|
|
|
|
|
|
|
|
|
||||||||
Gathered volumes (BBtu per day):
|
|
|
|
|
|
|
|
|
|
|
||||||||
Firm capacity reservation
|
|
1,826
|
|
|
1,553
|
|
|
17.6
|
|
|
1,140
|
|
|
36.2
|
|
|||
Volumetric based services (b)
|
|
361
|
|
|
420
|
|
|
(14.0
|
)
|
|
485
|
|
|
(13.4
|
)
|
|||
Total gathered volumes
|
|
2,187
|
|
|
1,973
|
|
|
10.8
|
|
|
1,625
|
|
|
21.4
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Capital expenditures
|
|
$
|
196,871
|
|
|
$
|
295,315
|
|
|
(33.3
|
)
|
|
$
|
225,537
|
|
|
30.9
|
|
(a)
|
Includes fees on volumes gathered in excess of firm contracted capacity.
|
(b)
|
Includes volumes gathered under interruptible contracts and volumes gathered in excess of firm contracted capacity.
|
|
|
Years Ended December 31,
|
||||||||||||||||
|
|
2017
|
|
2016
|
|
%
change
2017 -
2016
|
|
2015
|
|
%
change
2016 -
2015
|
||||||||
FINANCIAL DATA
|
|
|
|
(Thousands, other than per day amounts)
|
|
|
|
|||||||||||
Firm reservation revenues
|
|
$
|
348,193
|
|
|
$
|
277,816
|
|
|
25.3
|
|
|
$
|
247,231
|
|
|
12.4
|
|
Volumetric based fee revenues:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Usage fees under firm contracts
(a)
|
|
13,743
|
|
|
45,679
|
|
|
(69.9
|
)
|
|
42,646
|
|
|
7.1
|
|
|||
Usage fees under interruptible contracts
|
|
17,624
|
|
|
14,625
|
|
|
20.5
|
|
|
7,954
|
|
|
83.9
|
|
|||
Total volumetric based fee revenues
|
|
31,367
|
|
|
60,304
|
|
|
(48.0
|
)
|
|
50,600
|
|
|
19.2
|
|
|||
Total operating revenues
|
|
379,560
|
|
|
338,120
|
|
|
12.3
|
|
|
297,831
|
|
|
13.5
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Operating and maintenance
|
|
41,482
|
|
|
34,846
|
|
|
19.0
|
|
|
33,092
|
|
|
5.3
|
|
|||
Selling, general and administrative
|
|
32,244
|
|
|
33,083
|
|
|
(2.5
|
)
|
|
31,425
|
|
|
5.3
|
|
|||
Depreciation and amortization
|
|
58,689
|
|
|
32,269
|
|
|
81.9
|
|
|
25,535
|
|
|
26.4
|
|
|||
Total operating expenses
|
|
132,415
|
|
|
100,198
|
|
|
32.2
|
|
|
90,052
|
|
|
11.3
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operating income
|
|
$
|
247,145
|
|
|
$
|
237,922
|
|
|
3.9
|
|
|
$
|
207,779
|
|
|
14.5
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
OPERATIONAL DATA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Transmission pipeline throughput (BBtu per day)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Firm capacity reservation
|
|
2,399
|
|
|
1,651
|
|
|
45.3
|
|
|
1,841
|
|
|
(10.3
|
)
|
|||
Volumetric based services
(b)
|
|
37
|
|
|
430
|
|
|
(91.4
|
)
|
|
281
|
|
|
53.0
|
|
|||
Total transmission pipeline throughput
|
|
2,436
|
|
|
2,081
|
|
|
17.1
|
|
|
2,122
|
|
|
(1.9
|
)
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average contracted firm transmission reservation commitments (BBtu per day)
|
|
3,627
|
|
|
2,814
|
|
|
28.9
|
|
|
2,624
|
|
|
7.2
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Capital expenditures
|
|
$
|
111,102
|
|
|
$
|
292,049
|
|
|
(62.0
|
)
|
|
$
|
203,706
|
|
|
43.4
|
|
(a)
|
Includes commodity charges and fees on all volumes transported under firm contracts as well as transmission fees on volumes in excess of firm contracted capacity.
|
(b)
|
Includes volumes transported under interruptible contracts and volumes transported in excess of firm contracted capacity.
|
|
|
Years Ended December 31,
|
||||||||||||||||
|
|
2017 (a)
|
|
2016
|
|
% change
2017 - 2016
|
|
2015
|
|
% change
2016 - 2015
|
||||||||
FINANCIAL DATA
|
|
(Thousands, other than per day amounts)
|
||||||||||||||||
Gathering revenues:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Affiliate
|
|
$
|
26,242
|
|
|
$
|
—
|
|
|
100.0
|
|
|
$
|
—
|
|
|
—
|
|
Third-party
|
|
19
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
Total gathering revenues
|
|
26,261
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Compression revenues:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Affiliate
|
|
4,343
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
Third-party
|
|
10
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
Total compression revenues
|
|
4,353
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
Total operating revenues
|
|
30,614
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operation and maintenance expense
|
|
1,584
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
General and administrative expense
|
|
3,265
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
Depreciation expense
|
|
3,965
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
Total operating expenses
|
|
8,814
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operating income (loss)
|
|
$
|
21,800
|
|
|
$
|
—
|
|
|
100.0
|
|
|
$
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
OPERATIONAL DATA
|
|
|
|
|
|
|
|
|
|
|
||||||||
Gathered volumes (BBtu/d):
|
|
1,547
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Compression volumes (BBtu/d):
|
|
1,155
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Capital expenditures
|
|
$
|
28,320
|
|
|
$
|
—
|
|
|
100.0
|
|
|
$
|
—
|
|
|
—
|
|
|
|
Years Ended December 31,
|
||||||||||||||||
|
|
2017 (a)
|
|
2016
|
|
% change
2017 - 2016
|
|
2015
|
|
% change
2016 - 2015
|
||||||||
FINANCIAL DATA
|
|
(Thousands, other than per day amounts)
|
||||||||||||||||
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Affiliate
|
|
$
|
13,549
|
|
|
$
|
—
|
|
|
100.0
|
|
|
$
|
—
|
|
|
—
|
|
Third-party
|
|
56
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
Total operating revenues
|
|
13,605
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operation and maintenance expense
|
|
5,598
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
General and administrative expense
|
|
347
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
Depreciation expense
|
|
3,515
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
Total operating expenses
|
|
9,460
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Operating income (loss)
|
|
$
|
4,145
|
|
|
$
|
—
|
|
|
100.0
|
|
|
$
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
OPERATIONAL DATA
|
|
|
|
|
|
|
|
|
|
|
||||||||
Water services volumes (in MMgal):
|
|
226
|
|
|
—
|
|
|
100.0
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||||||
Capital expenditures
|
|
$
|
6,233
|
|
|
$
|
—
|
|
|
100.0
|
|
|
$
|
—
|
|
|
—
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Other income
|
|
$
|
24,955
|
|
|
$
|
31,693
|
|
|
$
|
9,953
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Loss on debt extinguishment
|
|
$
|
12,641
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
|
|
|
(Thousands)
|
|
|
|
||||
Interest expense
|
|
$
|
202,772
|
|
|
$
|
147,920
|
|
|
$
|
146,531
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Income tax (benefit) expense
|
|
$
|
(1,115,619
|
)
|
|
$
|
(263,464
|
)
|
|
$
|
104,675
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Net income attributable to noncontrolling interests
|
|
$
|
349,613
|
|
|
$
|
321,920
|
|
|
$
|
236,715
|
|
|
2017 Actual
|
|
2016 Actual
|
|
2015 Actual
|
||||||
Well development (primarily drilling and completion)
|
1,385
|
|
|
783
|
|
|
1,670
|
|
|||
Property acquisitions
|
1,007
|
|
|
1,284
|
|
|
182
|
|
|||
Other Production infrastructure
|
38
|
|
|
7
|
|
|
41
|
|
|||
EQM Gathering
|
197
|
|
|
295
|
|
|
226
|
|
|||
EQM Transmission
|
111
|
|
|
292
|
|
|
204
|
|
|||
RMP Gathering
|
28
|
|
|
—
|
|
|
—
|
|
|||
RMP Water
|
6
|
|
|
—
|
|
|
—
|
|
|||
Other corporate items
|
7
|
|
|
7
|
|
|
21
|
|
|||
Total
|
$
|
2,779
|
|
|
$
|
2,668
|
|
|
$
|
2,344
|
|
Less: non-cash *
|
9
|
|
|
77
|
|
|
(90
|
)
|
|||
Total cash capital expenditures
|
$
|
2,770
|
|
|
$
|
2,591
|
|
|
$
|
2,434
|
|
Rating Service
|
|
Senior
Notes
|
|
Outlook
|
Moody’s Investors Service (Moody's)
|
|
Baa3
|
|
Stable
|
Standard & Poor’s Ratings Service (S&P)
|
|
BBB
|
|
Negative
|
Fitch Ratings Service (Fitch)
|
|
BBB-
|
|
Stable
|
Rating Service
|
|
Senior
Notes
|
|
Outlook
|
Moody's
|
|
Ba1
|
|
Stable
|
S&P
|
|
BBB-
|
|
Stable
|
Fitch
|
|
BBB-
|
|
Stable
|
|
|
2018 (a)(b)(c)
|
|
2019 (b)
|
|
2020
|
||||||
NYMEX Swaps
|
|
|
|
|
|
|
|
|
|
|||
Total Volume (Bcf)
|
|
541
|
|
|
234
|
|
|
234
|
|
|||
Average Price per Mcf (NYMEX) (d)
|
|
$
|
3.14
|
|
|
$
|
3.03
|
|
|
$
|
3.05
|
|
Collars
|
|
|
|
|
|
|
||||||
Total Volume (Bcf)
|
|
117
|
|
|
66
|
|
|
—
|
|
|||
Average Floor Price per Mcf (NYMEX) (d)
|
|
$
|
3.28
|
|
|
$
|
3.15
|
|
|
$
|
—
|
|
Average Cap Price per Mcf (NYMEX) (d)
|
|
$
|
3.78
|
|
|
$
|
3.68
|
|
|
$
|
—
|
|
Puts (Long)
|
|
|
|
|
|
|
||||||
Total Volume (Bcf)
|
|
10
|
|
|
7
|
|
|
—
|
|
|||
Average Floor Price per Mcf (NYMEX)*
|
|
$
|
2.91
|
|
|
$
|
2.94
|
|
|
$
|
—
|
|
(b)
|
The Company also sold calendar year 2018 and 2019 calls for approximately 64 Bcf and 45 Bcf, respectively, at strike prices of $3.49 per Mcf and $3.69 per Mcf, respectively.
|
(d)
|
The average price is based on a conversion rate of 1.05 MMBtu/Mcf.
|
|
|
Total
|
|
2018
|
|
2019-2020
|
|
2021-2022
|
|
2023+
|
||||||||||
|
|
(Thousands)
|
||||||||||||||||||
Purchase obligations (a)
|
|
$
|
16,616,818
|
|
|
$
|
824,813
|
|
|
$
|
2,045,143
|
|
|
$
|
2,004,729
|
|
|
$
|
11,742,133
|
|
Senior Notes
|
|
5,618,200
|
|
|
8,000
|
|
|
1,711,200
|
|
|
1,524,000
|
|
|
2,375,000
|
|
|||||
Interest payments on Senior Notes (b)
|
|
1,515,749
|
|
|
241,748
|
|
|
449,128
|
|
|
333,269
|
|
|
491,604
|
|
|||||
Credit facility borrowings (c)
|
|
1,761,000
|
|
|
—
|
|
|
286,000
|
|
|
1,475,000
|
|
|
—
|
|
|||||
Operating leases (d)
|
|
231,515
|
|
|
70,887
|
|
|
64,779
|
|
|
27,185
|
|
|
68,664
|
|
|||||
Water infrastructure (e)
|
|
19,547
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19,547
|
|
|||||
Other liabilities (f)
|
|
78,748
|
|
|
30,949
|
|
|
47,799
|
|
|
—
|
|
|
—
|
|
|||||
Total contractual obligations
|
|
$
|
25,841,577
|
|
|
$
|
1,176,397
|
|
|
$
|
4,604,049
|
|
|
$
|
5,364,183
|
|
|
$
|
14,696,948
|
|
(a)
|
Purchase obligations are primarily commitments for demand charges under existing long-term contracts and binding precedent agreements with various unconsolidated pipelines, including commitments from the Company to the MVP Joint Venture, some of which extend up to 20 years or longer. The Company has entered into agreements to release some of its capacity to various third parties. Purchase obligations also include commitments with third parties for processing capacity in order to extract heavier liquid hydrocarbons from the natural gas stream.
|
(b)
|
Interest payments exclude interest related to the credit facility borrowings and the Floating Rate Notes (defined in Note
15
to the Consolidated Financial Statements) as the interest rates on the Company's, EQM's and RMP's credit facilities and the Floating Rate Notes are variable.
|
(c)
|
Credit facility borrowings were classified based on the termination dates of the Company's, EQM's and RMP's credit facilities.
|
(d)
|
Operating leases are primarily entered into for various office locations and warehouse buildings, as well as dedicated drilling rigs in support of the Company’s drilling program. The obligations for the Company’s various office locations and warehouse buildings totaled approximately $139.2 million as of December 31, 2017. The Company has agreements with several drillers to provide drilling equipment and services to the Company over the next four years. These obligations totaled approximately
$92.3 million
as of December 31, 2017. As of December 31, 2017, the Company had eight horizontal drilling rigs under contract, and an additional horizontal rig will become active on April 1, 2018. All of these will expire in 2019 with dates in this order: June 30, July 31, August 31 (2), September 30, October 31, November 30 and December 31 (2). The Company also had seven tophole drilling rigs under contract, six of which expire in 2018 and one that expires in 2019. Of the six tophole rigs that expire in 2018, the dates are in this order: January 3, February 3, February 25, June 2, August 27 and December 22. The expiration date for the tophole rig in 2019 is March 29. These drilling obligations have been included in the table above. The values in the table represent the gross amounts that the Company is committed to pay as operator. However, the Company will record in the Consolidated Financial Statements the Company's proportionate share of the amounts shown based on its working interest.
|
(f)
|
The other liabilities line represents commitments for total estimated payouts for the 2017 EQT Value Driver Award Program, 2017 Incentive PSU Program, 2017 restricted stock unit liability awards, 2016 EQT Value Driver Award Program and 2016 restricted stock unit liability awards. See “Critical Accounting Policies and Estimates” below and Note
18
to the Consolidated Financial Statements for further discussion regarding factors that affect the ultimate amount of the payout of these obligations.
|
|
|
Page Reference
|
|
|
|
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
(Thousands except per share amounts)
|
||||||||||
Revenues:
|
|
|
|
|
|
||||||
Sales of natural gas, oil and NGLs
|
$
|
2,651,318
|
|
|
$
|
1,594,997
|
|
|
$
|
1,690,360
|
|
Pipeline, water and net marketing services
|
336,676
|
|
|
262,342
|
|
|
263,640
|
|
|||
Gain (loss) on derivatives not designated as hedges
|
390,021
|
|
|
(248,991
|
)
|
|
385,762
|
|
|||
Total operating revenues
|
3,378,015
|
|
|
1,608,348
|
|
|
2,339,762
|
|
|||
|
|
|
|
|
|
||||||
Operating expenses:
|
|
|
|
|
|
|
|
|
|||
Transportation and processing
|
559,839
|
|
|
365,817
|
|
|
275,348
|
|
|||
Operation and maintenance
|
88,866
|
|
|
73,266
|
|
|
69,760
|
|
|||
Production
|
182,737
|
|
|
174,826
|
|
|
177,935
|
|
|||
Exploration
|
25,117
|
|
|
13,410
|
|
|
61,970
|
|
|||
Selling, general and administrative
|
262,664
|
|
|
272,747
|
|
|
249,925
|
|
|||
Depreciation, depletion and amortization
|
1,077,559
|
|
|
927,920
|
|
|
819,216
|
|
|||
Impairment of long-lived assets
|
—
|
|
|
66,687
|
|
|
122,469
|
|
|||
Acquisition costs
|
237,312
|
|
|
—
|
|
|
—
|
|
|||
Amortization of intangible assets
|
10,940
|
|
|
—
|
|
|
—
|
|
|||
Total operating expenses
|
2,445,034
|
|
|
1,894,673
|
|
|
1,776,623
|
|
|||
|
|
|
|
|
|
||||||
Gain on sale / exchange of assets
|
—
|
|
|
8,025
|
|
|
—
|
|
|||
Operating income (loss)
|
932,981
|
|
|
(278,300
|
)
|
|
563,139
|
|
|||
|
|
|
|
|
|
||||||
Other income
|
24,955
|
|
|
31,693
|
|
|
9,953
|
|
|||
Loss on debt extinguishment
|
12,641
|
|
|
—
|
|
|
—
|
|
|||
Interest expense
|
202,772
|
|
|
147,920
|
|
|
146,531
|
|
|||
Income (loss) before income taxes
|
742,523
|
|
|
(394,527
|
)
|
|
426,561
|
|
|||
Income tax (benefit) expense
|
(1,115,619
|
)
|
|
(263,464
|
)
|
|
104,675
|
|
|||
Net income (loss)
|
1,858,142
|
|
|
(131,063
|
)
|
|
321,886
|
|
|||
Less: Net income attributable to noncontrolling interests
|
349,613
|
|
|
321,920
|
|
|
236,715
|
|
|||
Net income (loss) attributable to EQT Corporation
|
$
|
1,508,529
|
|
|
$
|
(452,983
|
)
|
|
$
|
85,171
|
|
|
|
|
|
|
|
||||||
Earnings per share of common stock attributable to EQT Corporation:
|
|
|
|
|
|
|
|
|
|||
Basic:
|
|
|
|
|
|
|
|
|
|||
Weighted average common stock outstanding
|
187,380
|
|
|
166,978
|
|
|
152,398
|
|
|||
Net income (loss)
|
$
|
8.05
|
|
|
$
|
(2.71
|
)
|
|
$
|
0.56
|
|
|
|
|
|
|
|
||||||
Diluted:
|
|
|
|
|
|
|
|
|
|||
Weighted average common stock outstanding
|
187,727
|
|
|
166,978
|
|
|
152,939
|
|
|||
Net income (loss)
|
$
|
8.04
|
|
|
$
|
(2.71
|
)
|
|
$
|
0.56
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
(Thousands)
|
||||||||||
Net income (loss)
|
$
|
1,858,142
|
|
|
$
|
(131,063
|
)
|
|
$
|
321,886
|
|
|
|
|
|
|
|
||||||
Other comprehensive loss, net of tax:
|
|
|
|
|
|
|
|
|
|||
Net change in cash flow hedges:
|
|
|
|
|
|
|
|
|
|||
Natural gas, net of tax benefit of ($3,191), ($36,296) and ($102,271)
|
(4,982
|
)
|
|
(55,155
|
)
|
|
(152,359
|
)
|
|||
Interest rate, net of tax expense of $105, $104 and $100
|
144
|
|
|
144
|
|
|
144
|
|
|||
Pension and other post-retirement benefits liability adjustment, net of tax expense (benefit) of $193, $6,778 and ($564)
|
338
|
|
|
10,675
|
|
|
(901
|
)
|
|||
Other comprehensive loss
|
(4,500
|
)
|
|
(44,336
|
)
|
|
(153,116
|
)
|
|||
Comprehensive income (loss)
|
1,853,642
|
|
|
(175,399
|
)
|
|
168,770
|
|
|||
Less: Comprehensive income attributable to noncontrolling interests
|
349,613
|
|
|
321,920
|
|
|
236,715
|
|
|||
Comprehensive income (loss) attributable to EQT Corporation
|
$
|
1,504,029
|
|
|
$
|
(497,319
|
)
|
|
$
|
(67,945
|
)
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
(Thousands)
|
||||||||||
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|||
Net income (loss)
|
$
|
1,858,142
|
|
|
$
|
(131,063
|
)
|
|
$
|
321,886
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|||
Deferred income taxes
|
(1,050,612
|
)
|
|
(180,261
|
)
|
|
17,876
|
|
|||
Depreciation, depletion and amortization
|
1,077,559
|
|
|
927,920
|
|
|
819,216
|
|
|||
Amortization of intangibles
|
10,940
|
|
|
—
|
|
|
—
|
|
|||
Asset and lease impairments and exploratory well costs
|
20,327
|
|
|
75,434
|
|
|
182,242
|
|
|||
Gain on sale / exchange of assets
|
—
|
|
|
(8,025
|
)
|
|
—
|
|
|||
Loss on debt extinguishment
|
12,641
|
|
|
—
|
|
|
—
|
|
|||
(Recoveries of) provision for losses on accounts receivable
|
(979
|
)
|
|
3,856
|
|
|
(1,903
|
)
|
|||
Other income
|
(24,955
|
)
|
|
(31,693
|
)
|
|
(9,953
|
)
|
|||
Stock-based compensation expense
|
94,592
|
|
|
44,605
|
|
|
58,629
|
|
|||
(Gain) loss on derivatives not designated as hedges
|
(390,021
|
)
|
|
248,991
|
|
|
