Document
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2019
OR

¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                          to                         

Commission file number 001-37907

 
EXTRACTION OIL & GAS, INC.
 
 
(Exact name of registrant as specified in its charter)
 

DELAWARE
 
46-1473923
(State or other jurisdiction of
incorporation or organization)
 
(IRS Employer
Identification No.)
 
 
 
370 17th Street, Suite 5300
Denver, Colorado
 
80202
(Address of principal executive offices)
 
(Zip Code)

 
(720) 557-8300
 
 
(Registrant’s telephone number, including area code)
 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  x    No  ¨

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

Large accelerated filer
x
Accelerated filer
¨
Non-accelerated filer
¨
Smaller reporting company
¨
 
 
Emerging growth company
¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
Securities registered pursuant to Section 12(b) of the Act:
 
 
 
 
 
Title of each class
 
Trading Symbol(s)
 
Name of exchange on which registered
Common Stock, par value $0.01
 
XOG
 
NASDAQ Global Select Market

The total number of shares of common stock, par value $0.01 per share, outstanding as of April 29, 2019 was 162,849,212.

 



Table of Contents

EXTRACTION OIL & GAS, INC.
TABLE OF CONTENTS

 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

1

Table of Contents

GLOSSARY OF OIL AND GAS TERMS

Unless indicated otherwise or the context otherwise requires, references in this Quarterly Report on Form 10-Q (“Quarterly Report”) to the "Company," “Extraction,” "us," "we," "our," or "ours" or like terms refer to Extraction Oil & Gas, Inc., together with its consolidated subsidiaries. When the context requires, we refer to these entities separately.

The terms defined in this section are used throughout this Quarterly Report:

"Bbl" means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

"Bbl/d" means Bbl per day.

"Btu" means one British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.

"BOE" means barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

"BOE/d" means BOE per day.

"CIG" means Colorado Interstate Gas, which is calculated as NYMEX Henry Hub index price less the Rocky Mountains (CIGC) Inside FERC fixed price.

"Completion" means the installation of permanent equipment for the production of oil or natural gas.

"Field" means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

"Fracturing" or "hydraulic fracturing" means a procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases permeability and porosity.

"Gas" or "Natural gas" means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.

"Gross Acres" or "Gross Wells" means the total acres or wells, as the case may be, in which we have a working interest.

"Henry Hub" means Henry Hub index. Natural gas distribution point where prices are set for natural gas futures contracts traded on the NYMEX.

"Horizontal drilling" or "horizontal well" means a wellbore that is drilled laterally.

"Leases" means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.

"MBbl" One thousand barrels of oil, condensate or NGL.

"MBoe" One thousand barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

"Mcf" is an abbreviation for "1,000 cubic feet," which is a unit of measurement of volume for natural gas.

"MMBtu" One million Btus.

"MMcf" is an abbreviation for "1,000,000 cubic feet," which is a unit of measurement of volume for natural gas.



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Table of Contents

"Net Acres" or "Net Wells" is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.

"NGL" means natural gas liquids.

"NYMEX" means New York Mercantile Exchange.

"Proved reserves" means those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

"Reasonable certainty" means a high degree of confidence that the reserves quantities will be recovered, when a deterministic method is used. A high degree of confidence exists if the reserves quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical), engineering and economic data are made to estimated ultimate recovery (“EUR”) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

"Reservoir" means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

"Royalty" means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.

"SEC" means the Securities and Exchange Commission.

"Undeveloped leasehold acreage" means the leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains estimated net proved reserves.

"Wattenberg Field" means the Greater Wattenberg Area within the Denver-Julesburg Basin of Colorado as defined by the Colorado Oil and Gas Conservation Commission, which are the lands from and including Townships 2 South to 7 North and Ranges 61 West to 69 West, Six Principal Median.

"Working interest" means an interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the landowner's royalty, any overriding royalties, production costs, taxes and other costs.

"WTI" means the price of West Texas Intermediate oil on the NYMEX.