(385,762
|
)
|
|||
Cash settlements received on derivatives not designated as hedges
|
40,728
|
|
|
279,425
|
|
|
172,093
|
|
|||
Pension settlement charge
|
—
|
|
|
9,403
|
|
|
—
|
|
|||
Changes in other assets and liabilities:
|
|
|
|
|
|
|
|
|
|||
Excess tax benefits on stock-based compensation
|
—
|
|
|
(1,148
|
)
|
|
(22,945
|
)
|
|||
Accounts receivable
|
(8,979
|
)
|
|
(165,507
|
)
|
|
131,031
|
|
|||
Accounts payable
|
(16,680
|
)
|
|
40,548
|
|
|
(37,623
|
)
|
|||
Other items, net
|
14,995
|
|
|
(48,165
|
)
|
|
(27,847
|
)
|
|||
Net cash provided by operating activities
|
1,637,698
|
|
|
1,064,320
|
|
|
1,216,940
|
|
|||
|
|
|
|
|
|
||||||
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|||
Capital expenditures
|
(1,939,202
|
)
|
|
(1,538,125
|
)
|
|
(2,434,018
|
)
|
|||
Cash payments for Rice Merger (as defined in Note 2), net of cash acquired
|
(1,560,272
|
)
|
|
—
|
|
|
—
|
|
|||
Capital expenditures for other acquisitions
|
(818,957
|
)
|
|
(1,051,239
|
)
|
|
—
|
|
|||
Investments in trading securities
|
—
|
|
|
(288,772
|
)
|
|
—
|
|
|||
Sales of investments in trading securities
|
283,758
|
|
|
3,890
|
|
|
—
|
|
|||
Dry hole costs
|
(11,420
|
)
|
|
(1,369
|
)
|
|
(17,130
|
)
|
|||
Capital contributions to Mountain Valley Pipeline, LLC
|
(159,550
|
)
|
|
(98,399
|
)
|
|
(84,182
|
)
|
|||
Sales of interests in Mountain Valley Pipeline, LLC
|
—
|
|
|
12,533
|
|
|
9,723
|
|
|||
Restricted cash, net
|
75,000
|
|
|
(75,000
|
)
|
|
—
|
|
|||
Proceeds from sale of assets
|
3,573
|
|
|
75,000
|
|
|
—
|
|
|||
Net cash used in investing activities
|
(4,127,070
|
)
|
|
(2,961,481
|
)
|
|
(2,525,607
|
)
|
|||
|
|
|
|
|
|
||||||
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|||
Proceeds from the issuance of common shares of EQT Corporation, net of issuance costs
|
—
|
|
|
1,225,999
|
|
|
—
|
|
|||
Proceeds from the issuance of common units of EQT Midstream Partners, LP, net of issuance costs
|
—
|
|
|
217,102
|
|
|
1,182,002
|
|
|||
Proceeds from the sale of common units of EQT GP Holdings, LP, net of issuance costs
|
—
|
|
|
—
|
|
|
673,964
|
|
|||
Proceeds from issuance of debt
|
3,000,000
|
|
|
500,000
|
|
|
—
|
|
|||
Increase in borrowings on credit facilities
|
2,063,000
|
|
|
740,000
|
|
|
617,000
|
|
|||
Repayment of borrowings on credit facilities
|
(1,076,500
|
)
|
|
(1,039,000
|
)
|
|
(318,000
|
)
|
|||
Dividends paid
|
(20,827
|
)
|
|
(20,156
|
)
|
|
(18,310
|
)
|
|||
Distributions to noncontrolling interests
|
(236,123
|
)
|
|
(189,981
|
)
|
|
(121,759
|
)
|
|||
Contribution to Strike Force Midstream by minority owner, net of distribution
|
6,738
|
|
|
—
|
|
|
—
|
|
|||
Repayments and retirements of debt
|
(2,000,000
|
)
|
|
(5,119
|
)
|
|
(169,004
|
)
|
|||
Proceeds and excess tax benefits from awards under employee compensation plans
|
244
|
|
|
6,165
|
|
|
36,965
|
|
|||
Cash paid for taxes related to net settlement of share-based incentive awards
|
(72,116
|
)
|
|
(26,931
|
)
|
|
(47,013
|
)
|
|||
Debt issuance costs and revolving credit facility origination fees
|
(41,876
|
)
|
|
(8,580
|
)
|
|
—
|
|
|||
Premiums paid on debt extinguishment
|
(89,363
|
)
|
|
—
|
|
|
—
|
|
|||
Repurchase of common stock
|
(30
|
)
|
|
(30
|
)
|
|
(3,375
|
)
|
|||
Net cash provided by financing activities
|
1,533,147
|
|
|
1,399,469
|
|
|
1,832,470
|
|
|||
Net change in cash and cash equivalents
|
(956,225
|
)
|
|
(497,692
|
)
|
|
523,803
|
|
|||
Cash and cash equivalents at beginning of year
|
1,103,540
|
|
|
1,601,232
|
|
|
1,077,429
|
|
|||
Cash and cash equivalents at end of year
|
$
|
147,315
|
|
|
$
|
1,103,540
|
|
|
$
|
1,601,232
|
|
|
|
|
|
|
|
||||||
Cash paid (received) during the year for:
|
|
|
|
|
|
|
|
|
|||
Interest, net of amount capitalized
|
$
|
189,371
|
|
|
$
|
144,657
|
|
|
$
|
147,550
|
|
Income taxes, net
|
$
|
3,637
|
|
|
$
|
(41,142
|
)
|
|
$
|
95,708
|
|
|
2017
|
|
2016
|
||||
|
(Thousands)
|
||||||
Assets
|
|
|
|
|
|
||
Current assets:
|
|
|
|
|
|
||
Cash and cash equivalents
|
$
|
147,315
|
|
|
$
|
1,103,540
|
|
Trading securities
|
—
|
|
|
286,396
|
|
||
Accounts receivable (less accumulated provision for doubtful accounts: $8,226 in 2017; $6,923 in 2016)
|
725,236
|
|
|
341,628
|
|
||
Derivative instruments, at fair value
|
241,952
|
|
|
33,053
|
|
||
Prepaid expenses and other
|
48,552
|
|
|
63,602
|
|
||
Total current assets
|
1,163,055
|
|
|
1,828,219
|
|
||
|
|
|
|
||||
Property, plant and equipment
|
30,990,309
|
|
|
18,216,775
|
|
||
Less: accumulated depreciation and depletion
|
6,105,294
|
|
|
5,054,559
|
|
||
Net property, plant and equipment
|
24,885,015
|
|
|
13,162,216
|
|
||
|
|
|
|
||||
Restricted cash
|
—
|
|
|
75,000
|
|
||
Intangible assets, net
|
736,360
|
|
|
—
|
|
||
Goodwill
|
1,998,726
|
|
|
—
|
|
||
Investment in unconsolidated entity
|
460,546
|
|
|
184,562
|
|
||
Other assets
|
278,902
|
|
|
222,925
|
|
||
Total assets
|
$
|
29,522,604
|
|
|
$
|
15,472,922
|
|
|
2017
|
|
2016
|
||||
|
(Thousands)
|
||||||
Liabilities and Shareholders’ Equity
|
|
|
|
|
|
||
Current liabilities:
|
|
|
|
|
|
||
Current portion of Senior Notes
|
$
|
7,999
|
|
|
$
|
—
|
|
Accounts payable
|
654,624
|
|
|
309,978
|
|
||
Derivative instruments, at fair value
|
139,089
|
|
|
257,943
|
|
||
Other current liabilities
|
430,525
|
|
|
236,719
|
|
||
Total current liabilities
|
1,232,237
|
|
|
804,640
|
|
||
|
|
|
|
||||
Credit facility borrowings
|
1,761,000
|
|
|
—
|
|
||
Senior Notes
|
5,562,555
|
|
|
3,289,459
|
|
||
Deferred income taxes
|
1,768,900
|
|
|
1,760,004
|
|
||
Other liabilities and credits
|
783,299
|
|
|
499,572
|
|
||
Total liabilities
|
11,107,991
|
|
|
6,353,675
|
|
||
|
|
|
|
||||
Equity:
|
|
|
|
|
|
||
Shareholders’ equity
|
|
|
|
|
|
||
Common stock, no par value, authorized 320,000 shares, shares issued: 267,871 in 2017 and 177,896 in 2016
|
9,388,903
|
|
|
3,440,185
|
|
||
Treasury stock, shares at cost: 3,551 in 2017 (including 253 held in rabbi trust) and 5,069 in 2016 (including 226 held in rabbi trust)
|
(63,602
|
)
|
|
(91,019
|
)
|
||
Retained earnings
|
3,996,775
|
|
|
2,509,073
|
|
||
Accumulated other comprehensive (loss) income
|
(2,458
|
)
|
|
2,042
|
|
||
Total common shareholders’ equity
|
13,319,618
|
|
|
5,860,281
|
|
||
Noncontrolling interests in consolidated subsidiaries
|
5,094,995
|
|
|
3,258,966
|
|
||
Total equity
|
18,414,613
|
|
|
9,119,247
|
|
||
Total liabilities and equity
|
$
|
29,522,604
|
|
|
$
|
15,472,922
|
|
|
Common Stock
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Shares
Outstanding |
|
No
Par Value |
|
Retained
Earnings |
|
Accumulated
Other Comprehensive Income (Loss) |
|
Noncontrolling
Interests in Consolidated Subsidiaries |
|
Total
Equity |
|||||||||||
|
|
|
|
|
(Thousands)
|
|
|
|
|
|||||||||||||
Balance, December 31, 2014
|
151,596
|
|
|
$
|
1,466,192
|
|
|
$
|
2,917,129
|
|
|
$
|
199,494
|
|
|
$
|
1,790,248
|
|
|
$
|
6,373,063
|
|
Comprehensive income (net of tax):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Net income
|
|
|
|
|
|
|
85,171
|
|
|
|
|
|
236,715
|
|
|
321,886
|
|
|||||
Net change in cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Natural gas, net of tax of ($102,271)
|
|
|
|
|
|
|
|
|
|
(152,359
|
)
|
|
|
|
|
(152,359
|
)
|
|||||
Interest rate, net of tax of $100
|
|
|
|
|
|
|
|
|
|
144
|
|
|
|
|
|
144
|
|
|||||
Pension and other post-retirement benefits liability adjustment, net of tax of ($564)
|
|
|
|
|
|
|
|
|
|
(901
|
)
|
|
|
|
|
(901
|
)
|
|||||
Dividends ($0.12 per share)
|
|
|
|
|
|
|
(18,310
|
)
|
|
|
|
|
|
|
|
(18,310
|
)
|
|||||
Stock-based compensation plans, net
|
996
|
|
|
77,378
|
|
|
|
|
|
|
|
|
1,056
|
|
|
78,434
|
|
|||||
Distributions to noncontrolling interests ($2.505 and $0.15139 per common unit for EQT Midstream Partners, LP and EQT GP Holdings, LP, respectively)
|
|
|
|
|
|
|
|
|
(121,759
|
)
|
|
(121,759
|
)
|
|||||||||
Sale of common units of EQT GP Holdings, LP
|
|
|
|
|
|
|
|
|
673,964
|
|
|
673,964
|
|
|||||||||
Issuance of common units of EQT Midstream Partners, LP
|
|
|
|
|
|
|
|
|
1,182,002
|
|
|
1,182,002
|
|
|||||||||
Changes in ownership of consolidated subsidiaries
|
|
|
507,228
|
|
|
|
|
|
|
(811,975
|
)
|
|
(304,747
|
)
|
||||||||
Repurchase and retirement of common stock
|
(38
|
)
|
|
(1,597
|
)
|
|
$
|
(1,778
|
)
|
|
|
|
|
|
(3,375
|
)
|
||||||
Balance, December 31, 2015
|
152,554
|
|
|
$
|
2,049,201
|
|
|
$
|
2,982,212
|
|
|
$
|
46,378
|
|
|
$
|
2,950,251
|
|
|
$
|
8,028,042
|
|
Comprehensive income (net of tax):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Net (loss) income
|
|
|
|
|
|
|
(452,983
|
)
|
|
|
|
|
321,920
|
|
|
(131,063
|
)
|
|||||
Net change in cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Natural gas, net of tax of ($36,296)
|
|
|
|
|
|
|
|
|
|
(55,155
|
)
|
|
|
|
|
(55,155
|
)
|
|||||
Interest rate, net of tax of $104
|
|
|
|
|
|
|
|
|
|
144
|
|
|
|
|
|
144
|
|
|||||
Pension and other post-retirement benefits liability adjustment, net of tax of $6,778
|
|
|
|
|
|
|
|
|
|
10,675
|
|
|
|
|
|
10,675
|
|
|||||
Dividends ($0.12 per share)
|
|
|
|
|
|
|
(20,156
|
)
|
|
|
|
|
|
|
|
(20,156
|
)
|
|||||
Stock-based compensation plans, net
|
724
|
|
|
42,782
|
|
|
|
|
|
|
|
|
161
|
|
|
42,943
|
|
|||||
Distributions to noncontrolling interests ($3.05 and $0.571 per common unit for EQT Midstream Partners, LP and EQT GP Holdings, LP, respectively)
|
|
|
|
|
|
|
|
|
|
|
|
|
(189,981
|
)
|
|
(189,981
|
)
|
|||||
Issuance of common shares of EQT Corporation
|
19,550
|
|
|
1,225,999
|
|
|
|
|
|
|
|
|
1,225,999
|
|
||||||||
Issuance of common units of EQT Midstream Partners, LP
|
|
|
|
|
|
|
|
|
|
|
|
|
217,102
|
|
|
217,102
|
|
|||||
Elimination of deferred taxes
|
|
|
5,921
|
|
|
|
|
|
|
|
|
|
5,921
|
|
||||||||
Changes in ownership of consolidated subsidiaries
|
|
|
25,293
|
|
|
|
|
|
|
(40,487
|
)
|
|
(15,194
|
)
|
||||||||
Repurchase and retirement of common stock
|
(1
|
)
|
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
|
(30
|
)
|
|||||
Balance, December 31, 2016
|
172,827
|
|
|
$
|
3,349,166
|
|
|
$
|
2,509,073
|
|
|
$
|
2,042
|
|
|
$
|
3,258,966
|
|
|
$
|
9,119,247
|
|
Comprehensive income (net of tax):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Net income
|
|
|
|
|
|
|
1,508,529
|
|
|
|
|
|
349,613
|
|
|
1,858,142
|
|
|||||
Net change in cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Natural gas, net of tax of ($3,191)
|
|
|
|
|
|
|
|
|
|
(4,982
|
)
|
|
|
|
|
(4,982
|
)
|
|||||
Interest rate, net of tax of $105
|
|
|
|
|
|
|
|
|
|
144
|
|
|
|
|
|
144
|
|
|||||
Pension and other post-retirement benefits liability adjustment, net of tax of $193
|
|
|
|
|
|
|
|
|
|
338
|
|
|
|
|
|
338
|
|
|||||
Dividends ($0.12 per share)
|
|
|
|
|
|
|
(20,827
|
)
|
|
|
|
|
|
|
|
(20,827
|
)
|
|||||
Stock-based compensation plans, net
|
580
|
|
|
26,436
|
|
|
|
|
|
|
|
|
190
|
|
|
26,626
|
|
|||||
Distributions to noncontrolling interests ($3.655 and $0.806 per common unit for EQT Midstream Partners, LP and EQT GP Holdings, LP, respectively)
|
|
|
|
|
|
|
|
|
|
|
|
|
(236,123
|
)
|
|
(236,123
|
)
|
|||||
Rice Merger, net of withholdings
|
90,914
|
|
|
5,949,729
|
|
|
|
|
|
|
1,715,611
|
|
|
7,665,340
|
|
|||||||
Contribution from noncontrolling interest, net of distribution
|
|
|
|
|
|
|
|
|
6,738
|
|
|
6,738
|
|
|||||||||
Repurchase of common stock
|
(1
|
)
|
|
(30
|
)
|
|
|
|
|
|
|
|
(30
|
)
|
||||||||
Balance, December 31, 2017
|
264,320
|
|
|
$
|
9,325,301
|
|
|
$
|
3,996,775
|
|
|
$
|
(2,458
|
)
|
|
$
|
5,094,995
|
|
|
$
|
18,414,613
|
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(Thousands)
|
||||||
Oil and gas producing properties, successful efforts method
|
$
|
23,937,154
|
|
|
$
|
13,878,659
|
|
Accumulated depreciation and depletion
|
(5,121,646
|
)
|
|
(4,217,154
|
)
|
||
Net oil and gas producing properties
|
18,815,508
|
|
|
9,661,505
|
|
||
Gathering assets
|
2,765,763
|
|
|
1,330,998
|
|
||
Accumulated depreciation and amortization
|
(151,595
|
)
|
|
(110,473
|
)
|
||
Net gathering assets
|
2,614,168
|
|
|
1,220,525
|
|
||
Transmission assets
|
1,674,080
|
|
|
1,563,860
|
|
||
Accumulated depreciation and amortization
|
(248,474
|
)
|
|
(205,551
|
)
|
||
Net transmission assets
|
1,425,606
|
|
|
1,358,309
|
|
||
Water service assets
|
193,825
|
|
|
—
|
|
||
Accumulated depreciation and amortization
|
(3,363
|
)
|
|
—
|
|
||
Net water service assets
|
190,462
|
|
|
—
|
|
||
Other properties, at cost less accumulated depreciation (a)
|
1,839,271
|
|
|
921,877
|
|
||
Net property, plant and equipment
|
$
|
24,885,015
|
|
|
$
|
13,162,216
|
|
(in thousands)
|
December 31, 2017
|
||
Customer relationships
|
$
|
623,200
|
|
Less: accumulated amortization for customer relationships
|
(5,540
|
)
|
|
Non-compete agreements
|
124,100
|
|
|
Less: accumulated amortization for non-compete agreements
|
(5,400
|
)
|
|
Intangible assets, net
|
$
|
736,360
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(Thousands)
|
||||||||||
Net revenues
|
$
|
390,883
|
|
|
$
|
347,320
|
|
|
$
|
309,984
|
|
Operating expenses
|
$
|
151,510
|
|
|
$
|
118,611
|
|
|
$
|
109,954
|
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(Thousands)
|
||||||
Property, plant & equipment
|
$
|
1,787,656
|
|
|
$
|
1,675,433
|
|
Accumulated depreciation and amortization
|
(278,756
|
)
|
|
(234,336
|
)
|
||
Net property, plant & equipment
|
$
|
1,508,900
|
|
|
$
|
1,441,097
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(Thousands)
|
||||||
Mountain Valley Pipeline, LLC capital call
|
$
|
105,734
|
|
|
$
|
11,471
|
|
Incentive compensation
|
91,363
|
|
|
100,762
|
|
||
Taxes other than income
|
78,749
|
|
|
56,874
|
|
||
Accrued interest payable
|
52,993
|
|
|
39,593
|
|
||
Severance accrual
|
41,474
|
|
|
338
|
|
||
All other accrued liabilities
|
60,212
|
|
|
27,681
|
|
||
Total other current liabilities
|
$
|
430,525
|
|
|
$
|
236,719
|
|
|
Years Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(Thousands)
|
||||||
Asset retirement obligation as of beginning of period
|
$
|
243,600
|
|
|
$
|
168,142
|
|
Accretion expense
|
13,679
|
|
|
9,696
|
|
||
Liabilities incurred
|
19,678
|
|
|
2,943
|
|
||
Liabilities settled
|
(3,838
|
)
|
|
(1,484
|
)
|
||
Liabilities assumed in Rice Merger
|
50,941
|
|
|
—
|
|
||
Change in estimates
|
128,610
|
|
|
64,303
|
|
||
Asset retirement obligation as of end of period
|
$
|
452,670
|
|
|
$
|
243,600
|
|
(in thousands)
|
Preliminary Purchase Price Allocation
|
||
Consideration Given:
|
|
||
Equity consideration
|
$
|
5,943,289
|
|
Cash consideration
|
1,299,407
|
|
|
Buyout of preferred equity in Rice Midstream Holdings
|
429,708
|
|
|
Buyout of Common Units in RMGP
|
125,828
|
|
|
Settlement of pre-existing relationships
|
(14,699
|
)
|
|
Total consideration
|
7,783,533
|
|
|
|
|
||
Fair value of liabilities assumed:
|
|
||
Current liabilities
|
566,774
|
|
|
Long-term debt
|
2,151,656
|
|
|
Deferred income taxes
|
1,106,000
|
|
|
Other long term liabilities
|
67,533
|
|
|
Amount attributable to liabilities assumed
|
3,891,963
|
|
|
|
|
||
Fair value of assets acquired:
|
|
||
Cash
|
294,671
|
|
|
Accounts receivable
|
337,007
|
|
|
Current assets
|
109,465
|
|
|
Net property, plant and equipment
|
9,903,938
|
|
|
Intangible assets
|
747,300
|
|
|
Noncontrolling interests
|
(1,715,611
|
)
|
|
Amount attributable to assets acquired
|
9,676,770
|
|
|
Goodwill as of December 31, 2017
|
$
|
1,998,726
|
|
(in thousands)
|
|
||
Revenue attributable to EQT
|
$
|
323,414
|
|
Net income attributable to noncontrolling interests
|
$
|
16,644
|
|
Net income attributable to EQT
|
$
|
529,743
|
|
|
For the year ended December 31,
|
||||||
(in thousands, except per share data) (unaudited)
|
2017
|
|
2016
|
||||
Pro forma operating revenues
|
$
|
4,809,757
|
|
|
$
|
2,288,605
|
|
Pro forma net income (loss)
|
$
|
2,197,041
|
|
|
$
|
(528,786
|
)
|
Pro forma net income attributable to noncontrolling interests
|
$
|
(444,248
|
)
|
|
$
|
(401,149
|
)
|
Pro forma net income (loss) attributable to EQT
|
$
|
1,752,793
|
|
|
$
|
(929,935
|
)
|
Pro forma income (loss) per share (basic)
|
$
|
6.30
|
|
|
$
|
(3.59
|
)
|
Pro forma income (loss) per share (diluted)
|
$
|
6.29
|
|
|
$
|
(3.59
|
)
|
|
|
Common Units Issued
|
|
GP Units Issued
|
|
Price Per Unit
|
|
Net Proceeds
|
|
Underwriters' Discount and Other Offering Expenses
|
||||||||
|
|
(Thousands, except unit and per unit amounts)
|
||||||||||||||||
March 2015 equity offering
(a)
|
|
9,487,500
|
|
|
25,255
|
|
|
$
|
76.00
|
|
|
$
|
696,582
|
|
|
$
|
24,468
|
|
$750 million At the Market (ATM) Program in 2015
(b)
|
|
1,162,475
|
|
|
—
|
|
|
74.92
|
|
|
85,483
|
|
|
1,610
|
|
|||
November 2015 equity offering
(c)
|
|
5,650,000
|
|
|
—
|
|
|
71.80
|
|
|
399,937
|
|
|
5,733
|
|
|||
$750 million ATM Program in 2016
(d)
|
|
2,949,309
|
|
|
—
|
|
|
$
|
74.42
|
|
|
$
|
217,102
|
|
|
$
|
2,381
|
|
(a)
|
The underwriters exercised their option to purchase additional common units. EQM Midstream Services, LLC, the general partner of EQM (the EQM General Partner), purchased
25,255
EQM general partner units for approximately
$1.9 million
to maintain its then
2.0%
general partner ownership percentage. In connection with the offering, the Company recorded a
$122.3 million
gain to additional paid-in-capital, a decrease in noncontrolling interest in consolidated subsidiary of
$195.8 million
and an increase to deferred tax liability of
$73.5 million
. EQM used the proceeds from the offering to fund a portion of the purchase price for the NWV Gathering Transaction discussed below.
|
(b)
|
In 2015, EQM entered into an equity distribution agreement that established an "At the Market" (ATM) common unit offering program, pursuant to which a group of managers, acting as EQM's sales agents, may sell EQM common units having an aggregate offering price of up to
$750 million
(the
$750 million
ATM Program). The price per unit represents an average price for all issuances under the
$750 million
ATM Program in 2015. The underwriters' discount and other offering expenses in the table include commissions of approximately
$0.9 million
and other offering expenses of approximately
$0.7 million
. In connection with the offerings, the Company recorded a
$12.4 million
gain to additional
|
(c)
|
EQM used the net proceeds for general partnership purposes and to repay amounts outstanding under EQM's revolving credit facility. In connection with the offering, the Company recorded a
$52.1 million
gain to additional paid-in-capital, a decrease in noncontrolling interest in consolidated subsidiary of
$83.5 million
and an increase to deferred tax liability of
$31.3 million
.
|
(d)
|
The price per unit represents an average price for all issuances under the
$750 million
ATM Program in 2016. The underwriters' discount and offering expenses in the table include commissions of approximately
$2.2 million
. In connection with these sales, the Company recorded a
$24.9 million
gain to additional paid-in-capital, a decrease in noncontrolling interest in consolidated subsidiary of
$39.9 million
and an increase to deferred tax liability of
$15.0 million
. EQM used the net proceeds for general partnership purposes.
|
Year Ended December 31, 2017
|
EQT Production
|
|
EQM Gathering
|
|
EQM Transmission
|
|
RMP Gathering
|
|
RMP Water
|
|
Intersegment Eliminations
|
|
EQT Corporation
|
||||||||||||||
|
(Thousands)
|
||||||||||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Sales of natural gas, oil and NGLs
|
$
|
2,651,318
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,651,318
|
|
Pipeline, water and net marketing services
|
64,998
|
|
|
454,536
|
|
|
379,560
|
|
|
30,614
|
|
|
13,605
|
|
|
(606,637
|
)
|
|
336,676
|
|
|||||||
Gain on derivatives not designated as hedges
|
390,021
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
390,021
|
|
|||||||
Total operating revenues
|
$
|
3,106,337
|
|
|
$
|
454,536
|
|
|
$
|
379,560
|
|
|
$
|
30,614
|
|
|
$
|
13,605
|
|
|
$
|
(606,637
|
)
|
|
$
|
3,378,015
|
|
Year Ended December 31, 2016
|
EQT Production
|
|
EQM Gathering
|
|
EQM Transmission
|
|
Intersegment Eliminations
|
|
EQT Corporation
|
||||||||||
|
(Thousands)
|
||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales of natural gas, oil and NGLs
|
$
|
1,594,997
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,594,997
|
|
Pipeline and net marketing services
|
41,048
|
|
|
397,494
|
|
|
338,120
|
|
|
(514,320
|
)
|
|
262,342
|
|
|||||
Loss on derivatives not designated as hedges
|
(248,991
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(248,991
|
)
|
|||||
Total operating revenues
|
$
|
1,387,054
|
|
|
$
|
397,494
|
|
|
$
|
338,120
|
|
|
$
|
(514,320
|
)
|
|
$
|
1,608,348
|
|
Year Ended December 31, 2015
|
EQT Production
|
|
EQM Gathering
|
|
EQM Transmission
|
|
Intersegment Eliminations
|
|
EQT Corporation
|
||||||||||
|
(Thousands)
|
||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales of natural gas, oil and NGLs
|
$
|
1,690,360
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,690,360
|
|
Pipeline and net marketing services
|
55,542
|
|
|
335,105
|
|
|
297,831
|
|
|
(424,838
|
)
|
|
263,640
|
|
|||||
Gain on derivatives not designated as hedges
|
385,762
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
385,762
|
|
|||||
Total operating revenues
|
$
|
2,131,664
|
|
|
$
|
335,105
|
|
|
$
|
297,831
|
|
|
$
|
(424,838
|
)
|
|
$
|
2,339,762
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
|
|
|
(Thousands)
|
|
|
|
||||
Operating income (loss):
|
|
|
|
|
|
|
|
|
|
|||
EQT Production (a)
|
|
$
|
589,716
|
|
|
$
|
(719,731
|
)
|
|
$
|
132,008
|
|
EQM Gathering
|
|
333,563
|
|
|
289,027
|
|
|
243,257
|
|
|||
EQM Transmission
|
|
247,145
|
|
|
237,922
|
|
|
207,779
|
|
|||
RMP Gathering (b)
|
|
21,800
|
|
|
—
|
|
|
—
|
|
|||
RMP Water (b)
|
|
4,145
|
|
|
—
|
|
|
—
|
|
|||
Unallocated expenses (c)
|
|
(263,388
|
)
|
|
(85,518
|
)
|
|
(19,905
|
)
|
|||
Total operating income (loss)
|
|
$
|
932,981
|
|
|
$
|
(278,300
|
)
|
|
$
|
563,139
|
|
|
|
|
|
|
|
|
||||||
Reconciliation of operating income (loss) to net income (loss):
|
||||||||||||
Total operating income (loss)
|
|
$
|
932,981
|
|
|
$
|
(278,300
|
)
|
|
$
|
563,139
|
|
Other income
|
|
24,955
|
|
|
31,693
|
|
|
9,953
|
|
|||
Loss on debt extinguishment
|
|
12,641
|
|
|
—
|
|
|
—
|
|
|||
Interest expense
|
|
202,772
|
|
|
147,920
|
|
|
146,531
|
|
|||
Income tax (benefit) expense
|
|
(1,115,619
|
)
|
|
(263,464
|
)
|
|
104,675
|
|
|||
Net income (loss)
|
|
$
|
1,858,142
|
|
|
$
|
(131,063
|
)
|
|
$
|
321,886
|
|
(a)
|
For the year ended December 31, 2017, the operating income for EQT Production includes the results of operations for the production operations and retained midstream operations acquired in the Rice Merger for the period of
November 13, 2017
through December 31, 2017. See Note
2
for a discussion of the Rice Merger. Gains on sales / exchanges of assets of
$8.0 million
are included in EQT Production operating income for 2016. See Note
9
. Impairment of long-lived assets of
$6.9 million
and
$122.5 million
are included in EQT Production operating income for 2016 and 2015, respectively. See Note
1
for a discussion of impairment of long-lived assets.
|
(b)
|
Operating income for RMP Gathering and RMP Water, both acquired in the Rice Merger, includes the results of operations for the period of
November 13, 2017
through December 31, 2017. See Note
2
for a discussion of the Rice Merger.
|
(c)
|
Unallocated expenses generally include incentive compensation expense and administrative costs. In addition, 2017 includes
$237.3 million
of Rice Merger related expenses and 2016 includes a
$59.7 million
impairment on gathering assets prior to the sale to EQM.
|
|
|
As of December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Segment assets:
|
|
|
|
|
|
|
|
|
||||
EQT Production
|
|
$
|
22,711,854
|
|
|
$
|
10,923,824
|
|
|
$
|
9,905,344
|
|
EQM Gathering
|
|
1,411,857
|
|
|
1,225,686
|
|
|
1,019,004
|
|
|||
EQM Transmission
|
|
1,462,881
|
|
|
1,399,201
|
|
|
1,169,517
|
|
|||
RMP Gathering
|
|
2,720,305
|
|
|
—
|
|
|
—
|
|
|||
RMP Water
|
|
185,079
|
|
|
—
|
|
|
—
|
|
|||
Total operating segments
|
|
28,491,976
|
|
|
13,548,711
|
|
|
12,093,865
|
|
|||
Headquarters assets, including cash and short-term investments
|
|
1,030,628
|
|
|
1,924,211
|
|
|
1,882,307
|
|
|||
Total assets
|
|
$
|
29,522,604
|
|
|
$
|
15,472,922
|
|
|
$
|
13,976,172
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
|
|
(Thousands)
|
|
|
||||||
Depreciation, depletion and amortization: (d)
|
|
|
|
|
|
|
|
|
|
|||
EQT Production (e)
|
|
$
|
982,103
|
|
|
$
|
859,018
|
|
|
$
|
765,298
|
|
EQM Gathering
|
|
38,796
|
|
|
30,422
|
|
|
24,360
|
|
|||
EQM Transmission (g)
|
|
58,689
|
|
|
32,269
|
|
|
25,535
|
|
|||
RMP Gathering (f)
|
|
3,965
|
|
|
—
|
|
|
—
|
|
|||
RMP Water (f)
|
|
3,515
|
|
|
—
|
|
|
—
|
|
|||
Other (g)
|
|
(9,509
|
)
|
|
6,211
|
|
|
4,023
|
|
|||
Total
|
|
$
|
1,077,559
|
|
|
$
|
927,920
|
|
|
$
|
819,216
|
|
|
|
|
|
|
|
|
||||||
Expenditures for segment assets: (h)
|
|
|
|
|
|
|
|
|
|
|||
EQT Production (e) (i)
|
|
$
|
2,430,094
|
|
|
$
|
2,073,907
|
|
|
$
|
1,893,750
|
|
EQM Gathering
|
|
196,871
|
|
|
295,315
|
|
|
225,537
|
|
|||
EQM Transmission
|
|
111,102
|
|
|
292,049
|
|
|
203,706
|
|
|||
RMP Gathering (f) (j)
|
|
28,320
|
|
|
—
|
|
|
—
|
|
|||
RMP Water (f) (j)
|
|
6,233
|
|
|
—
|
|
|
—
|
|
|||
Other
|
|
6,080
|
|
|
7,002
|
|
|
21,421
|
|
|||
Total
|
|
$
|
2,778,700
|
|
|
$
|
2,668,273
|
|
|
$
|
2,344,414
|
|
(e)
|
For the year ended December 31, 2017, depreciation, depletion and amortization expense and expenditures for segment assets for EQT Production includes activity for the production operations and retained midstream operations acquired in the Rice Merger for the period of
November 13, 2017
through December 31, 2017. See Note
2
for a discussion of the Rice Merger.
|
(f)
|
Depreciation, depletion and amortization expense and expenditures for segment assets for RMP Gathering and RMP Water, both acquired in the Rice Merger, includes activity for the period of
November 13, 2017
through December 31, 2017. See Note
2
for a discussion of the Rice Merger.
|
(g)
|
Depreciation, depletion and amortization expense for EQM Transmission includes a non-cash charge of
$10.5 million
related to the revaluation of differences between the regulatory and tax bases in EQM's regulated property, plant and equipment. For purposes of consolidated reporting at EQT, the
$10.5 million
is recorded to income tax expense. This reclass is shown as a reduction of other depreciation, depletion and amortization expense.
|
(h)
|
Includes the capitalized portion of non-cash stock-based compensation costs, non-cash acquisitions and the impact of capital accruals. These non-cash items are excluded from capital expenditures on the statements of consolidated cash flows. The net impact of these non-cash items was
$9.1 million
,
$76.5 million
and
$(89.6) million
for the years ended December 31,
2017
,
2016
and
2015
, respectively. The impact of accrued capital expenditures includes the reversal of the prior period accrual as well as the current period estimate, both of which are non-cash items. The year ended December 31, 2017 included
$10.0 million
of non-cash capital expenditures related to 2017 acquisitions and
$(14.3) million
of measurement period adjustments for 2016 acquisitions. The year ended December 31, 2016 included
$87.6 million
of non-cash capital expenditures related to 2016 acquisitions. See Note
10
for discussion of the 2017 and 2016 acquisitions. Expenditures for segment assets does not include consideration for the Rice Merger.
|
(j)
|
Expenditures for segment assets in the RMP Gathering and RMP Water segments included
$17.1 million
in cash paid by EQT for capital expenditures accrued as of the opening balance sheet date of the Rice Merger.
|
As of December 31, 2017
|
|
Derivative
instruments,
recorded in the
Consolidated
Balance
Sheet, gross
|
|
Derivative
instruments
subject to
master
netting
agreements
|
|
Margin
deposits
remitted to
counterparties
|
|
Derivative
instruments,
net
|
||||||||
|
|
(Thousands)
|
||||||||||||||
Asset derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Derivative instruments, at fair value
|
|
$
|
241,952
|
|
|
$
|
(86,856
|
)
|
|
$
|
—
|
|
|
$
|
155,096
|
|
Liability derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Derivative instruments, at fair value
|
|
$
|
139,089
|
|
|
$
|
(86,856
|
)
|
|
$
|
—
|
|
|
$
|
52,233
|
|
As of December 31, 2016
|
|
Derivative
instruments,
recorded in the
Consolidated
Balance
Sheet, gross
|
|
Derivative
instruments
subject to
master
netting
agreements
|
|
Margin
deposits
remitted to
counterparties
|
|
Derivative
instruments,
net
|
||||||||
|
|
(Thousands)
|
||||||||||||||
Asset derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Derivative instruments, at fair value
|
|
$
|
33,053
|
|
|
$
|
(23,373
|
)
|
|
$
|
—
|
|
|
$
|
9,680
|
|
Liability derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Derivative instruments, at fair value
|
|
$
|
257,943
|
|
|
$
|
(23,373
|
)
|
|
$
|
—
|
|
|
$
|
234,570
|
|
|
|
|
|
Fair value measurements at reporting date using
|
||||||||||||
Description
|
|
As of
December 31, 2017
|
|
Quoted prices
in active
markets for
identical
assets
(Level 1)
|
|
Significant
other
observable
inputs
(Level 2)
|
|
Significant
unobservable
inputs
(Level 3)
|
||||||||
|
|
(Thousands)
|
||||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Derivative instruments, at fair value
|
|
$
|
241,952
|
|
|
$
|
—
|
|
|
$
|
241,952
|
|
|
$
|
—
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Derivative instruments, at fair value
|
|
$
|
139,089
|
|
|
$
|
—
|
|
|
$
|
139,089
|
|
|
$
|
—
|
|
|
|
|
|
Fair value measurements at reporting date using
|
||||||||||||
Description
|
|
As of
December 31, 2016
|
|
Quoted prices
in active
markets for
identical
assets
(Level 1)
|
|
Significant
other
observable
inputs
(Level 2)
|
|
Significant
unobservable
inputs
(Level 3)
|
||||||||
|
|
(Thousands)
|
||||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Trading securities
|
|
$
|
286,396
|
|
|
$
|
—
|
|
|
$
|
286,396
|
|
|
$
|
—
|
|
Derivative instruments, at fair value
|
|
$
|
33,053
|
|
|
$
|
—
|
|
|
$
|
33,053
|
|
|
$
|
—
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Derivative instruments, at fair value
|
|
$
|
257,943
|
|
|
$
|
—
|
|
|
$
|
257,943
|
|
|
$
|
—
|
|
•
|
On July 8, 2016, the Company acquired approximately
62,500
net Marcellus acres and
31
Marcellus wells,
24
of which were producing, from Statoil USA Onshore Properties, Inc. (the Statoil Acquisition). The net acres acquired are primarily located in Wetzel, Tyler and Harrison Counties of West Virginia.
|
•
|
In the fourth quarter of 2016, the Company acquired approximately
42,600
net Marcellus acres and
42
Marcellus wells,
32
of which were producing at the time of the acquisition, which were being jointly developed by Trans Energy, Inc. (Trans Energy) and Republic Energy Ventures, LLC and its affiliates (collectively, Republic). The net acres acquired are primarily located in Wetzel, Marshall and Marion Counties of West Virginia. The acquisitions were effected through simultaneous transaction agreements that were executed on October 24, 2016 including: (i) a purchase and sale agreement between the Company and Republic; and (ii) an agreement and plan of merger among the Company, a wholly owned subsidiary of the Company (TE Merger Sub) and Trans Energy. The Republic acquisition closed on November 3, 2016 (the Republic Transaction). On October 27, 2016, the Company commenced a tender offer, through its wholly owned subsidiary, to acquire the outstanding shares of common stock of Trans Energy, a publicly traded company, at an offer price of
$3.58
per share in cash. Following the tender offer on December 5, 2016, TE Merger Sub merged with and into Trans Energy, at which time Trans Energy became an indirect wholly owned subsidiary of the Company (the Trans Energy Merger).
|
•
|
On December 16, 2016, the Company acquired approximately
17,000
net Marcellus acres located in Washington, Westmoreland and Greene Counties of Pennsylvania, and
two
related Marcellus wells both of which were producing (the 2016 Pennsylvania Acquisition).
|
•
|
On February 1, 2017, the Company acquired approximately
14,000
net Marcellus acres located in Marion, Monongalia and Wetzel Counties of West Virginia from a third party.
|
•
|
On February 27, 2017, the Company acquired approximately
85,000
net Marcellus acres, including drilling rights on approximately
44,000
net Utica acres and current natural gas production of approximately
110
MMcfe per day, from Stone Energy Corporation. The acquired acres are primarily located in Wetzel, Marshall, Tyler and Marion Counties of West Virginia. The acquired assets also included
174
Marcellus wells,
120
of which were producing at the time of the acquisition, and
20
miles of gathering pipeline.
|
•
|
On June 30, 2017, the Company acquired approximately
11,000
net Marcellus acres, and the associated Utica drilling rights, from a third party. The acquired acres are primarily located in Allegheny, Washington and Westmoreland Counties of Pennsylvania.