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Table of Contents

PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(Unaudited)
 
March 31,
2019
 
December 31,
2018
ASSETS
 
 
 
Current Assets:
 
 
 
Cash and cash equivalents
$
112,771

 
$
234,986

Accounts receivable
 
 
 
Trade
27,088

 
41,695

Oil, natural gas and NGL sales
88,244

 
91,225

Inventory and prepaid expenses
27,804

 
26,816

Commodity derivative asset
226

 
48,907

Assets held for sale

 
21,008

Total Current Assets
256,133

 
464,637

Property and Equipment (successful efforts method), at cost:
 
 
 
Proved oil and gas properties
4,097,082

 
3,916,622

Unproved oil and gas properties
613,153

 
609,284

Wells in progress
130,135

 
144,323

Less: accumulated depletion, depreciation and amortization
(1,267,393
)
 
(1,152,590
)
Net oil and gas properties
3,572,977

 
3,517,639

Gathering systems and facilities
173,333

 
114,469

Other property and equipment, net of accumulated depreciation
47,386

 
39,849

Net Property and Equipment
3,793,696

 
3,671,957

Non-Current Assets:
 
 
 
Commodity derivative asset
388

 
8,432

Other non-current assets
46,782

 
21,001

Total Non-Current Assets
47,170

 
29,433

Total Assets
$
4,096,999

 
$
4,166,027

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
Current Liabilities:
 
 
 
Accounts payable and accrued liabilities
$
193,111

 
$
186,218

Revenue payable
96,357

 
117,344

Production taxes payable
57,025

 
57,516

Commodity derivative liability
49,358

 
196

Accrued interest payable
17,820

 
22,249

Asset retirement obligations
15,189

 
15,729

Liabilities related to assets held for sale

 
3,146

Total Current Liabilities
428,860

 
402,398

Non-Current Liabilities:
 
 
 
Credit facility
325,000

 
285,000

Senior Notes, net of unamortized debt issuance costs
1,097,970

 
1,132,659

Production taxes payable
139,212

 
115,607

Commodity derivative liability
5,876

 

Other non-current liabilities
22,424

 
8,072

Asset retirement obligations
54,849

 
54,062

Deferred tax liability
80,176

 
109,176

Total Non-Current Liabilities
1,725,507

 
1,704,576

Total Liabilities
2,154,367

 
2,106,974

Commitments and Contingencies—Note 11
 
 
 
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 issued and outstanding
165,963

 
164,367

Stockholders' Equity:
 
 
 
Common stock, $0.01 par value; 900,000,000 shares authorized; 164,112,268 and 171,666,485 issued and outstanding
1,601

 
1,678

Treasury stock, at cost, 12,367,312 and 4,543,262 shares
(64,872
)
 
(32,737
)
Additional paid-in capital
2,157,923

 
2,153,661

Accumulated deficit
(469,820
)
 
(375,788
)
Total Extraction Oil & Gas, Inc. Stockholders' Equity
1,624,832

 
1,746,814

Noncontrolling interest
151,837

 
147,872

Total Stockholders' Equity
1,776,669

 
1,894,686

Total Liabilities and Stockholders' Equity
$
4,096,999

 
$
4,166,027

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Table of Contents

EXTRACTION OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)
 
  For the Three Months Ended March 31,
 
2019
 
2018
Revenues:
 
 
 
Oil sales
$
165,424

 
$
180,263

Natural gas sales
35,892

 
24,081

NGL sales
20,601

 
25,871

Total Revenues
221,917

 
230,215

Operating Expenses:
 
 
 
Lease operating expenses
21,857

 
20,703

Transportation and gathering
10,365

 
7,539

Production taxes
18,129

 
20,323

Exploration expenses
6,194

 
7,267

Depletion, depreciation, amortization and accretion
118,770

 
96,207

Impairment of long lived assets
8,248

 

Gain on sale of oil and gas properties
(222
)
 

General and administrative expenses
27,652

 
30,969

Total Operating Expenses
210,993

 
183,008

Operating Income
10,924

 
47,207

Other Income (Expense):
 
 
 
Commodity derivatives loss
(122,091
)
 
(50,328
)
Interest expense
(13,008
)
 
(63,302
)
Other income
1,143

 
328

Total Other Income (Expense)
(133,956
)
 
(113,302
)
Loss Before Income Taxes
(123,032
)
 
(66,095
)
Income tax benefit
29,000

 
14,100

Net Loss
$
(94,032
)
 
$
(51,995
)
Net income attributable to noncontrolling interest
3,975

 

Net Loss Attributable to Extraction Oil & Gas, Inc.
(98,007
)
 
(51,995
)
Adjustments to reflect Series A Preferred Stock dividends and accretion of discount
(4,317
)
 
(4,159
)
Net Loss Attributable to Common Shareholders
(102,324
)
 
(56,154
)
Loss Per Common Share (Note 10)
 
 
 
Basic and diluted
$
(0.60
)
 
$
(0.32
)
Weighted Average Common Shares Outstanding
 
 
 
Basic and diluted
170,702

 
174,213











THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Table of Contents

EXTRACTION OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS’ EQUITY AND NONCONTROLLING INTEREST
(In thousands)
(Unaudited)