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Current:
|
|
|
|
|
|
|
|
|
|
|||
Federal
|
|
$
|
(65,034
|
)
|
|
$
|
(82,905
|
)
|
|
$
|
85,696
|
|
State
|
|
27
|
|
|
(298
|
)
|
|
1,103
|
|
|||
Subtotal
|
|
(65,007
|
)
|
|
(83,203
|
)
|
|
86,799
|
|
|||
Deferred:
|
|
|
|
|
|
|
|
|
|
|||
Federal
|
|
(998,483
|
)
|
|
(117,155
|
)
|
|
(109,642
|
)
|
|||
State
|
|
(52,129
|
)
|
|
(63,106
|
)
|
|
127,518
|
|
|||
Subtotal
|
|
(1,050,612
|
)
|
|
(180,261
|
)
|
|
17,876
|
|
|||
Total income taxes
|
|
$
|
(1,115,619
|
)
|
|
$
|
(263,464
|
)
|
|
$
|
104,675
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Tax at statutory rate
|
|
$
|
259,884
|
|
|
$
|
(138,084
|
)
|
|
$
|
149,296
|
|
Federal tax reform
|
|
(1,205,140
|
)
|
|
—
|
|
|
—
|
|
|||
State income taxes
|
|
(52,606
|
)
|
|
(71,613
|
)
|
|
(7,566
|
)
|
|||
Valuation allowance
|
|
10,680
|
|
|
23,808
|
|
|
91,144
|
|
|||
Noncontrolling partners’ share of earnings
|
|
(122,365
|
)
|
|
(112,672
|
)
|
|
(82,850
|
)
|
|||
Regulatory liability/asset
|
|
10,488
|
|
|
35,438
|
|
|
(35,438
|
)
|
|||
Federal tax credits
|
|
(34,956
|
)
|
|
(4,539
|
)
|
|
(7,243
|
)
|
|||
Other
|
|
18,396
|
|
|
4,198
|
|
|
(2,668
|
)
|
|||
Income tax (benefit) expense
|
|
$
|
(1,115,619
|
)
|
|
$
|
(263,464
|
)
|
|
$
|
104,675
|
|
Effective tax rate
|
|
(150.2
|
)%
|
|
66.8
|
%
|
|
24.5
|
%
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Balance at January 1
|
|
$
|
252,434
|
|
|
$
|
259,301
|
|
|
$
|
56,957
|
|
Additions based on tax positions related to current year
|
|
50,469
|
|
|
23,978
|
|
|
152,983
|
|
|||
Additions for tax positions of prior years
|
|
8,978
|
|
|
20,336
|
|
|
50,688
|
|
|||
Reductions for tax positions of prior years
|
|
(10,323
|
)
|
|
(51,181
|
)
|
|
(1,327
|
)
|
|||
Lapse of statute of limitations
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Balance at December 31
|
|
$
|
301,558
|
|
|
$
|
252,434
|
|
|
$
|
259,301
|
|
|
|
As of December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
|
|
(Thousands)
|
||||||
Deferred income taxes:
|
|
|
|
|
|
|
||
Total deferred income tax assets
|
|
$
|
(971,184
|
)
|
|
$
|
(875,303
|
)
|
Total deferred income tax liabilities
|
|
2,740,084
|
|
|
2,635,307
|
|
||
Total net deferred income tax liabilities
|
|
1,768,900
|
|
|
1,760,004
|
|
||
Total deferred income tax liabilities (assets):
|
|
|
|
|
|
|
||
Drilling and development costs expensed for income tax reporting
|
|
2,074,091
|
|
|
1,473,355
|
|
||
Tax depreciation in excess of book depreciation
|
|
644,590
|
|
|
1,161,952
|
|
||
Incentive compensation and deferred compensation plans
|
|
(43,822
|
)
|
|
(77,743
|
)
|
||
Net operating loss carryforwards
|
|
(564,180
|
)
|
|
(282,943
|
)
|
||
Investment in partnerships
|
|
(132,667
|
)
|
|
(386,676
|
)
|
||
Alternative minimum tax credit carryforward
|
|
(435,190
|
)
|
|
(224,428
|
)
|
||
Federal tax credits
|
|
(50,341
|
)
|
|
(2,508
|
)
|
||
Unrealized hedge (losses) gains
|
|
21,403
|
|
|
(101,430
|
)
|
||
Other
|
|
(7,376
|
)
|
|
(997
|
)
|
||
Total excluding valuation allowances
|
|
1,506,508
|
|
|
1,558,582
|
|
||
Valuation allowances
|
|
262,392
|
|
|
201,422
|
|
||
Total net deferred income tax liabilities
|
|
$
|
1,768,900
|
|
|
$
|
1,760,004
|
|
|
|
|
|
Interest
|
|
Ownership as of
|
|
As of December 31,
|
||||||
Investees
|
|
Location
|
|
Type
|
|
December 31, 2017
|
|
2017
|
|
2016
|
||||
|
|
|
|
|
|
|
|
(Thousands)
|
||||||
MVP Joint Venture
|
|
USA
|
|
Joint
|
|
45.5%
|
|
$
|
460,546
|
|
|
$
|
184,562
|
|
•
|
EQGP's only cash-generating assets consist of its partnership interests in EQM; therefore, its cash flow is dependent upon the ability of EQM to make cash distributions to its partners;
|
•
|
EQM and RMP depend on EQT for a substantial majority of their revenues and future growth; therefore, EQM and RMP are indirectly subject to the business risks of EQT;
|
•
|
EQM's natural gas gathering, transmission and storage services, RMP's natural gas gathering, compression and water services, and Strike Force Midstream's gathering and compression services are subject to extensive regulation by federal, state and local regulatory authorities and subject to stringent environmental laws and regulations, which may expose EQM, RMP and Strike Force Midstream to significant costs and liabilities;
|
•
|
Expanding EQM, RMP and Strike Force Midstream's businesses by constructing new midstream assets subjects EQM, RMP, and Strike Force Midstream to risks. If EQM, RMP and Strike Force Midstream do not complete these expansion projects, their future growth may be limited;
|
•
|
EQM, RMP and Strike Force Midstream are subject to numerous hazards and operational risks which include, but are not limited to, ruptures, fires, explosions, leaks and damage to pipelines, facilities, equipment and surrounding properties caused by natural disasters, acts of sabotage and terrorism, and inadvertent damage; and
|
•
|
Certain of the services EQM provides on its transmission and storage system are subject to long-term, fixed-price "negotiated rate" contracts that are not subject to adjustment, even if EQM's cost to perform such services exceeds the revenues received from such contracts, and, as a result, EQM's costs could exceed its revenues received under such contracts.
|
Classification
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
|
(Thousands)
|
||||||
Assets:
|
|
|
|
|
|
|
||
Cash and cash equivalents
|
|
$
|
2,857
|
|
|
$
|
60,453
|
|
Accounts receivable
|
|
28,804
|
|
|
20,662
|
|
||
Prepaid expenses and other
|
|
8,470
|
|
|
5,745
|
|
||
Property, plant and equipment, net
|
|
2,804,059
|
|
|
2,578,834
|
|
||
Other assets
|
|
483,004
|
|
|
206,104
|
|
||
Liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
47,042
|
|
|
$
|
35,831
|
|
Other current liabilities
|
|
133,531
|
|
|
32,242
|
|
||
Credit facility borrowings
|
|
180,000
|
|
|
—
|
|
||
Senior Notes
|
|
987,352
|
|
|
985,732
|
|
||
Other liabilities and credits
|
|
20,273
|
|
|
9,562
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Operating revenues
|
|
$
|
834,096
|
|
|
$
|
735,614
|
|
|
$
|
632,936
|
|
Operating expenses
|
|
256,403
|
|
|
211,630
|
|
|
183,956
|
|
|||
Other (expenses) income
|
|
(8,773
|
)
|
|
11,010
|
|
|
(14,980
|
)
|
|||
Net income
|
|
$
|
568,920
|
|
|
$
|
534,994
|
|
|
$
|
434,000
|
|
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
647,828
|
|
|
$
|
535,357
|
|
|
$
|
488,329
|
|
Net cash used in investing activities
|
|
$
|
(456,968
|
)
|
|
$
|
(732,033
|
)
|
|
$
|
(1,043,822
|
)
|
Net cash (used in) provided by financing activities
|
|
$
|
(248,456
|
)
|
|
$
|
(103,828
|
)
|
|
$
|
735,712
|
|
Classification
|
|
December 31, 2017
|
||
|
|
(Thousands)
|
||
Assets:
|
|
|
||
Cash
|
|
$
|
10,538
|
|
Accounts receivable
|
|
12,246
|
|
|
Other current assets
|
|
1,327
|
|
|
Property and equipment, net
|
|
1,431,802
|
|
|
Goodwill
|
|
1,346,918
|
|
|
Liabilities:
|
|
|
||
Accounts payable
|
|
$
|
4
|
|
Other current liabilities
|
|
28,830
|
|
|
Credit facility borrowings
|
|
286,000
|
|
|
Other long-term liabilities
|
|
9,360
|
|
|
|
For the period November 13, 2017 through December 31, 2017
|
||
|
|
(Thousands)
|
||
Operating revenues
|
|
$
|
44,219
|
|
Operating expenses
|
|
18,274
|
|
|
Other expenses
|
|
(811
|
)
|
|
Net income
|
|
$
|
25,134
|
|
|
|
|
||
Net cash provided by operating activities
|
|
$
|
22,430
|
|
Net cash used in investing activities
|
|
$
|
(34,553
|
)
|
Net cash provided by financing activities
|
|
$
|
9,959
|
|
|
December 31, 2017
|
||
|
(Thousands)
|
||
Assets:
|
|
||
Cash
|
$
|
43,938
|
|
Accounts receivable
|
12,477
|
|
|
Property and equipment, net
|
356,346
|
|
|
Intangible Assets
|
457,992
|
|
|
Liabilities:
|
|
||
Other current liabilities
|
$
|
24,341
|
|
|
|
For the period November 13, 2017 through December 31, 2017
|
||
|
|
(in thousands)
|
||
Operating revenues
|
|
$
|
9,214
|
|
Operating expenses
|
|
6,330
|
|
|
Other (expenses) income
|
|
52
|
|
|
Net income
|
|
$
|
2,936
|
|
|
|
|
||
Net cash provided by operating activities
|
|
$
|
8,588
|
|
Net cash used in investing activities
|
|
$
|
(36,190
|
)
|
Net cash provided by financing activities
|
|
$
|
26,951
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||||||
|
|
Principal Value
|
Carrying Value (a)
|
Fair
Value (b)
|
|
Principal Value
|
Carrying Value (a)
|
Fair
Value (b) |
||||||||||||
|
|
(Thousands)
|
||||||||||||||||||
5.15% Notes, due March 1, 2018
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
200,000
|
|
$
|
199,545
|
|
$
|
207,180
|
|
6.50% Notes, due April 1, 2018
|
|
—
|
|
—
|
|
—
|
|
|
500,000
|
|
499,089
|
|
527,205
|
|
||||||
8.13% Notes, due June 1, 2019
|
|
700,000
|
|
698,918
|
|
755,153
|
|
|
700,000
|
|
698,106
|
|
789,271
|
|
||||||
Floating Rate Notes due October 1, 2020
|
|
500,000
|
|
497,206
|
|
501,325
|
|
|
—
|
|
—
|
|
—
|
|
||||||
2.50% Notes due October 1, 2020
|
|
500,000
|
|
497,169
|
|
497,670
|
|
|
—
|
|
—
|
|
—
|
|
||||||
4.88% Notes, due November 15, 2021
|
|
750,000
|
|
744,920
|
|
801,953
|
|
|
750,000
|
|
743,595
|
|
801,218
|
|
||||||
3.00% Notes due October 1, 2022
|
|
750,000
|
|
742,364
|
|
743,550
|
|
|
—
|
|
—
|
|
—
|
|
||||||
4.00% EQM Notes, due August 1, 2024
|
|
500,000
|
|
494,939
|
|
504,110
|
|
|
500,000
|
|
494,170
|
|
493,125
|
|
||||||
7.75% debentures, due July 15, 2026
|
|
115,000
|
|
110,732
|
|
135,024
|
|
|
115,000
|
|
110,235
|
|
141,800
|
|
||||||
4.125% EQM Notes, due December 1, 2026
|
|
500,000
|
|
492,413
|
|
501,990
|
|
|
500,000
|
|
491,562
|
|
488,460
|
|
||||||
3.90% Notes due October 1, 2027
|
|
1,250,000
|
|
1,238,707
|
|
1,245,200
|
|
|
—
|
|
—
|
|
—
|
|
||||||
Medium-term notes:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
7.42% Series B, due 2023
|
|
10,000
|
|
10,000
|
|
11,433
|
|
|
10,000
|
|
9,998
|
|
11,677
|
|
||||||
7.6% Series C, due 2018
|
|
8,000
|
|
7,999
|
|
8,012
|
|
|
8,000
|
|
7,991
|
|
8,375
|
|
||||||
8.7% to 9.0% Series A, due 2020 through 2021
|
|
35,200
|
|
35,187
|
|
40,510
|
|
|
35,200
|
|
35,168
|
|
41,906
|
|
||||||
|
|
5,618,200
|
|
5,570,554
|
|
5,745,930
|
|
|
3,318,200
|
|
3,289,459
|
|
3,510,217
|
|
||||||
Less Senior Notes payable within one year
|
|
8,000
|
|
7,999
|
|
8,012
|
|
|
—
|
|
—
|
|
—
|
|
||||||
Total Senior Notes
|
|
$
|
5,610,200
|
|
$
|
5,562,555
|
|
$
|
5,737,918
|
|
|
$
|
3,318,200
|
|
$
|
3,289,459
|
|
$
|
3,510,217
|
|
|
|
Year Ended December 31, 2017
|
||||||||||||||||||||
|
|
Natural gas cash
flow hedges, net
of tax
|
|
|
|
Interest rate
cash flow
hedges, net
of tax
|
|
|
|
Pension and
other post-
retirement
benefits
liability
adjustment,
net of tax
|
|
|
|
Accumulated
OCI (loss), net
of tax
|
||||||||
|
|
(Thousands)
|
||||||||||||||||||||
Accumulated OCI (loss), net of tax, as of December 31, 2016
|
|
$
|
9,607
|
|
|
|
|
$
|
(699
|
)
|
|
|
|
$
|
(6,866
|
)
|
|
|
|
$
|
2,042
|
|
(Gains) losses reclassified from accumulated OCI, net of tax
|
|
(4,982
|
)
|
|
(a)
|
|
144
|
|
|
(a)
|
|
338
|
|
|
(b)
|
|
(4,500
|
)
|
||||
Accumulated OCI (loss),
net of tax, as of December
31, 2017
|
|
$
|
4,625
|
|
|
|
|
$
|
(555
|
)
|
|
|
|
$
|
(6,528
|
)
|
|
|
|
$
|
(2,458
|
)
|
|
|
Year Ended December 31, 2016
|
||||||||||||||||||||
|
|
Natural gas cash
flow hedges, net
of tax
|
|
|
|
Interest rate
cash flow
hedges, net
of tax
|
|
|
|
Pension and
other post-
retirement
benefits
liability
adjustment,
net of tax
|
|
|
|
Accumulated
OCI (loss), net
of tax
|
||||||||
|
|
(Thousands)
|
||||||||||||||||||||
Accumulated OCI (loss),
net of tax, as of December
31, 2015
|
|
$
|
64,762
|
|
|
|
|
$
|
(843
|
)
|
|
|
|
$
|
(17,541
|
)
|
|
|
|
$
|
46,378
|
|
(Gains) losses reclassified from accumulated OCI, net of tax
|
|
(55,155
|
)
|
|
(a)
|
|
144
|
|
|
(a)
|
|
10,675
|
|
|
(b)
|
|
(44,336
|
)
|
||||
Accumulated OCI (loss),
net of tax, as of December
31, 2016
|
|
$
|
9,607
|
|
|
|
|
$
|
(699
|
)
|
|
|
|
$
|
(6,866
|
)
|
|
|
|
$
|
2,042
|
|
|
|
Year Ended December 31, 2015
|
||||||||||||||||||||
|
|
Natural gas cash
flow hedges, net of tax |
|
|
|
Interest rate
cash flow hedges, net of tax |
|
|
|
Pension and
other post- retirement benefits liability adjustment, net of tax |
|
|
|
Accumulated
OCI (loss), net of tax |
||||||||
|
|
(Thousands)
|
||||||||||||||||||||
Accumulated OCI (loss), net
of tax, as of December 31, 2014
|
|
$
|
217,121
|
|
|
|
|
$
|
(987
|
)
|
|
|
|
$
|
(16,640
|
)
|
|
|
|
$
|
199,494
|
|
(Gains) losses reclassified from accumulated OCI, net of tax
|
|
(152,359
|
)
|
|
(a)
|
|
144
|
|
|
(a)
|
|
(901
|
)
|
|
(b)
|
|
(153,116
|
)
|
||||
Accumulated OCI (loss),
net of tax, as of December
31, 2015
|
|
$
|
64,762
|
|
|
|
|
$
|
(843
|
)
|
|
|
|
$
|
(17,541
|
)
|
|
|
|
$
|
46,378
|
|
|
(Thousands)
|
|
Possible future acquisitions
|
20,457
|
|
Stock compensation plans
|
14,261
|
|
Total
|
34,718
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands except per share amounts)
|
||||||||||
Basic earnings per common share:
|
|
|
|
|
|
|
|
|
|
|||
Net income (loss) attributable to EQT Corporation
|
|
$
|
1,508,529
|
|
|
$
|
(452,983
|
)
|
|
$
|
85,171
|
|
Average common shares outstanding
|
|
187,380
|
|
|
166,978
|
|
|
152,398
|
|
|||
Basic earnings (loss) per common share
|
|
$
|
8.05
|
|
|
$
|
(2.71
|
)
|
|
$
|
0.56
|
|
Diluted earnings per common share:
|
|
|
|
|
|
|
|
|
|
|||
Net income (loss) attributable to EQT Corporation
|
|
$
|
1,508,529
|
|
|
$
|
(452,983
|
)
|
|
$
|
85,171
|
|
Average common shares outstanding
|
|
187,380
|
|
|
166,978
|
|
|
152,398
|
|
|||
Potentially dilutive securities:
|
|
|
|
|
|
|
|
|
|
|||
Stock options and awards (a)
|
|
347
|
|
|
—
|
|
|
541
|
|
|||
Total
|
|
187,727
|
|
|
166,978
|
|
|
152,939
|
|
|||
Diluted earnings (loss) per common share
|
|
$
|
8.04
|
|
|
$
|
(2.71
|
)
|
|
$
|
0.56
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(millions)
|
||||||||||
2013 Executive Performance Incentive Program
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6.8
|
|
2014 Executive Performance Incentive Program
|
|
—
|
|
|
9.5
|
|
|
12.9
|
|
|||
2015 Executive Performance Incentive Program
|
|
5.4
|
|
|
12.4
|
|
|
12.1
|
|
|||
2016 Incentive Performance Share Unit Program
|
|
13.1
|
|
|
7.2
|
|
|
—
|
|
|||
2017 Incentive Performance Share Unit Program
|
|
5.0
|
|
|
—
|
|
|
—
|
|
|||
2014 EQT Value Driver Award Program
|
|
—
|
|
|
—
|
|
|
1.1
|
|
|||
2014 EQM Value Driver Award Program
|
|
—
|
|
|
—
|
|
|
0.6
|
|
|||
2015 EQT Value Driver Award Program
|
|
—
|
|
|
3.2
|
|
|
14.6
|
|
|||
2016 EQT Value Driver Performance Share Unit Award Program
|
|
3.4
|
|
|
15.7
|
|
|
—
|
|
|||
2017 EQT Value Driver Performance Share Unit Award Program
|
|
10.8
|
|
|
—
|
|
|
—
|
|
|||
Restricted stock awards
|
|
87.1
|
|
|
9.4
|
|
|
7.0
|
|
|||
Non-qualified stock options
|
|
2.6
|
|
|
3.1
|
|
|
1.9
|
|
|||
Other programs, including non-employee director awards
|
|
1.0
|
|
|
5.5
|
|
|
(2.3
|
)
|
|||
Total share-based compensation expense
|
|
$
|
128.4
|
|
|
$
|
66.0
|
|
|
$
|
54.7
|
|
•
|
the 2013 Executive Performance Incentive Plan (2013 Incentive PSU Program) under the 2009 Long-Term Incentive Plan (2009 LTIP);
|
•
|
the 2014 Executive Performance Incentive Plan (2014 Incentive PSU Program) under the 2009 LTIP;
|
•
|
the 2015 Executive Performance Incentive Plan (2015 Incentive PSU Program) under the 2014 Long-Term Incentive Plan (2014 LTIP);
|
•
|
the 2016 Incentive Performance Share Unit Program (2016 Incentive PSU Program) under the 2014 LTIP; and
|
•
|
the 2017 Incentive Performance Share Unit Program (2017 Incentive PSU Program) under the 2014 LTIP.
|
•
|
the level of total shareholder return relative to a predefined peer group; and
|
•
|
with respect to the 2013 Incentive PSU Program, the level of cumulative operating cash flow per share, and with respect to the other Incentive PSU Programs, the cumulative total sales volume growth, in each case, over the performance period.
|
Incentive PSU Program
|
Settled In
|
Accounting Treatment
|
Fair Value
1
|
Risk Free Rate
|
Vested/Payment Date
|
Awards Paid
|
Value
(in millions)
|
Unvested/Expected Payment Date
2
|
Awards Outstanding as of December 31, 2017
3
|
|||||||
2013
|
Stock
|
Equity
|
$
|
140.00
|
|
0.36
|
%
|
February 2016
|
261,073
|
|
$
|
36.6
|
|
N/A
|
N/A
|
|
2014
|
Stock
|
Equity
|
$
|
189.68
|
|
0.78
|
%
|
February 2017
|
238,060
|
|
$
|
45.2
|
|
N/A
|
N/A
|
|
2015
|
Stock
|
Equity
|
$
|
141.11
|
|
1.10
|
%
|
N/A
|
N/A
|
|
N/A
|
|
First Quarter of 2018
|
306,407
|
|
|
2016
4
|
Stock
|
Equity
|
$
|
96.30
|
|
1.31
|
%
|
N/A
|
N/A
|
|
N/A
|
|
First Quarter of 2019
|
447,145
|
|
|
2017
5
|
Stock
|
Equity
|
$
|
120.60
|
|
1.47
|
%
|
N/A
|
N/A
|
|
N/A
|
|
First Quarter of 2020
|
79,070
|
|
|
2017
6
|
Cash
|
Liability
|
$
|
103.70
|
|
1.88
|
%
|
N/A
|
N/A
|
|
N/A
|
|
First Quarter of 2020
|
117,530
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
(millions)
|
||||||||||
Award
|
|
2017
|
|
2016
|
|
2015
|
||||||
2013 Incentive PSU Program
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4.4
|
|
2014 Incentive PSU Program
|
|
—
|
|
|
4.2
|
|
|
4.9
|
|
|||
2015 Incentive PSU Program
|
|
2.2
|
|
|
4.9
|
|
|
4.9
|
|
|||
2016 Incentive PSU Program
|
|
4.4
|
|
|
3.3
|
|
|
—
|
|
|||
2017 Incentive PSU Program (liability only)
|
|
$
|
1.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
For the Years Ended December 31,
|
|||||||||||||||||
|
|
2017
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
Liability
2
|
|
Equity
|
|
|
Equity
|
|
|
Equity
|
|
|
Equity
|
|
|
Equity
|
|
|
Risk-free rate
|
|
1.88
|
%
|
|
1.47
|
%
|
|
1.31
|
%
|
|
1.10
|
%
|
|
0.78
|
%
|
|
0.36
|
%
|
Dividend Yield
1
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
Volatility factor
|
|
33.01
|
%
|
|
32.30
|
%
|
|
28.43
|
%
|
|
27.45
|
%
|
|
31.38
|
%
|
|
32.97
|
%
|
Expected term
2
|
|
2 years
|
|
|
3 years
|
|
|
3 years
|
|
|
3 years
|
|
|
3 years
|
|
|
3 years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
•
|
the 2014 Value Driver Award Program (2014 EQT VDPSU Program) under the 2009 LTIP;
|
•
|
the 2015 Value Driver Award Program (2015 EQT VDPSU Program) under the 2014 LTIP;
|
•
|
the 2016 Value Driver Performance Share Unit Award Program (2016 EQT VDPSU Program) under the 2014 LTIP; and
|
•
|
the 2017 Value Driver Performance Share Unit Award Program (2017 EQT VDPSU Program) under the 2014 LTIP.
|
EQT VDPSU Program
|
Settled In
|
Accounting Treatment
|
Fair Value per Unit
1
|
Vested/Payment Date
|
Number of awards (including accrued dividends) or cash (millions) paid
|
Unvested/Expected Payment Date
|
Awards Outstanding (including accrued dividends) as of December 31, 2017
2
|
|||||
2014
|
Cash
|
Liability
|
$
|
75.70
|
|
February 2015
|
$
|
14.2
|
|
N/A
|
N/A
|
|
$
|
52.13
|
|
February 2016
|
$
|
9.4
|
|
||||||
2015
|
Stock
|
Equity
|
$
|
75.70
|
|
February 2016
|
222,751
|
|
N/A
|
N/A
|
|
|
|
|
|
$
|
75.70
|
|
February 2017
|
208,567
|
|
N/A
|
N/A
|
|
|
2016
3
|
Cash
|
Liability
|
$
|
65.40
|
|
February 2017
|
$
|
21.3
|
|
N/A
|
N/A
|
|
$
|
56.92
|
|
N/A
|
N/A
|
|
Second tranche first quarter of 2018
|
298,480
|
|
||||
2017
4
|
Cash
|
Liability
|
$
|
56.92
|
|
N/A
|
N/A
|
|
First tranche first quarter of 2018
|
245,913
|
|
|
N/A
|
|
N/A
|
N/A
|
|
Second tranche first quarter of 2019
|
246,297
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
(millions)
|
||||||||||
Award
|
|
2017
|
|
2016
|
|
2015
|
||||||
2014 EQT VDPSU Program
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.3
|
|
2015 EQT VDPSU Program
|
|
—
|
|
|
4.1
|
|
|
10.9
|
|
|||
2016 EQT VDPSU Program
|
|
7.0
|
|
|
16.3
|
|
|
—
|
|
|||
2017 EQT VDPSU Program
|
|
$
|
10.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Restricted Stock
|
|
Non-
Vested
Shares
|
|
Weighted
Average
Fair Value
|
|
Aggregate
Fair Value
|
|||||
Outstanding at January 1, 2017
|
|
224,340
|
|
|
$
|
81.61
|
|
|
$
|
18,309,538
|
|
Granted
|
|
2,375,584
|
|
|
65.12
|
|
|
154,690,670
|
|
||
Vested
|
|
(1,854,549
|
)
|
|
66.31
|
|
|
(122,983,162
|
)
|
||
Forfeited
|
|
(15,875
|
)
|
|
78.12
|
|
|
(1,240,174
|
)
|
||
Outstanding at December 31, 2017
|
|
729,500
|
|
|
$
|
66.86
|
|
|
$
|
48,776,872
|
|
|
|
For the Years Ended December 31,
|
|||||||
|
|
2017
1
|
|
2016
1
|
|
2015
|
|||
Risk-free interest rate
|
|
1.95
|
%
|
|
1.67
|
%
|
|
1.61
|
%
|
Dividend yield
|
|
0.18
|
%
|
|
0.16
|
%
|
|
0.12
|
%
|
Volatility factor
|
|
27.45
|
%
|
|
28.59
|
%
|
|
26.80
|
%
|
Expected term
|
|
5 years
|
|
|
5 years
|
|
|
5 years
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2017
1
|
|
2016
1
|
|
2015
|
||||||
Number of Options Granted
|
|
153,700
|
|
|
228,500
|
|
|
158,200
|
|
|||
Weighted Average Grant Date Fair Value
|
|
$
|
17.47
|
|
|
$
|
15.10
|
|
|
$
|
19.90
|
|
Total Intrinsic Value of Options Exercised (millions)
|
|
$
|
1.7
|
|
|
$
|
3.5
|
|
|
$
|
15.1
|
|
Non-qualified Stock Options
|
|
Shares
|
|
Weighted
Average
Exercise
Price
|
|
Weighted
Average
Remaining
Contractual
Term
|
|
Aggregate
Intrinsic
Value
|
|||||
Outstanding at January 1, 2017
|
|
1,174,200
|
|
|
$
|
60.99
|
|
|
|
|
|
||
Granted
|
|
153,700
|
|
|
63.97
|
|
|
|
|
|
|||
Exercised
|
|
(158,700
|
)
|
|
44.84
|
|
|
|
|
|
|||
Forfeited
|
|
(40,000
|
)
|
|
67.91
|
|
|
|
|
|
|||
Expired
|
|
—
|
|
|
—
|
|
|
|
|
|
|||
Outstanding at December 31, 2017
|
|
1,129,200
|
|
|
$
|
63.42
|
|
|
6.25 years
|
|
$
|
1,428,439
|
|
Exercisable at December 31, 2017
|
|
691,100
|
|
|
$
|
63.92
|
|
|
5.08 years
|
|
$
|
668,266
|
|
|
|
Three Months Ended
|
||||||||||||||
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
|
|
(Thousands, except per share amounts)
|
||||||||||||||
2017 (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Total operating revenues
|
|
$
|
897,523
|
|
|
$
|
690,893
|
|
|
$
|
660,313
|
|
|
$
|
1,129,286
|
|
Operating income
|
|
390,644
|
|
|
189,794
|
|
|
137,694
|
|
|
214,849
|
|
||||
Net income
|
|
250,705
|
|
|
122,645
|
|
|
105,457
|
|
|
1,379,335
|
|
||||
Net income attributable to EQT Corporation
|
|
163,992
|
|
|
41,126
|
|
|
23,340
|
|
|
1,280,071
|
|
||||
Earnings per share of common stock attributable to EQT Corporation:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net income
|
|
$
|
0.95
|
|
|
$
|
0.24
|
|
|
$
|
0.13
|
|
|
$
|
5.85
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|||||||
Net income
|
|
$
|
0.95
|
|
|
$
|
0.24
|
|
|
$
|
0.13
|
|
|
$
|
5.83
|
|
2016 (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Total operating revenues
|
|
$
|
545,069
|
|
|
$
|
127,531
|
|
|
$
|
556,726
|
|
|
$
|
379,022
|
|
Operating income
|
|
127,201
|
|
|
(324,492
|
)
|
|
108,457
|
|
|
(189,466
|
)
|
||||
Net income (loss)
|
|
88,425
|
|
|
(180,807
|
)
|
|
70,104
|
|
|
(108,785
|
)
|
||||
Net income (loss) attributable to EQT Corporation
|
|
5,636
|
|
|
(258,645
|
)
|
|
(8,016
|
)
|
|
(191,958
|
)
|
||||
Earnings per share of common stock attributable to EQT Corporation:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net income (loss)
|
|
$
|
0.04
|
|
|
$
|
(1.55
|
)
|
|
$
|
(0.05
|
)
|
|
$
|
(1.11
|
)
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net income (loss)
|
|
$
|
0.04
|
|
|
$
|
(1.55
|
)
|
|
$
|
(0.05
|
)
|
|
$
|
(1.11
|
)
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
At December 31:
|
|
|
|
|
|
|
|
|
|
|||
Capitalized Costs:
|
|
|
|
|
|
|
||||||
Proved properties
|
|
$
|
18,920,855
|
|
|
$
|
12,179,833
|
|
|
$
|
10,918,499
|
|
Unproved properties
|
|
5,016,299
|
|
|
1,698,826
|
|
|
898,270
|
|
|||
Total capitalized costs
|
|
23,937,154
|
|
|
13,878,659
|
|
|
11,816,769
|
|
|||
Accumulated depreciation and depletion
|
|
5,121,646
|
|
|
4,217,154
|
|
|
3,425,618
|
|
|||
Net capitalized costs
|
|
$
|
18,815,508
|
|
|
$
|
9,661,505
|
|
|
$
|
8,391,151
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Costs incurred: (a)
|
|
|
|
|
|
|
||||||
Property acquisition:
|
|
|
|
|
|
|
|
|
|
|||
Proved properties (b)
|
|
$
|
5,251,711
|
|
|
$
|
403,314
|
|
|
$
|
23,890
|
|
Unproved properties (c)
|
|
3,310,995
|
|
|
880,545
|
|
|
158,405
|
|
|||
Exploration (d)
|
|
15,505
|
|
|
6,047
|
|
|
53,463
|
|
|||
Development
|
|
1,365,615
|
|
|
777,787
|
|
|
1,633,498
|
|
|||
Geological and geophysical
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|||
Nonaffiliated
|
|
$
|
2,651,318
|
|
|
$
|
1,594,997
|
|
|
$
|
1,690,360
|
|
Production costs
|
|
1,338,069
|
|
|
1,055,017
|
|
|
877,194
|
|
|||
Exploration costs
|
|
25,117
|
|
|
13,410
|
|
|
61,970
|
|
|||
Depreciation, depletion and accretion
|
|
982,103
|
|
|
859,018
|
|
|
765,298
|
|
|||
Impairment of long-lived assets
|
|
—
|
|
|
6,939
|
|
|
122,469
|
|
|||
Amortization of intangible assets
|
|
5,540
|
|
|
—
|
|
|
—
|
|
|||
Income tax expense (benefit)
|
|
117,984
|
|
|
(136,323
|
)
|
|
(54,857
|
)
|
|||
Results of operations from producing activities (excluding corporate overhead)
|
|
$
|
182,505
|
|
|
$
|
(203,064
|
)
|
|
$
|
(81,714
|
)
|
|
|
Years Ended December 31,
|
|||||||
|
|
2017
|
|
2016
|
|
2015
|
|||
|
|
(Millions of Cubic Feet)
|
|||||||
Total - Natural Gas, Oil, and NGLs (a)
|
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
13,508,407
|
|
|
9,976,597
|
|
|
10,738,948
|
|
Revision of previous estimates
|
|
(2,766,981
|
)
|
|
(472,285
|
)
|
|
(2,194,675
|
)
|
Purchase of hydrocarbons in place
|
|
9,389,638
|
|
|
2,395,776
|
|
|
—
|
|
Sale of hydrocarbons in place
|
|
(2,646
|
)
|
|
—
|
|
|
(61
|
)
|
Extensions, discoveries and other additions
|
|
2,225,141
|
|
|
2,384,682
|
|
|
2,051,071
|
|
Production
|
|
(907,892
|
)
|
|
(776,363
|
)
|
|
(618,686
|
)
|
End of year
|
|
21,445,667
|
|
|
13,508,407
|
|
|
9,976,597
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
6,842,958
|
|
|
6,279,557
|
|
|
4,826,387
|
|
End of year
|
|
11,297,956
|
|
|
6,842,958
|
|
|
6,279,557
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|||
Beginning of year
|
|
6,665,449
|
|
|
3,697,040
|
|
|
5,912,561
|
|
End of year
|
|
10,147,711
|
|
|
6,665,449
|
|
|
3,697,040
|
|
|
|
Years Ended December 31,
|
|||||||
|
|
2017
|
|
2016
|
|
2015
|
|||
|
|
(Millions of Cubic Feet)
|
|||||||
Natural Gas
|
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
12,331,867
|
|
|
9,110,311
|
|
|
9,775,954
|
|
Revision of previous estimates
|
|
(2,760,467
|
)
|
|
(607,171
|
)
|
|
(2,059,531
|
)
|
Purchase of natural gas in place
|
|
8,890,145
|
|
|
2,288,166
|
|
|
—
|
|
Sale of natural gas in place
|
|
(1,210
|
)
|
|
—
|
|
|
(61
|
)
|
Extensions, discoveries and other additions
|
|
2,164,578
|
|
|
2,241,528
|
|
|
1,955,935
|
|
Production
|
|
(794,677
|
)
|
|
(700,967
|
)
|
|
(561,986
|
)
|
End of year
|
|
19,830,236
|
|
|
12,331,867
|
|
|
9,110,311
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
6,074,958
|
|
|
5,652,989
|
|
|
4,257,377
|
|
End of year
|
|
10,152,543
|
|
|
6,074,958
|
|
|
5,652,989
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|||
Beginning of year
|
|
6,256,909
|
|
|
3,457,322
|
|
|
5,518,577
|
|
End of year
|
|
9,677,693
|
|
|
6,256,909
|
|
|
3,457,322
|
|
|
|
Years Ended December 31,
|
|||||||
|
|
2017
|
|
2016
|
|
2015
|
|||
|
|
(Thousands of Bbls)
|
|||||||
Oil (a)
|
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
6,395
|
|
|
5,900
|
|
|
5,005
|
|
Revision of previous estimates
|
|
5,103
|
|
|
1,159
|
|
|
1,219
|
|
Purchase of oil in place
|
|
355
|
|
|
3
|
|
|
—
|
|
Sale of oil in place
|
|
(139
|
)
|
|
—
|
|
|
—
|
|
Extensions, discoveries and other additions
|
|
9
|
|
|
62
|
|
|
419
|
|
Production
|
|
(992
|
)
|
|
(729
|
)
|
|
(743
|
)
|
End of year
|
|
10,731
|
|
|
6,395
|
|
|
5,900
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
6,395
|
|
|
5,900
|
|
|
5,005
|
|
End of year
|
|
10,731
|
|
|
6,395
|
|
|
5,900
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|||
Beginning of year
|
|
—
|
|
|
—
|
|
|
—
|
|
End of year
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Years Ended December 31,
|
|||||||
|
2017
|
|
2016
|
|
2015
|
|||
|
(Thousands of Bbls)
|
|||||||
NGLs (a)
|
|
|
|
|
|
|||
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
||
Beginning of year
|
189,695
|
|
|
138,481
|
|
|
155,494
|
|
Revision of previous estimates
|
(6,189
|
)
|
|
21,322
|
|
|
(23,743
|
)
|
Purchase of NGLs in place
|
82,894
|
|
|
17,932
|
|
|
—
|
|
Sale of NGLs in place
|
(100
|
)
|
|
—
|
|
|
—
|
|
Extensions, discoveries and other additions
|
10,084
|
|
|
23,797
|
|
|
15,437
|
|
Production
|
(17,877
|
)
|
|
(11,837
|
)
|
|
(8,707
|
)
|
End of year
|
258,507
|
|
|
189,695
|
|
|
138,481
|
|
Proved developed reserves:
|
|
|
|
|
|
|
||
Beginning of year
|
121,605
|
|
|
98,528
|
|
|
89,830
|
|
End of year
|
180,170
|
|
|
121,605
|
|
|
98,528
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|||
Beginning of year
|
68,090
|
|
|
39,953
|
|
|
65,664
|
|
End of year
|
78,337
|
|
|
68,090
|
|
|
39,953
|
|
•
|
Transfer of
987
Bcfe of proved undeveloped reserves to proved developed reserves.
|
•
|
Increase of
9,390
Bcfe associated with the acquisition of proved developed reserves (
3,330
Bcfe) and proved undeveloped reserves (
6,060
Bcfe) in the Company’s Marcellus, Upper Devonian and Utica plays.
|
•
|
Extensions, discoveries and other additions of
2,225
Bcfe, which exceeded the 2017 production of
908
Bcfe.
|
•
|
Negative revisions of
3,522
Bcfe from proved undeveloped locations, primarily due to
3,074
Bcfe from locations that are no longer anticipated to be drilled within
5
years of booking as a result of acquiring new acreage. The acquired acreage presents opportunities to drill considerably longer laterals, realize operational efficiencies and improve overall returns.
|
•
|
Upward revisions of
477
Bcfe from proved developed locations, primarily due to increased reserves from producing wells.
|
•
|
Upward revisions of
278
Bcfe associated with previously booked locations whose economic lives had been extended due to improved commodity prices.
|
•
|
Transfer of
647
Bcfe of proved undeveloped reserves to proved developed reserves.
|
•
|
Increase of
2,396
Bcfe associated with the acquisition of proved developed reserves (
320
Bcfe) and proved undeveloped reserves (
2,076
Bcfe) in the Company’s Marcellus and Upper Devonian plays.
|
•
|
Extensions, discoveries and other additions of
2,385
Bcfe, which exceeded the 2016 production of
776
Bcfe.
|
•
|
Negative revisions of
509
Bcfe from proved undeveloped locations, primarily due to
389
Bcfe from economic locations that the Company no longer expects to develop within
5
years of booking, along with the removal of locations that are no longer economic as determined in accordance with Securities and Exchange Commission (SEC) pricing requirements.
|
•
|
Upward revisions of
68
Bcfe from proved developed locations, primarily due to increased reserves from producing wells.
|
•
|
Negative revisions of
31
Bcfe associated with previously booked locations whose economic lives had been shortened due to reduced commodity prices.
|
•
|
Transfer of
1,528
Bcfe of proved undeveloped reserves to proved developed reserves.
|
•
|
Extensions, discoveries and other additions of
2,051
Bcfe, which exceeded the 2015 production of
619
Bcfe.
|
•
|
Negative revisions of
2,321
Bcfe from proved undeveloped locations, due primarily to the removal of locations that were no longer economic as determined in accordance with SEC pricing requirements and from
342
Bcfe from economic locations that the Company no longer expects to develop within
5
years of booking.
|
•
|
Upward revisions of
386
Bcfe from proved developed locations, primarily due to increased reserves from producing wells.
|
•
|
Negative revisions of
259
Bcfe associated with previously booked locations whose economic lives had been shortened due to reduced commodity prices.
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Future cash inflows (a)
|
|
$
|
51,423,920
|
|
|
$
|
24,011,281
|
|
|
$
|
17,619,037
|
|
Future production costs
|
|
(18,379,892
|
)
|
|
(14,864,126
|
)
|
|
(10,963,285
|
)
|
|||
Future development costs
|
|
(5,637,676
|
)
|
|
(3,778,698
|
)
|
|
(2,377,650
|
)
|
|||
Future income tax expenses
|
|
(5,811,125
|
)
|
|
(1,753,067
|
)
|
|
(1,333,989
|
)
|
|||
Future net cash flow
|
|
21,595,227
|
|
|
3,615,390
|
|
|
2,944,113
|
|
|||
10% annual discount for estimated timing of cash flows
|
|
(12,593,293
|
)
|
|
(2,626,636
|
)
|
|
(1,966,559
|
)
|
|||
Standardized measure of discounted future net cash flows
|
|
$
|
9,001,934
|
|
|
$
|
988,754
|
|
|
$
|
977,554
|
|
(a)
|
The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2017, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2017 of $51.34 per Bbl of oil (first day of each month closing price for West Texas Intermediate (WTI)) less regional adjustments, $2.801 per Dth for Columbia Gas Transmission Corp., $2.100 per Dth for Dominion Transmission, Inc., $2.914 per Dth for the East Tennessee Natural Gas Pipeline, $2.058 per Dth for Texas Eastern Transmission Corp., $1.995 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $2.321 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.665 per Dth for Waha, and $2.840 per Dth for the Rockies Express Pipeline Zone 3. For 2017, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2017 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $23.07 per Bbl of NGLs from certain West Virginia Marcellus reserves, $31.11 per Bbl of NGLs from certain Kentucky reserves, $29.47 per Bbl for Ohio Utica reserves, and $27.93 per Bbl for Permian reserves.
|
|
|
|
The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2016, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2016 of $42.75 per Bbl of oil (first day of each month closing price for WTI) less regional adjustments, $2.342 per Dth for Columbia Gas Transmission Corp., $1.348 per Dth for Dominion Transmission, Inc., $2.334 per Dth for the East Tennessee Natural Gas Pipeline, $1.325 per Dth for Texas Eastern Transmission Corp., $1.305 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $1.862 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.343 per Dth for Waha, and $2.402 per Dth for the Rockies Express Pipeline Zone 3. For 2016, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2016 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $13.87 per Bbl of NGLs from certain West Virginia Marcellus reserves, $17.27 per Bbl of NGLs from certain Kentucky reserves, $14.71 per Bbl for Ohio Utica reserves, and $18.91 per Bbl for Permian reserves.
|
|
|
|
The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2015, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2015 of $50.28 per Bbl of oil (first day of each month closing price for WTI) less regional adjustments, $2.506 per Dth for Columbia Gas Transmission Corp., $1.394 per Dth for Dominion Transmission, Inc., $2.552 per Dth for the East Tennessee Natural Gas Pipeline, $1.428 per Dth for Texas Eastern Transmission Corp., $1.079 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $2.430 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.473 per Dth for Waha, and $2.549 per Dth for Houston Ship Channel. For 2015, NGLs pricing using arithmetic averages of the closing prices on the first day of each month during 2015 for NGLs components and adjusted using the regional component makeup of produced NGLs resulted in prices of $17.60 per Bbl of NGLs from certain West Virginia Marcellus reserves, $21.69 per Bbl of NGLs from certain Kentucky reserves, $16.84 per Bbl for Ohio Utica reserves, and $17.51 per Bbl for Permian reserves.
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(Thousands)
|
||||||||||
Sales and transfers of natural gas and oil produced – net
|
|
$
|
(1,313,249
|
)
|
|
$
|
(539,980
|
)
|
|
$
|
(813,166
|
)
|
Net changes in prices, production and development costs
|
|
2,236,183
|
|
|
(1,129,026
|
)
|
|
(5,546,405
|
)
|
|||
Extensions, discoveries and improved recovery, less related costs
|
|
1,269,712
|
|
|
590,885
|
|
|
264,735
|
|
|||
Development costs incurred
|
|
712,635
|
|
|
402,891
|
|
|
971,186
|
|
|||
Purchase of minerals in place – net
|
|
5,357,921
|
|
|
592,078
|
|
|
—
|
|
|||
Sale of minerals in place – net
|
|
(284
|
)
|
|
—
|
|
|
(43
|
)
|
|||
Revisions of previous quantity estimates
|
|
(297,437
|
)
|
|
(60,959
|
)
|
|
(1,541,418
|
)
|
|||
Accretion of discount
|
|
115,437
|
|
|
122,674
|
|
|
600,099
|
|
|||
Net change in income taxes
|
|
(1,477,603
|
)
|
|
(91,823
|
)
|
|
2,424,200
|
|
|||
Timing and other (a)
|
|
1,409,865
|
|
|
124,460
|
|
|
(191,662
|
)
|
|||
Net increase (decrease)
|
|
8,013,180
|
|
|
11,200
|
|
|
(3,832,474
|
)
|
|||
Beginning of year
|
|
988,754
|
|
|
977,554
|
|
|
4,810,028
|
|
|||
End of year
|
|
$
|
9,001,934
|
|
|
$
|
988,754
|
|
|
$
|
977,554
|
|
(a)
|
Increase in 2017 primarily driven by timing changes to the Company’s development plan as a result of the Rice Merger.
|
•
|
Information required by Item 401 of Regulation S-K with respect to directors is incorporated herein by reference from the sections captioned “Item No. 1 – Election of Directors,” and “Corporate Governance and Board Matters” in the Company’s definitive proxy statement;
|
•
|
Information required by Item 405 of Regulation S-K with respect to compliance with Section 16(a) of the Exchange Act is incorporated herein by reference from the section captioned “Equity Ownership – Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive proxy statement;
|
•
|
Information required by Item 407(d)(4) of Regulation S-K with respect to disclosure of the existence of the Company’s separately-designated standing Audit Committee and the identification of the members of the Audit Committee is incorporated herein by reference from the section captioned “Corporate Governance and Board Matters – Board Meetings and Committees – Audit Committee” in the Company’s definitive proxy statement; and
|
•
|
Information required by Item 407(d)(5) of Regulation S-K with respect to disclosure of the Company’s audit committee financial expert is incorporated herein by reference from the section captioned “Corporate Governance and Board Matters – Board Meetings and Committees – Audit Committee” in the Company’s definitive proxy statement.
|
•
|
Information required by Item 402 of Regulation S-K with respect to named executive officer and director compensation is incorporated herein by reference from the sections captioned “Executive Compensation - Compensation Discussion and Analysis,” “Executive Compensation - Compensation Tables,” “Executive Compensation - Compensation Policies and Practices and Risk Management,” and “Directors’ Compensation” in the Company’s definitive proxy statement; and
|
•
|
Information required by paragraphs (e)(4) and (e)(5) of Item 407 of Regulation S-K with respect to certain matters related to the Management Development and Compensation Committee of the Company's Board of Directors is incorporated herein by reference from the sections captioned “Corporate Governance and Board Matters - Compensation Committee Interlocks and Insider Participation” and “Executive Compensation - Report of the Management Development and Compensation Committee” in the Company’s definitive proxy statement.
|
Plan Category
|
|
Number Of
Securities To Be Issued Upon
Exercise Of
Outstanding
Options, Warrants
and Rights
(A)
|
|
Weighted Average
Exercise Price
of Outstanding
Options,
Warrants and
Rights
(B)
|
|
Number Of Securities
Remaining Available
For Future Issuance Under Equity
Compensation Plans (Excluding Securities Reflected In
Column A)
(C)
|
|
||||
Equity Compensation Plans Approved by Shareholders
(1)
|
|
3,835,415
|
|
(2)
|
$
|
63.42
|
|
(3)
|
3,068,980
|
|
(4)
|
Equity Compensation Plans Not Approved by Shareholders
(5)
|
|
89,891
|
|
(6)
|
N/A
|
|
|
4,872,501
|
|
|
|
Total
|
|
3,925,306
|
|
|
$
|
63.42
|
|
|
7,941,481
|
|
|
(1)
|
Consists of the 2014 LTIP, the 2009 LTIP, the 1999 NEDSIP and the 2008 ESPP. Effective as of April 30, 2014, in connection with the adoption of the 2014 LTIP, the Company ceased making new grants under the 2009 LTIP. Effective as of April 22, 2009, in connection with the adoption of the 2009 LTIP, the Company ceased making new grants under the 1999 NEDSIP. The 2009 LTIP and the 1999 NEDSIP remain effective solely for the purpose of issuing shares upon the exercise or payout of awards outstanding under such plans on April 30, 2014 (for the 2009 LTIP) and April 22, 2009 (for the 1999 NEDSIP).
|
(2)
|
Consists of (i) 520,100 shares subject to outstanding stock options under the 2014 LTIP; (ii) 2,569,766 shares subject to outstanding performance awards under the 2014 LTIP, inclusive of dividend reinvestments thereon (counted at a 3X multiple assuming maximum performance is achieved under the awards (representing 856,589
target
awards and dividend reinvestments thereon)); (iii) 76,532 shares subject to outstanding directors' deferred stock units under the 2014 LTIP, inclusive of dividend reinvestments thereon; (iv) 628,800 shares subject to outstanding stock options under the 2009 LTIP; (v) 34,983 shares subject to outstanding directors’ deferred stock units under the 2009 LTIP, inclusive of dividend reinvestments thereon; and (vi) 5,234 shares subject to outstanding directors’ deferred stock units under the 1999 NEDSIP, inclusive of dividend reinvestments thereon.
|
(3)
|
The weighted-average exercise price is calculated based solely upon outstanding stock options under the 2014 LTIP and the 2009 LTIP and excludes deferred stock units under the 2014 LTIP, the 2009 LTIP and the 1999 NEDSIP and performance awards under the 2014 LTIP and the 2009 LTIP. The weighted average remaining term of the stock options was
6.25 years
as of
December 31, 2017
.
|
(4)
|
Consists of (i) 2,511,109 shares available for future issuance under the 2014 LTIP, (ii) 4,899 shares under the 2009 LTIP and (iii) 552,972 shares available for future issuance under the 2008 ESPP. As of
December 31, 2017
, 5,004 shares were subject to purchase under the 2008 ESPP.
|
(5)
|
Consists of the 2005 DDCP, the 1999 DDCP and the Rice LTIP each of which is described below.
|
(6)
|
Consists of (i) 25,529 shares invested in the EQT Common Stock Fund, payable in shares of common stock, allocated to non-employee directors’ accounts under the 2005 DDCP and the 1999 DDCP as of
December 31, 2017
; and (ii) 64,362 performance awards under the Rice LTIP, inclusive of dividend reinvestments thereon (based upon amounts previously confirmed in connection with the Rice Merger).
|
(a)
|
|
Documents filed as part of this report
|
|
||
|
|
|
|
|
|
|
|
1.
|
|
All Financial Statements
|
|
|
|
|
|
|
|
|
|
|
|
Index to Consolidated Financial Statements
|
Page Reference
|
|
|
|
|
Statements of Consolidated Operations for each of the three years in the period ended December 31, 2017
|
|
|
|
|
|
Statements of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 2017
|
|
|
|
|
|
Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2017
|
|
|
|
|
|
Consolidated Balance Sheets as of December 31, 2017 and 2016
|
|
|
|
|
|
Statements of Consolidated Equity for each of the three years in the period ended December 31, 2017
|
|
|
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
|
|
|
|
|
2.
|
|
Financial Statement Schedule
|
|
|
|
|
|
|
|
|
|
|
|
Schedule II - Valuation and Qualifying Accounts and Reserves for the Three Years Ended December 31, 2017
|
|
|
|
|
|
|
|
Column A
|
|
Column B
|
|
Column C
|
|
Column D
|
|
Column E
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Description
|
|
Balance at Beginning of Period
|
|
(Deductions) Additions Charged to Costs and Expenses
|
|
Additions Charged to Other Accounts
|
|
Deductions
|
|
Balance at
End of
Period
|
||||||||||
|
|
(Thousands)
|
||||||||||||||||||
Valuation allowance for deferred tax assets:
|
|
|
|
|
|
|
|
|||||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2017
|
|
$
|
201,422
|
|
|
$
|
70,063
|
|
|
$
|
—
|
|
|
$
|
(9,093
|
)
|
|
$
|
262,392
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2016
|
|
$
|
156,084
|
|
|
$
|
24,706
|
|
|
$
|
21,536
|
|
|
$
|
(904
|
)
|
|
$
|
201,422
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2015
|
|
$
|
64,987
|
|
|
$
|
91,097
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
156,084
|
|
|
|
|
|
|
|
|
|
|
|
All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.
|
|
|
|
|
|
|
|
|
|
3.
|
|
Exhibits
|
|
|
|
|
|
|
|
Exhibits
|
|
Description
|
|
Method of Filing
|
|
|
|
|
|
|
Agreement and Plan of Merger dated as of June 19, 2017 among the Company, Eagle Merger Sub I, Inc. and Rice Energy Inc.
|
|
Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-3551) filed on June 19, 2017
|
|
|
|
|
|
|
|
Amendment No. 1 to Agreement and Plan of Merger dated as of October 26, 2017 among the Company, Eagle Merger Sub I, Inc. and Rice Energy Inc.
|
|
Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-3551) filed on October 26, 2017
|
|
|
|
|
|
|
|
Purchase and Sale Agreement dated as of September 26, 2016 among Vantage Energy Investment LLC, Vantage Energy Investment II LLC, Rice Energy Inc., Vantage Energy, LLC, and Vantage Energy II, LLC
|
|
Incorporated herein by reference to Exhibit 10.1 to Rice Energy Inc.'s Form 8-K (#001-36273) filed on September 30, 2016
|
|
|
|
|
|
|
|
Restated Articles of Incorporation of EQT Corporation (amended through November 13, 2017)
|
|
Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on November 14, 2017
|
|
|
|
|
|
|
|
Amended and Restated Bylaws of EQT Corporation (amended through November 13, 2017)
|
|
Incorporated herein by reference to Exhibit 3.3 to Form 8-K (#001-3551) filed on November 14, 2017
|
|
|
|
|
|
|
|
Indenture dated as of April 1, 1983 between the Company and Pittsburgh National Bank, as Trustee
|
|
Incorporated herein by reference to Exhibit 4.01(a) to Form 10-K (#001-3551) for the year ended December 31, 2007
|
|
|
|
|
|
|
|
Instrument appointing Bankers Trust Company as successor trustee to Pittsburgh National Bank
|
|
Incorporated herein by reference to Exhibit 4.01(b) to Form 10-K (#001-3551) for the year ended December 31, 1998
|
|
|
|
|
|
|
|
Resolution adopted August 19, 1991 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 through 27, establishing the terms and provisions of the Series A Medium-Term Notes
|
|
Incorporated herein by reference to Exhibit 4.01(g) to Form 10-K (#001-3551) for the year ended December 31, 1996
|
|
|
|
|
|
|
|
Resolutions adopted July 6, 1992 and February 19, 1993 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 through 8, establishing the terms and provisions of the Series B Medium-Term Notes
|
|
Incorporated herein by reference to Exhibit 4.01(h) to Form 10-K (#001-3551) for the year ended December 31, 1997
|
|
|
|
|
|
|
|
Resolution adopted July 14, 1994 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 and 2, establishing the terms and provisions of the Series C Medium-Term Notes
|
|
Incorporated herein by reference to Exhibit 4.01(i) to Form 10-K (#001-3551) for the year ended December 31, 1995
|
|
|
|
|
|
|
|
Second Supplemental Indenture dated as of June 30, 2008 between the Company and Deutsche Bank Trust Company Americas, as Trustee, pursuant to which EQT Corporation assumed the obligations of Equitable Resources, Inc. under the related Indenture
|
|
Incorporated herein by reference to Exhibit 4.01(g) to Form 8-K (#001-3551) filed on July 1, 2008
|
|
|
|
|
|
|
|
Indenture dated as of July 1, 1996 between the Company and The Bank of New York, as successor to Bank of Montreal Trust Company, as Trustee
|
|
Incorporated herein by reference to Exhibit 4.01(a) to Form S-4 Registration Statement (#333-103178) filed on February 13, 2003
|
Exhibits
|
|
Description
|
|
Method of Filing
|
|
|
|
|
|
|
Resolutions adopted January 18 and July 18, 1996 by the Board of Directors of the Company and Resolution adopted July 18, 1996 by the Executive Committee of the Board of Directors of the Company, establishing the terms and provisions of the 7.75% Debentures issued July 29, 1996
|
|
Incorporated herein by reference to Exhibit 4.01(j) to Form 10-K (#001-3551) for the year ended December 31, 1996
|
|
|
|
|
|
|
|
Supplemental Indenture dated as of June 30, 2008 between the Company and The Bank of New York, as Trustee, pursuant to which EQT Corporation assumed the obligations of Equitable Resources, Inc. under the related Indenture
|
|
Incorporated herein by reference to Exhibit 4.02(f) to Form 8-K (#001-3551) filed on July 1, 2008
|
|
|
|
|
|
|
|
Indenture dated as of March 18, 2008 between the Company and The Bank of New York, as Trustee
|
|
Incorporated herein by reference to Exhibit 4.1 to Form 8-K (#001-3551) filed on March 18, 2008
|
|
|
|
|
|
|
|
Third Supplemental Indenture dated as of May 15, 2009 between the Company and The Bank of New York, as Trustee, pursuant to which the 8.13% Senior Notes due 2019 were issued
|
|
Incorporated herein by reference to Exhibit 4.1 to Form 8-K (#001-3551) filed on May 15, 2009
|
|
|
|
|
|
|
|
Fourth Supplemental Indenture dated as of November 7, 2011 between the Company and The Bank of New York Mellon, as Trustee, pursuant to which the 4.88% Senior Notes due 2021 were issued
|
|
Incorporated herein by reference to Exhibit 4.2 to Form 8-K (#001-3551) filed on November 7, 2011
|
|
|
|
|
|
|
|
Fifth Supplemental Indenture dated as of October 4, 2017 between the Company and The Bank of New York Mellon, as Trustee, pursuant to which the Floating Rate Notes due 2020 were issued
|
|
Incorporated herein by reference to Exhibit 4.3 to Form 8-K (#001-3551) filed on October 4, 2017
|
|
|
|
|
|
|
|
Sixth Supplemental Indenture dated as of October 4, 2017 between the Company and The Bank of New York Mellon, as Trustee, pursuant to which the 2.50% Senior Notes due 2020 were issued
|
|
Incorporated herein by reference to Exhibit 4.5 to Form 8-K (#001-3551) filed on October 4, 2017
|
|
|
|
|
|
|
|
Seventh Supplemental Indenture dated as of October 4, 2017 between the Company and The Bank of New York Mellon, as Trustee, pursuant to which the 3.00% Senior Notes due 2022 were issued
|
|
Incorporated herein by reference to Exhibit 4.7 to Form 8-K (#001-3551) filed on October 4, 2017
|
Exhibits
|
|
Description
|
|
Method of Filing
|
|
|
|
|
|
|
Eighth Supplemental Indenture dated as of October 4, 2017 between the Company and The Bank of New York Mellon, as Trustee, pursuant to which the 3.90% Senior Notes due 2027 were issued
|
|
Incorporated herein by reference to Exhibit 4.9 to Form 8-K (#001-3551) filed on October 4, 2017
|
|
|
|
|
|
|
|
Indenture dated as of August 1, 2014 among EQT Midstream Partners, LP, the subsidiaries of EQT Midstream Partners, LP party thereto, and The Bank of New York Mellon Trust Company, N.A., as Trustee
|
|
Incorporated herein by reference to Exhibit 4.01 to Form 10-Q (#001-3551) for the quarter ended September 30, 2014
|
|
|
|
|
|
|
|
First Supplemental Indenture dated as of August 1, 2014 among EQT Midstream Partners, LP, the subsidiaries of EQT Midstream Partners, LP party thereto, and The Bank of New York Mellon Trust Company, N.A., as Trustee, pursuant to which the EQT Midstream Partners, LP 4.00% Senior Notes due 2024 were issued
|
|
Incorporated herein by reference to Exhibit 4.02 to Form 10-Q (#001-3551) for the quarter ended September 30, 2014
|
|
|
|
|
|
|
|
Second Supplemental Indenture dated as of November 4, 2016 between EQT Midstream Partners, LP and The Bank of New York Mellon Trust Company, N.A., as Trustee, pursuant to which the EQT Midstream Partners, LP 4.125% Senior Notes due 2026 were issued
|
|
Incorporated herein by reference to Exhibit 4.2 to EQT Midstream Partners, LP's Form 8-K (#001-35574) filed on November 4, 2016
|
|
|
|
|
|
|
*
10.01(a)
|
|
2009 Long-Term Incentive Plan (as amended and restated July 11, 2012)
|
|
Incorporated herein by reference to Exhibit 10.2 to Form 10-Q (#001-3551) for the quarter ended June 30, 2012
|
|
|
|
|
|
*
10.01(b)
|
|
Form of Participant Award Agreement (Stock Option) under 2009 Long-Term Incentive Plan (pre-2012 grants)
|
|
Incorporated herein by reference to Exhibit 10.01(q) to Form 10-K (#001-3551) for the year ended December 31, 2010
|
|
|
|
|
|
*
10.01(c)
|
|
Form of Amendment to Stock Option Award Agreements
|
|
Incorporated herein by reference to Exhibit 10.3 to Form 10-Q (#001-3551) for the quarter ended June 30, 2011
|
|
|
|
|
|
*
10.01(d)
|
|
Form of Participant Award Agreement (Stock Option) under 2009 Long-Term Incentive Plan (2012 grants)
|
|
Incorporated herein by reference to Exhibit 10.02(n) to Form 10-K (#001-3551) for the year ended December 31, 2011
|
|
|
|
|
|
*
10.01(e)
|
|
Form of Participant Award Agreement (Phantom Stock Unit Awards) under 2009 Long-Term Incentive Plan (pre-2013 grants)
|
|
Incorporated herein by reference to Exhibit 10.02(b) to Form 10-K (#001-3551) for the year ended December 31, 2012
|
|
|
|
|
|
*
10.01(f)
|
|
Form of Participant Award Agreement (Stock Option) under 2009 Long-Term Incentive Plan (2013 grants)
|
|
Incorporated herein by reference to Exhibit 10.02(t) to Form 10-K (#001-3551) for the year ended December 31, 2012
|
|
|
|
|
|
*
10.01(g)
|
|
Form of Participant Award Agreement (Phantom Stock Unit Awards) under 2009 Long-Term Incentive Plan (2013 and 2014 grants)
|
|
Incorporated herein by reference to Exhibit 10.02(s) to Form 10-K (#001-3551) for the year ended December 31, 2012
|
|
|
|
|
|
Exhibits
|
|
Description
|
|
Method of Filing
|
|
|
|
|
|
|
|
|
|
|
*
10.01(h)
|
|
Form of Participant Award Agreement (Stock Option) under 2009 Long-Term Incentive Plan (2014 grants)
|
|
Incorporated herein by reference to Exhibit 10.02(v) to Form 10-K (#001-3551) for the year ended December 31, 2013
|
|
|
|
|
|
*
10.01(i)
|
|
2014 Executive Performance Incentive Program
|
|
Incorporated herein by reference to Exhibit 10.02(w) to Form 10-K (#001-3551) for the year ended December 31, 2013
|
|
|
|
|
|
*
10.01(j)
|
|
Form of Participant Award Agreement under 2014 Executive Performance Incentive Program
|
|
Incorporated herein by reference to Exhibit 10.02(x) to Form 10-K (#001-3551) for the year ended December 31, 2013
|
|
|
|
|
|
*
10.02(a)
|
|
2014 Long-Term Incentive Plan
|
|
Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on May 1, 2014
|
|
|
|
|
|
*
10.02(b)
|
|
Form of Participant Award Agreement (Phantom Stock Unit Awards) under 2014 Long-Term Incentive Plan
|
|
Incorporated herein by reference to Exhibit 10.03(b) to Form 10-K (#001-3551) for the year ended December 31, 2014
|
|
|
|
|
|
*
10.02(c)
|
|
2015 Executive Performance Incentive Program
|
|
Incorporated herein by reference to Exhibit 10.03(d) to Form 10-K (#001-3551) for the year ended December 31, 2014
|
|
|
|
|
|
*
10.02(d)
|
|
Form of Participant Award Agreement under 2015 Executive Performance Incentive Program
|
|
Incorporated herein by reference to Exhibit 10.03(e) to Form 10-K (#001-3551) for the year ended December 31, 2014
|
|
|
|
|
|
*
10.02(e)
|
|
Amendment to 2015 Executive Performance Incentive Program
|
|
Incorporated herein by reference to Exhibit 10.03(f) to Form 10-K (#001-3551) for the year ended December 31, 2014
|
|
|
|
|
|
*
10.02(f)
|
|
Form of EQT 2015 Value Driver Performance Award Agreement
|
|
Incorporated herein by reference to Exhibit 10.9(c) to EQT Midstream Partners, LP's Form 10-K (#001-35574) for the year ended December 31, 2016
|
|
|
|
|
|
*
10.02(g)
|
|
2016 Incentive Performance Share Unit Program
|
|
Incorporated herein by reference to Exhibit 10.02(g) to Form 10-K (#001-3551) for the year ended December 31, 2015
|
|
|
|
|
|
*
10.02(h)
|
|
Form of Participant Award Agreement under 2016 Incentive Performance Share Unit Program
|
|
Incorporated herein by reference to Exhibit 10.02(h) to Form 10-K (#001-3551) for the year ended December 31, 2015
|
Exhibits
|
|
Description
|
|
Method of Filing
|
|
|
|
|
|
*
10.02(i)
|
|
2016 Restricted Stock Award Agreement (Standard) for Robert J. McNally
|
|
Incorporated herein by reference to Exhibit 10.03 to Form 10-Q (#001-3551) for the quarter ended March 31, 2016
|
|
|
|
|
|
*
10.02(j)
|
|
Form of EQT 2016 Value Driver Performance Award Agreement
|
|
Incorporated herein by reference to Exhibit 10.9(d) to EQT Midstream Partners, LP's Form 10-K (#001-35574) for the year ended December 31, 2016
|
|
|
|
|
|
*
10.02(k)
|
|
Form of Participant Award Agreement (Stock Option) under 2014 Long-Term Incentive Plan (pre-2017 grants)
|
|
Incorporated herein by reference to Exhibit 10.03(c) to Form 10-K (#001-3551) for the year ended December 31, 2014
|
|
|
|
|
|
*
10.02(l)
|
|
2017 Incentive Performance Share Unit Program
|
|
Incorporated herein by reference to Exhibit 10.02(l) to Form 10-K (#001-3551) for the year ended December 31, 2016
|
|
|
|
|
|
*
10.02(m)
|
|
Form of Participant Award Agreement under 2017 Incentive Performance Share Unit Program
|
|
Incorporated herein by reference to Exhibit 10.02(m) to Form 10-K (#001-3551) for the year ended December 31, 2016
|
|
|
|
|
|
*
10.02(n)
|
|
Form of Participant Award Agreement (Stock Option) under 2014 Long-Term Incentive Plan (2017 grants)
|
|
Incorporated herein by reference to Exhibit 10.02(k) to Form 10-K (#001-3551) for the year ended December 31, 2016
|
|
|
|
|
|
*
10.02(o)
|
|
Form of EQT 2017 Value Driver Performance Award Agreement
|
|
Incorporated herein by reference to Exhibit 10.9(e) to EQT Midstream Partners, LP's Form 10-K (#001-35574) for the year ended December 31, 2016
|
|
|
|
|
|
*
10.02(p)
|
|
Form of EQT Restricted Stock Unit Award Agreement (Standard)
|
|
Incorporated herein by reference to Exhibit 10.9(a) to EQT Midstream Partners, LP's Form 10-K (#001-35574) for the year ended December 31, 2016
|
|
|
|
|
|
*
10.02(q)
|
|
Form of Restricted Stock Award Agreement under 2014
Long-Term Incentive Plan (pre-2018 grants) |
|
Incorporated herein by reference to Exhibit 10.02(d) to Form 10-K (#001-3551) for the year ended December 31, 2016
|
|
|
|
|
|
*
10.02(r)
|
|
Form of Participant Award Agreement (Stock Option) under 2014 Long-Term Incentive Plan (2018 grants)
|
|
Filed herewith as Exhibit 10.02(r)
|
|
|
|
|
|
*
10.02(s)
|
|
Form of Restricted Stock Award Agreement under 2014 Long-Term Incentive Plan (2018 grants)
|
|
Filed herewith as Exhibit 10.02(s)
|
|
|
|
|
|
*
10.02(t)
|
|
2018 Incentive Performance Share Unit Program
|
|
Filed herewith as Exhibit 10.02(t)
|
|
|
|
|
|
*
10.02(u)
|
|
Form of Participant Award Agreement under 2018 Incentive Performance Share Unit Program
|
|
Filed herewith as Exhibit 10.02(u)
|
|
|
|
|
|
*
10.03(a)
|
|
Rice Energy Inc. 2014 Long-Term Incentive Plan (as amended and restated May 9, 2014)
|
|
Incorporated herein by reference to Exhibit 10.3 to Rice Energy Inc.'s Form 10-Q (#001-36273) for the quarter ended June 30, 2014
|
Exhibits
|
|
Description
|
|
Method of Filing
|
|
|
|
|
|
*
10.03(b)
|
|
Form of Restricted Stock Unit Agreement (Directors) for Rice Energy Inc.
|
|
Incorporated herein by reference to Exhibit 10.19 to Rice Energy Inc.'s Amendment No. 2 to Form S-1 Registration Statement (#333-192894) filed on January 8, 2014
|
|
|
|
|
|
*
10.04(a)
|
|
EQT GP Services, LLC 2015 Long-Term Incentive Plan
|
|
Incorporated herein by reference to Exhibit 10.3 to EQT GP Holdings, LP's Form 8-K (#001-37380) filed on May 15, 2015
|
|
|
|
|
|
*
10.04(b)
|
|
Form of EQT GP Holdings, LP Phantom Unit Award Agreement
|
|
Incorporated herein by reference to Exhibit 10.5 to EQT GP Holdings, LP's Amendment No. 1 to Form S-1 Registration Statement (#333-202053) filed on April 1, 2015
|
|
|
|
|
|
*
10.05
|
|
EQT Midstream Services, LLC 2012 Long-Term Incentive Plan
|
|
Incorporated herein by reference to Exhibit 10.03 to Form 10-K (#001-3551) for the year ended December 31, 2012
|
|
|
|
|
|
*
10.06
|
|
Rice Midstream Partners LP 2014 Long-Term Incentive Plan
|
|
Incorporated herein by reference to Exhibit 4.3 to Rice Midstream Partners LP's Form S-8 Registration Statement (#333-201169) filed on December 19, 2014
|
|
|
|
|
|
*
10.07(a)
|
|
1999 Non-Employee Directors’ Stock Incentive Plan (as amended and restated December 3, 2008)
|
|
Incorporated herein by reference to Exhibit 10.02(a) to Form 10-K (#001-3551) for the year ended December 31, 2008
|
|
|
|
|
|
*
10.07(b)
|
|
Form of Participant Award Agreement (Phantom Stock Unit Awards) under 1999 Non-Employee Directors’ Stock Incentive Plan
|
|
Incorporated herein by reference to Exhibit 10.04(c) to Form 10-K (#001-3551) for the year ended December 31, 2006
|
|
|
|
|
|
*
10.08
|
|
2016 Executive Short-Term Incentive Plan
|
|
Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on April 21, 2016
|
|
|
|
|
|
*
10.09
|
|
2006 Payroll Deduction and Contribution Program (as amended and restated July 7, 2015)
|
|
Incorporated herein by reference to Exhibit 10.06 to Form 10-Q (#001-3551) for the quarter ended June 30, 2015
|
|
|
|
|
|
*
10.10(a)
|
|
1999 Directors' Deferred Compensation Plan (as amended and restated December 3, 2014)
|
|
Incorporated herein by reference to Exhibit 10.08 to Form 10-K (#001-3551) for the year ended December 31, 2014
|
|
|
|
|
|
*
10.10(b)
|
|
2005 Directors’ Deferred Compensation Plan (as amended and restated December 3, 2014)
|
|
Incorporated herein by reference to Exhibit 10.09 to Form 10-K (#001-3551) for the year ended December 31, 2014
|
|
|
|
|
|
*
10.11
|
|
Form of Indemnification Agreement between the Company and each executive officer and each outside director
|
|
Incorporated herein by reference to Exhibit 10.18 to Form 10-K (#001-3551) for the year ended December 31, 2008
|
|
|
|
|
|
|
Second Amended and Restated Credit Agreement dated as of July 31, 2017 among the Company, PNC Bank, National Association, as Administrative Agent, Swing Line Lender and an L/C Issuer and the other lenders party thereto
|
|
Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on August 3, 2017
|
Exhibits
|
|
Description
|
|
Method of Filing
|
|
|
|
|
|
*
10.13
|
|
Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of July 29, 2015 between the Company and David L. Porges
|
|
Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on July 31, 2015
|
|
|
|
|
|
*
10.14
|
|
Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of July 29, 2015 between the Company and Steven T. Schlotterbeck
|
|
Incorporated herein by reference to Exhibit 10.5 to Form 8-K (#001-3551) filed on July 31, 2015
|
|
|
|
|
|
*
10.15(a)
|
|
Offer letter dated as of March 7, 2016 between the Company and Robert J. McNally
|
|
Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on March 17, 2016
|
|
|
|
|
|
*
10.15(b)
|
|
Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of March 10, 2016 between the Company and Robert J. McNally
|
|
Incorporated herein by reference to Exhibit 10.02 to Form 10-Q (#001-3551) for the quarter ended March 31, 2016
|
|
|
|
|
|
*
10.16
|
|
Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of July 29, 2015 between the Company and Lewis B. Gardner
|
|
Incorporated herein by reference to Exhibit 10.4 to Form 8-K (#001-3551) filed on July 31, 2015
|
*
10.17
|
|
Second Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of March 1, 2017 between the Company and David E. Schlosser, Jr.
|
|
Filed herewith as Exhibit 10.17
|
|
|
|
|
|
*
10.18(a)
|
|
Offer Letter dated as of July 26, 2017 between the Company and Jeremiah J. Ashcroft III
|
|
Filed herewith as Exhibit 10.18(a)
|
|
|
|
|
|
*
10.18(b)
|
|
Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of August 7, 2017 between the Company and Jeremiah J. Ashcroft III
|
|
Filed herewith as Exhibit 10.18(b)
|
|
|
|
|
|
*
10.19(a)
|
|
Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of July 29, 2015 between the Company and M. Elise Hyland
|
|
Incorporated herein by reference to Exhibit 10.2 to EQT Midstream Partners, LP's Form 10-Q (#001-35574) for the quarter ended March 31, 2017
|
|
|
|
|
|
*
10.19(b)
|
|
Transition Agreement and General Release dated as of February 28, 2017 between the Company and M. Elise Hyland
|
|
Incorporated herein by reference to Exhibit 10.3 to EQT Midstream Partners, LP's Form 10-Q (#001-35574) for the quarter ended March 31, 2017
|
|
|
|
|
|
*
10.20(a)
|
|
Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement dated as of July 29, 2015 between the Company and Randall L. Crawford
|
|
Incorporated herein by reference to Exhibit 10.3 to Form 8-K (#001-3551) filed on July 31, 2015
|
|
|
|
|
|
*
10.20(b)
|
|
Amendment to Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement effective as of January 1, 2016 between the Company and Randall L. Crawford
|
|
Incorporated herein by reference to Exhibit 10.12(b) to Form 10-K (#001-3551) for the year ended December 31, 2015
|
|
|
|
|
|
*
10.20(c)
|
|
Transition Agreement and General Release dated as of January 9, 2017 between the Company and Randall L. Crawford
|
|
Incorporated herein by reference to Exhibit 10.14(e) to Form 10-K (#001-3551) for the year ended December 31, 2016
|
|
|
|
|
|
*
10.21
|
|
Separation and Release Agreement, dated as of November 13, 2017, among the Company, EQT RE, LLC and Daniel J. Rice IV
|
|
Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on November 17, 2017
|
Exhibits
|
|
Description
|
|
Method of Filing
|
|
|
|
|
|
|
Schedule of Subsidiaries
|
|
Filed herewith as Exhibit 21
|
|
|
|
|
|
|
|
Consent of Independent Registered Public Accounting Firm
|
|
Filed herewith as Exhibit 23.01
|
|
|
|
|
|
|
|
Consent of Ryder Scott Company, L.P.
|
|
Filed herewith as Exhibit 23.02
|
|
|
|
|
|
|
|
Rule 13(a)-14(a) Certification of Principal Executive Officer
|
|
Filed herewith as Exhibit 31.01
|
|
|
|
|
|
|
|
Rule 13(a)-14(a) Certification of Principal Financial Officer
|
|
Filed herewith as Exhibit 31.02
|
|
|
|
|
|
|
|
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer
|
|
Furnished herewith as Exhibit 32
|
|
|
|
|
|
|
|
Independent Petroleum Engineers’ Audit Report
|
|
Filed herewith as Exhibit 99
|
|
|
|
|
|
|
101
|
|
Interactive Data File
|
|
Filed herewith as Exhibit 101
|
|
|
EQT CORPORATION
|
|
|
|
|
|
|
|
By:
|
/s/ STEVEN T. SCHLOTTERBECK
|
|
|
|
Steven T. Schlotterbeck
|
|
|
|
President and Chief Executive Officer
|
|
|
|
February 15, 2018
|
/s/ STEVEN T. SCHLOTTERBECK
|
|
President,
|
|
February 15, 2018
|
Steven T. Schlotterbeck
|
|
Chief Executive Officer and
|
|
|
(Principal Executive Officer)
|
|
Director
|
|
|
|
|
|
|
|
/s/ ROBERT J. MCNALLY
|
|
Senior Vice President
|
|
February 15, 2018
|
Robert J. McNally
|
|
and Chief Financial Officer
|
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
|
|
/s/ JIMMI SUE SMITH
|
|
Chief Accounting Officer
|
|
February 15, 2018
|
Jimmi Sue Smith
|
|
|
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
|
|
/s/ VICKY A. BAILEY
|
|
Director
|
|
February 15, 2018
|
Vicky A. Bailey
|
|
|
|
|
|
|
|
|
|
/s/ PHILIP G. BEHRMAN
|
|
Director
|
|
February 15, 2018
|
Philip G. Behrman
|
|
|
|
|
|
|
|
|
|
/s/ KENNETH M. BURKE
|
|
Director
|
|
February 15, 2018
|
Kenneth M. Burke
|
|
|
|
|
|
|
|
|
|
/s/ A. BRAY CARY JR.
|
|
Director
|
|
February 15, 2018
|
A. Bray Cary, Jr.
|
|
|
|
|
|
|
|
|
|
/s/ MARGARET K. DORMAN
|
|
Director
|
|
February 15, 2018
|
Margaret K. Dorman
|
|
|
|
|
|
|
|
|
|
/s/ THOMAS F. KARAM
|
|
Director
|
|
February 15, 2018
|
Thomas F. Karam
|
|
|
|
|
|
|
|
|
|
/s/ DAVID L. PORGES
|
|
Executive Chairman
|
|
February 15, 2018
|
David L. Porges
|
|
|
|
|
|
|
|
|
|
/s/ DANIEL J. RICE IV
|
|
Director
|
|
February 15, 2018
|
Daniel J. Rice IV
|
|
|
|
|
|
|
|
|
|
/s/ JAMES E. ROHR
|
|
Director
|
|
February 15, 2018
|
James E. Rohr
|
|
|
|
|
|
|
|
|
|
/s/ NORMAN J. SZYDLOWSKI
|
|
Director
|
|
February 15, 2018
|
Norman J. Szydlowski
|
|
|
|
|
|
|
|
|
|
/s/ STEPHEN A. THORINGTON
|
|
Director
|
|
February 15, 2018
|
Stephen A. Thorington
|
|
|
|
|
|
|
|
|
|
/s/ LEE T. TODD, JR.
|
|
Director
|
|
February 15, 2018
|
Lee T. Todd, Jr.
|
|
|
|
|
|
|
|
|
|
/s/ CHRISTINE J. TORETTI
|
|
Director
|
|
February 15, 2018
|
Christine J. Toretti
|
|
|
|
|
|
|
|
|
|
/s/ ROBERT F. VAGT
|
|
Director
|
|
February 15, 2018
|
Robert F. Vagt
|
|
|
|
|
S
|
I hereby elect to participate in the Executive Alternative Work Arrangement Classification as described in paragraph 9 of the above Second Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement. I hereby agree to execute an Executive Alternative Work Arrangement Employment Agreement in a form substantially similar to the one attached hereto as Exhibit A, within 90 days prior to my relinquishment of full-time status, which agreement will become effective automatically on the day following my Eligible Termination. I understand that I will not be eligible for the Executive Alternative Work Arrangement, including the post-employment benefits described therein if my termination from employment is not an Eligible Termination.
|
£
|
I hereby decline to participate in the Executive Alternative Work Arrangement Classification as described in paragraph 9 of the above Second Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement.
|
EQT CORPORATION
By:
Title
Date
|
|
EMPLOYEE
Name: David E. Schlosser
Date
|
(i)
|
if (a) your grant of Options is assumed by the surviving entity of the Change of Control (or otherwise equitably converted or substituted in connection with the Change of Control in a manner approved by the Committee) or (b) the Company is the surviving entity of the Change of Control, and (1) your employment is terminated without Cause (as defined below), including termination resulting from death or Disability (as defined in the Plan), or (2) you resign for Good Reason (as defined below), in each case prior to the second anniversary of the effective date of the Change of Control, all unvested Options will vest immediately upon such termination or resignation; and
|
(ii)
|
if (a) your grant of Options is not assumed by the surviving entity of the Change of Control (or otherwise equitably converted or substituted in connection with the Change of Control in a manner approved by the Committee) and (b) the Company is not the surviving entity of the Change of Control, all unvested Options will vest immediately upon such Change of Control.
|
Termination Date
|
|
Percent Vested
|
Prior to January 1, 2019
|
|
0%
|
On or after January 1, 2019 and prior to
January 1, 2020 |
|
25%
|
On or after January 1, 2020 and prior to
January 1, 2021 |
|
50%
|
1.
|
Defined Terms
. Capitalized terms used herein and not otherwise defined shall have the meanings assigned to such terms in the Plan. In addition, and notwithstanding any contrary definition in the Plan, for purposes of this Agreement:
|
(a)
|
“Cause” means: (i) Grantee’s conviction of a felony, a crime of moral turpitude or fraud or Grantee’s having committed fraud, misappropriation or embezzlement in connection with the performance of Grantee’s duties; (ii) Grantee’s willful and repeated failures to substantially perform assigned duties; or (iii) Grantee’s violation of any provision of a written employment-related agreement between Grantee and the Company or express significant policies of the Company. If the Company terminates Grantee’s employment for Cause, the Company shall give Grantee written notice setting forth the reason for Grantee’s termination not later than 30 days after such termination.
|
(b)
|
“Good Reason” means Grantee’s resignation within 90 days after: (i) a reduction in Grantee’s base salary of 10% or more (unless the reduction is applicable to all similarly situated employees); (ii) a reduction in Grantee’s annual short-term bonus target of 10% or more (unless the reduction is applicable to all similarly situated employees); (iii) a significant diminution in Grantee’s job
|
(c)
|
“Qualifying Change of Control” means a Change of Control (as then defined in the Plan) unless (i) Grantee’s Restricted Shares are assumed by the surviving entity of the Change of Control (or otherwise equitably converted or substituted in connection with the Change of Control in a manner approved by the Committee) or (ii) the Company is the surviving entity of the Change of Control.
|
(d)
|
“Qualifying Termination” means the involuntary termination by the Company (or, as applicable, its successor) of Grantee’s employment as a result of (i) the sale, consolidation or full or partial shutdown of a facility, department or business unit; (ii) a position elimination because of a reorganization or lack of work; or (iii) Grantee’s death or Disability.
|
(e)
|
“Restricted Period” means the period prior to the Vesting Date when the Restricted Shares are subject to the restrictions imposed under Section 2.
|
(f)
|
“Restricted Shares” means, collectively, the original number of restricted shares awarded to Grantee on the Grant Date as designated in the first paragraph of this Agreement, together with any additional restricted shares accumulated from dividends or other distributions in accordance with Section 6 of this Agreement, that are subject to the restrictions imposed under Section 2 below that have not then expired or terminated.
|
(g)
|
“Vesting Date” is defined in Section 3 of this Agreement.
|
(a)
|
as to 100% of the Restricted Shares, on the third anniversary of the Grant Date, provided Grantee has continued in the employment of the Company and/or its Affiliates through such date, or
|
(b)
|
as to 100% of the Restricted Shares, upon the occurrence of a Qualifying Change of Control, provided Grantee has continued in the employment of the Company and/or its Affiliates through such date, or
|
(c)
|
as to 100% of the Restricted Shares, upon (i) the termination of Grantee’s employment under the circumstances described in clause (i) under Section 4(a) below, (ii) Grantee’s qualifying resignation
|
(d)
|
as to the Pro Rata Amount only, upon termination of Grantee’s employment under the circumstances described in Section 4(b)(ii) below.
|
(a)
|
Notwithstanding Section 9 of the Plan, in the event that following a Change of Control that is not a Qualifying Change of Control, (i) Grantee’s employment is terminated without Cause or (ii) Grantee resigns for Good Reason, in each case prior to the second anniversary of the effective date of the Change of Control, the Restricted Shares will vest.
|
(b)
|
Except as provided in Section 4(a) above, (i) if Grantee’s employment is terminated due to Grantee’s death, 100% of the Restricted Shares will vest and (ii) if Grantee’s termination is due to any other Qualifying Termination, the Restricted Shares will vest as follows (such percentage of Restricted Shares then vesting is defined as the “Pro Rata Amount”):
|
Termination Date
|
|
Percent Vesting
|
Prior to the first anniversary of the Grant Date
|
|
0%
|
On or after the first anniversary of the Grant Date and prior to the second anniversary of the Grant Date
|
|
25%
|
On or after the second anniversary of the Grant Date and prior to the third anniversary of the Grant Date
|
|
50%
|
(a)
|
Termination After Change of Control
. With respect to any Participant’s award under the Program, and notwithstanding Section 9 of the 2014 Plan, in the event that following a Change of Control that is not a Qualifying Change of Control, (i) such Participant’s employment is terminated without Cause (as defined below), or (ii) such Participant resigns for Good Reason (as defined below), in each case prior to the second anniversary of the effective date of the Change of Control, the Participant shall retain all of his or her Performance Share Units, contingent upon (i) the Participant executing and not revoking a full release of claims in a form acceptable to the Company within 30 days of his or her termination or resignation, as applicable, and (ii) achievement of the Performance Conditions set forth in Section 5.
|
(b)
|
Voluntary Termination or Qualifying Termination With Continued Board Service
. If a Participant’s employment is terminated voluntarily (including retirement) or such termination is a Qualifying Termination (as defined below) and, in either case, the Participant remains on the board of directors of the Company or any subsidiary or affiliate of the Company whose equity is publicly traded on the New York Stock Exchange or the NASDAQ Stock Market following such termination of employment, the Participant shall retain all of his or her Performance Share Units, contingent upon achievement of the Performance Conditions set forth in Section 5, for as long as the Participant remains on such board of directors, in which case any references herein to such Participant’s employment shall be deemed to include his or her continued service on such board. Except as set forth in the preceding sentence and subsection (a) above, a Participant’s Performance Share Units shall be forfeited upon his or her retirement or resignation as an employee of the Company or an Affiliate.
|
(c)
|
Other Termination
. If a Participant’s employment is involuntarily terminated and such termination is not a Qualifying Termination, the Participant’s Performance Share Units shall be forfeited. Except as provided in subsections (a) and (b) above, (i) if the termination is due to the Participant’s death, the Participant’s estate or beneficiary will retain all of his or her Performance Share Units, contingent upon the Participant’s estate or beneficiary executing and not revoking a full release of claims in a form acceptable to the Company within 30 days of his or her death, and (ii) if the termination is due to any other Qualifying Termination, the Participant will retain a percent of his or her Performance Share Units as set forth below, contingent upon (A) the Participant
|
•
|
Determining and certifying, in writing, the extent to which the Performance Conditions have been achieved prior to any payments under the Program,
|
•
|
Ensuring that the Program is administered in accordance with its provisions and the 2014 Plan,
|
•
|
Approving Program Participants,
|
•
|
Authorizing Performance Share Unit awards to Participants,
|
•
|
Adjusting Performance Share Unit awards to account for extraordinary events,
|
•
|
Serving as the final arbiter of any disagreement between Program Participants, Company management, Program administrators, and any other interested parties to the Program, and
|
•
|
Maintaining final authority to amend, modify or terminate the Program at any time.
|
ANADARKO PETROLEUM CORPORATION
|
ANTERO RESOURCES CORPORATION
|
APACHE CORPORATION
|
CABOT OIL & GAS CORPORATION
|
CHESAPEAKE ENERGY CORPORATION
|
CIMAREX ENERGY CO.
|
CONCHO RESOURCES INC.
|
CNX RESOURCES CORPORATION
|
CONTINENTAL RESOURCES, INC.
|
DEVON ENERGY CORPORATION
|
DIAMONDBACK ENERGY, INC.
|
ENCANA CORP.
|
EOG RESOURCES, INC.
|
HESS CORPORATION
|
MARATHON OIL CORPORATION
|
NEWFIELD EXPLORATION COMPANY
|
NOBLE ENERGY, INC.
|
PIONEER NATURAL RESOURCES COMPANY
|
RANGE RESOURCES CORPORATION
|
(a)
|
Cumulative Selling, General and Administrative Expense plus Cumulative Production Expense minus Cumulative Production Taxes plus Cumulative Operation and Maintenance Expense
; divided by
|
(b)
|
Cumulative Total Production Sales Volumes
.
|
(a)
|
Capital Expenditures for Covered Wells
; divided by
|
(b)
|
Total Production Sales Volumes for Covered Wells plus Proved Developed Reserves at end of Calculation Period
.
|
•
|
Calculation Period:
means the period commencing January 1, 2018 and ending December 31, 2020; provided, however, in the event that a Qualifying Change of Control occurs prior to the filing of the Company’s Form 10-K for the year ending December 31, 2020, Calculation Period means the period consisting of completed quarters in the Performance Period for which a Form 10-Q or Form 10-K has been filed.
|
•
|
Capital Expenditures for Covered Wells:
means the sum of the gross capital expenditures by the Company charged to the AFE, capitalized interest, capitalized overhead and pad costs, in each case for the Covered Wells from inception of the Covered Well through the end of the Calculation Period.
|
•
|
Covered Wells:
means gross development wells that are (a) SPUD and TIL’d by the Company or (b) SPUD and plugged by the Company, in each case during the Calculation Period but excluding such wells as are disposed of during the Calculation Period.
|
•
|
Cumulative:
means the aggregate amount over the Calculation Period.
|
•
|
(A)
Operation and Maintenance Expense
, (B)
Production Expense
, (C)
Production Taxes,
(D)
Selling, General and Administrative Expense
and (E)
Total Production Sales Volumes
: mean, in each case, the amount set forth for such line item as reported in the Company’s Forms 10-K, in the case of completed years
|
•
|
Proved Developed Reserves at end of Calculation Period:
means the gross proved developed reserves for the Covered Wells at the end of the Calculation Period. Such amount shall be determined based upon the Company’s internal books and records, included annually in the Company’s Form 10-K or proxy statement and subject to audit or review procedures by the Company’s independent reserve auditor, currently Ryder Scott Company, L.P. (
Ryder Scott
).
|
•
|
SPUD:
means drilling operations commenced.
|
•
|
TIL’d:
means turned-in-line.
|
•
|
Total Production Sales Volumes for Covered Wells
: means the gross production sales volumes associated with the Covered Wells during the Calculation Period. Such amount shall be determined based upon the Company’s internal books and records, included annually in the Company’s Form 10-K or proxy statement and subject to audit or review procedures by Ryder Scott.
|
(a)
|
(i)
Cumulative Earnings Before Interest and Taxes
divided by the
Calculation Factor
multiplied by (ii) four; divided by
|
(b)
|
(i) (X) the sum of
Total Assets
minus
Current Liabilities
minus
Cash
at each quarter end during the
Calculation Period
plus (Y) for each quarter during the
Calculation Period
in which an
Impairment
occurs and for each subsequent quarter until and excluding the quarter in which the related asset is sold, the amount by which
Net Property, Plant and Equipment
was reduced by such
Impairment
; divided by (ii) the
Calculation Factor
.
|
•
|
Calculation Period:
means the period commencing January 1, 2018 and ending December 31, 2020; provided, however, in the event that a Qualifying Change of Control occurs prior to the filing of the Company’s Form 10-K for the year ending December 31, 2020, Calculation Period means the period consisting of completed quarters in the Performance Period for which a Form 10-Q or Form 10-K has been filed.
|
•
|
Calculation Factor:
means the number of completed quarters in the Calculation Period.
|
•
|
(A)
Cash
, (B)
Current Liabilities
, (C)
Net Property, Plant and Equipment
, (D)
Net Income
, and (E)
Total Assets
: mean, in each case, the amount set forth for such line item in the Company’s annual financial statements, in the case of completed years, or in the Company’s quarterly financial statements, in the case of shorter periods, as filed with the SEC. For the avoidance of doubt, Net Income is Net Income before deductions for noncontrolling interests.
|
•
|
Cumulative:
means the aggregate amount over the Calculation Period.
|
•
|
Earnings Before Interest and Taxes:
means (a) Net Income plus interest expense plus income tax expense plus Impairments, in each case for the Calculation Period plus/minus (b) the loss/gain on the sale or other disposition of Huron/Permian Assets during the Calculation Period.
|
•
|
Huron/Permian Assets:
means assets located in the Huron or Permian.
|
•
|
Impairments:
means impairments on the Huron/Permian Assets to the extent included in Earnings Before Interest and Taxes.
|
|
Less than Threshold
|
Threshold
|
Below Target
|
Target
|
Exceeds
|
Stretch
|
Performance Goal
|
18
th
– 20
th
rank
|
17
th
rank
|
15
th
rank
|
10
th
rank
|
5
th
rank
|
3
rd
– 1
st
rank
|
Payout Factor
|
0%
|
16.7%
|
50%
|
100%
|
200%
|
300%
|
|
Less than Threshold
|
Threshold
|
Target
|
Exceeds
|
Stretch
|
Performance Goal
|
Less than $.61/Mcfe
|
$.61/Mcfe
|
$.45/Mcfe
|
$.35/Mcfe
|
$.32/Mcfe
|
Payout Factor
|
0%
|
50%
|
100%
|
200%
|
300%
|
|
Less than Threshold
|
Threshold
|
Target
|
Exceeds
|
Stretch
|
Performance Goal
|
Less than $.52/Mcfe
|
$.52/Mcfe
|
$.44/Mcfe
|
$.41/Mcfe
|
$.38/Mcfe
|
Payout Factor
|
0%
|
50%
|
100%
|
200%
|
300%
|
ROCE Achieved
|
ROCE Modifier
|
7% or less
|
0.9 x
|
9%
|
1.0 x
|
11% or more
|
1.1 x
|
•
|
“2018 Rice Operating Synergies” shall mean the amount by which 2018 Operating Efficiency (as defined below) is less than $0.54 per Mcfe.
|
•
|
“2018 Operating Efficiency” shall mean Operating Efficiency as defined in the Program document, except that (i) “Calculation Period” shall mean the period commencing January 1, 2018 and ending on December 31, 2018 (“First Year”); provided, however, in the event that a Qualifying Change of Control occurs prior to the filing of the Company’s Form 10-K with the SEC for the year ending December 31, 2018, the Calculation Period shall mean the period consisting of completed quarters in the First Year for which a Form 10-Q has been filed with the SEC and (ii) each of Operation and Maintenance Expense, Production Expense, Production Taxes, and Selling, General and Administrative Expense shall exclude (Y) Rice transition costs and (Z) costs associated with the Company’s analyses of (A) the Company’s “sum-of-the-parts” discount and (B) the structure of the Company’s master limited partnerships, and the implementation of any changes recommended as a result of either of the foregoing.
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•
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“2018 Rice Development Synergies” shall mean the amount by which 2018 Development Efficiency (as defined below) is less than $0.52 per Mcfe. “2018 Development Efficiency” shall mean Development Efficiency as defined in the Program document except that “Calculation Period” shall be calculated as defined above in this Participant Award Agreement.
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•
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Miscellaneous Allowance in the amount of $10,000. The Miscellaneous Allowance is not grossed up for tax purposes.
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•
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Please see the attached Moving and Relocation Benefit Summary for additional details on this benefit.
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•
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EQT’s policy provides for up to 90 days of estimated temporary living expenses. You will be eligible for up to one year of temporary living expenses.
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•
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Action by the Boards of Directors of EQT Corporation and EQT Midstream Partners, LP and EQT’s Committees to elect you to the positions identified above and to approve your compensation;
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•
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In accordance with the Federal Immigration Reform and Control Act of 1986, you are required to provide EQT with verification of your identity and eligibility to work in the United States; and
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•
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Submitting to and successfully completing all pre-employment assessments including a drug screen, background check and our Director and Officer Questionnaire, and execution and delivery of the Non-Compete Agreement.
|
S
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I hereby elect to participate in the Executive Alternative Work Arrangement Classification as described in paragraph 9 of the above Confidentiality, Non-Solicitation and Non-Competition Agreement. I hereby agree to execute an Executive Alternative Work Arrangement Employment Agreement in a form substantially similar to the one attached hereto as Exhibit A, within 90 days prior to my relinquishment of full-time status, which agreement will become effective automatically on the day following my Eligible Termination. I understand that I will not be eligible for the Executive Alternative Work Arrangement, including the post-employment benefits described therein if my termination from employment is not an Eligible Termination.
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£
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I hereby decline to participate in the Executive Alternative Work Arrangement Classification as described in paragraph 9 of the above Confidentiality, Non-Solicitation and Non-Competition Agreement.
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EQT CORPORATION
By:
Title
Date
|
|
EMPLOYEE
Name: Jeremiah J. Ashcroft III
Date
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Entity
|
|
Jurisdiction
|
Alpha Shale Holdings LLC
|
|
Delaware
|
Alpha Shale Resources LP
|
|
Delaware
|
American Shale Development, Inc.
|
|
Delaware
|
Blue Tiger Oilfield Services, LLC
|
|
Delaware
|
EQM Gathering Holdings, LLC
|
|
Delaware
|
EQM Gathering Opco, LLC
|
|
Delaware
|
EQT Capital Corporation
|
|
Delaware
|
EQT CNG, LLC
|
|
Delaware
|
EQT Energy, LLC
|
|
Delaware
|
EQT Energy Supply, LLC
|
|
Delaware
|
EQT Energy Supply Holdings, LP
|
|
Delaware
|
EQT Gathering, LLC
|
|
Delaware
|
EQT Gathering Holdings, LLC
|
|
Delaware
|
EQT GP Corporation
|
|
Delaware
|
EQT GP Holdings, LP
|
|
Delaware
|
EQT GP Services, LLC
|
|
Delaware
|
EQT Investments Holdings, LLC
|
|
Delaware
|
EQT IP Ventures, LLC
|
|
Delaware
|
EQT Midstream Finance Corporation
|
|
Delaware
|
EQT Midstream Partners, LP
|
|
Delaware
|
EQT Midstream Services, LLC
|
|
Delaware
|
EQT Production Company
|
|
Pennsylvania
|
EQT Production Texas, LLC
|
|
Delaware
|
Equitrans Investments, LLC
|
|
Delaware
|
Equitrans Services, LLC
|
|
Delaware
|
Equitrans, LP
|
|
Pennsylvania
|
ET Blue Grass Clearing, LLC
|
|
Pennsylvania
|
ET Blue Grass, LLC
|
|
Delaware
|
MVP Holdco, LLC
|
|
Delaware
|
Rager Mountain Storage Company, LLC
|
|
Delaware
|
Rice Drilling B LLC
|
|
Delaware
|
Rice Energy Operating, LLC
|
|
Delaware
|
Rice Marketing LLC
|
|
Delaware
|
Rice Midstream GP, LLC
|
|
Delaware
|
Rice Midstream GP Holdings LP
|
|
Delaware
|
Rice Midstream GP Management LLC
|
|
Delaware
|
Rice Midstream Holdings LLC
|
|
Delaware
|
Rice Midstream Management LLC
|
|
Delaware
|
Rice Midstream Partners LP
|
|
Delaware
|
Rice Water Services (PA) LLC
|
|
Delaware
|
Rice Water Services (OH) LLC
|
|
Delaware
|
Rice Olympus Midstream LLC
|
|
Delaware
|
Rice Poseidon Midstream LLC
|
|
Delaware
|
Strike Force Midstream Holdings LLC
|
|
Delaware
|
Strike Force Midstream LLC
|
|
Delaware
|
Trans Energy, Inc.
|
|
Nevada
|
Vantage Energy, LLC
|
|
Delaware
|
Vantage Energy Appalachia LLC
|
|
Pennsylvania
|
Vantage Energy Holdings LLC
|
|
Delaware
|
Strike Force East LLC
|
|
Delware
|
Strike Force South LLC
|
|
Delaware
|
Vantage Energy Appalachia II LLC
|
|
Delaware
|
Vantage Energy II Alpha, LLC
|
|
Delaware
|
Vantage Energy II Access, LLC
|
|
Delaware
|
Vantage Energy II, LLC
|
|
Delaware
|
Vantage Energy Piceance LLC
|
|
Delaware
|
Vantage Energy Unita LLC
|
|
Delaware
|
Vantage Fort Worth Energy LLC
|
|
Delaware
|
Vista Gathering, LLC
|
|
Delaware
|
EQT MG, LLC
|
|
Delaware
|
EQT RE, LLC
|
|
Delaware
|
EQT SG, LLC
|
|
Delaware
|
Rice Drilling C LLC
|
|
Pennsylvania
|
Rice Drilling D LLC
|
|
Delaware
|
Rice Energy Marketing LLC
|
|
Delaware
|
Rice Energy Sub Holdings LLC
|
|
Delaware
|
Rice GPH LLC
|
|
Delaware
|
Rice Midstream OpCo LLC
|
|
Delaware
|
Rice West Virginia Midstream LLC
|
|
Delaware
|
•
|
Registration Statement (Post-Effective Amendment No. 1 on Form S-8 to Form S-4 No. 333-219508) pertaining to the Rice Energy Inc. 2014 Long-Term Incentive Plan,
|
•
|
Registration Statement (Form S-8 No. 333-221529) pertaining to the Rice Energy Inc. 2014 Long-Term Incentive Plan,
|
•
|
Registration Statement (Form S-3 No. 333-158198) pertaining to the 2009 Dividend Reinvestment and Stock Purchase Plan,
|
•
|
Registration Statement (Form S-3 No. 333-214092) pertaining to the registration of Debt Securities, Preferred Stock and Common Stock,
|
•
|
Registration Statement (Form S-8 No. 333-185845) pertaining to the Employee Savings Plan,
|
•
|
Registration Statement (Form S-8 No. 333-82193) pertaining to the 1999 Non-Employee Directors’ Stock Incentive Plan,
|
•
|
Registration Statement (Form S-8 No. 333-32410) pertaining to the Deferred Compensation Plan and the Directors’ Deferred Compensation Plan,
|
•
|
Registration Statement (Form S-8 No. 333-122382) pertaining to the 2005 Employee Deferred Compensation Plan and the 2005 Directors’ Deferred Compensation Plan,
|
•
|
Registration Statement (Form S-8 No. 333-152044) pertaining to the 2008 Employee Stock Purchase Plan,
|
•
|
Registration Statement (Form S-8 No. 333-158682) pertaining to the 2009 Long-Term Incentive Plan, and
|
•
|
Registration Statement (Form S-8 No. 333-195625) pertaining to the 2014 Long-Term Incentive Plan;
|
February 15, 2018
|
|
|
/s/ Steven T. Schlotterbeck
|
|
Steven T. Schlotterbeck
|
|
President and Chief Executive Officer
|
February 15, 2018
|
|
|
|
|
/s/ Robert J. McNally
|
|
Robert J. McNally
|
|
Senior Vice President and Chief Financial Officer
|
/s/ Steven T. Schlotterbeck
|
|
February 15, 2018
|
Steven T. Schlotterbeck
President and Chief Executive Officer
|
|
|
|
|
|
|
|
|
/s/ Robert J. McNally
|
|
February 15, 2018
|
Robert J. McNally
Senior Vice President and Chief Financial Officer
|
|
\s\ Gabrielle Morrow
|
Gabrielle Morrow, P. E.
|
TBPE License No. 109935
|
Senior Vice President
|
As of December 31, 2017
|
|
|
Proved
|
||||||
|
|
Developed
|
|
|
|
Total
|
||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
Net Reserves
|
|
|
|
|
|
|
|
|
Gas – MMcf
|
|
9,959,583
|
|
188,422
|
|
9,677,693
|
|
19,825,698
|
Plant Products - Mbbl
|
|
179,630
|
|
479
|
|
78,337
|
|
258,446
|
Oil/Condensate - Mbbl
|
|
10,731
|
|
0
|
|
0
|
|
10,731
|
(1)
|
completion intervals which are open at the time of the estimate, but which have not started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|