 
Common Stock
 
Treasury Stock
 
 
 
 
 
 
 
Noncontrolling interest
 
 
 
Shares
 
Amount
 
Shares
 
Amount
 
Additional Paid in Capital
 
Accumulated Deficit
 
Extraction Oil & Gas, Inc. Stockholders' Equity
 
Amount
 
Total Stockholders' Equity
Balance at January 1, 2019
176,210
 
$1,678
 
4,543
 
$(32,737)
 
$2,153,661
 
$(375,788)
 
$1,746,814
 
$147,872
 
$1,894,686
Preferred Units issuance costs and discount
 
 
 
 
 
 
 
(10)
 
(10)
Preferred Units commitment fees and dividends paid-in-kind
 
 
 
 
(3,975)
 
 
(3,975)
 
3,975
 
Stock-based compensation
 
 
 
 
13,008
 
 
13,008
 
 
13,008
Series A Preferred Stock dividends
 
 
 
 
(2,721)
 
 
(2,721)
 
 
(2,721)
Accretion of beneficial conversion feature on Series A Preferred Stock
 
 
 
 
(1,596)
 
 
(1,596)
 
 
(1,596)
Repurchase of common stock
 
(77)
 
7,824
 
(32,135)
 
 
 
(32,212)
 
 
(32,212)
Shares issued under LTIP, including payment of tax withholdings using withheld shares
270
 
 
 
 
(454)
 
 
(454)
 
 
(454)
Net loss
 
 
 
 
 
(94,032)
 
(94,032)
 
 
(94,032)
Balance at March 31, 2019
176,480
 
$1,601
 
12,367
 
$(64,872)
 
$2,157,923
 
$(469,820)
 
$1,624,832
 
$151,837
 
$1,776,669

 
Common Stock
 
Treasury Stock
 
 
 
 
 
 
 
Noncontrolling interest
 
 
 
Shares
 
Amount
 
Shares
 
Amount
 
Additional Paid in Capital
 
Accumulated Deficit
 
Extraction Oil & Gas, Inc. Stockholders' Equity
 
Amount
 
Total Stockholders' Equity
Balance at January 1, 2018
172,060

 
1,718

 
165

 
(2,105
)
 
2,114,795

 
(497,643
)
 
1,616,765

 

 
1,616,765

Stock-based compensation
2,794

 

 

 

 
15,721

 

 
15,721

 

 
15,721

Series A Preferred Stock dividends

 

 

 

 
(2,721
)
 

 
(2,721
)
 

 
(2,721
)
Accretion of beneficial conversion feature on Series A Preferred Stock

 

 

 

 
(1,438
)
 

 
(1,438
)
 

 
(1,438
)
Repurchase of common stock

 

 
166

 
(2,309
)
 

 

 
(2,309
)
 

 
(2,309
)
Shares issued under LTIP, including payment of tax withholdings using withheld shares
852

 

 

 

 
(2,305
)
 

 
(2,305
)
 

 
(2,305
)
Net loss

 

 

 

 

 
(51,995
)
 
(51,995
)
 

 
(51,995
)
Balance at March 31, 2018
175,706

 
1,718

 
331

 
(4,414
)
 
2,124,052

 
(549,638
)
 
1,571,718

 

 
1,571,718














THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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EXTRACTION OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
 
  For the Three Months Ended March 31,
 
2019
 
2018
Cash flows from operating activities:
 
 
 
Net loss
$
(94,032
)
 
$
(51,995
)
Reconciliation of net loss to net cash provided by operating activities:
 
 
 
Depletion, depreciation, amortization and accretion
118,770

 
96,207

Abandonment and impairment of unproved properties
3,893

 
3,923

Impairment of long lived assets
8,248

 

Gain on sale of oil and gas properties
(222
)
 

Gain on repurchase of 2026 Senior Notes
(7,317
)
 

Amortization of debt issuance costs
1,498

 
10,442

Non-cash lease expense
2,486

 

Deferred rent

 
785

Commodity derivatives loss
122,091

 
50,328

Settlements on commodity derivatives
(3,538
)
 
(22,293
)
Premiums paid on commodity derivatives

 
(12,117
)
Earnings in unconsolidated subsidiaries
(338
)
 
(339
)
Distributions from unconsolidated subsidiaries
1,751

 
339

Make-whole premium expense on 2021 Senior Notes

 
35,600

Deferred income tax benefit
(29,000
)
 
(14,100
)
Stock-based compensation
13,008

 
15,721

Changes in current assets and liabilities:
 
 
 
Accounts receivable—trade
11,908

 
(15,351
)
Accounts receivable—oil, natural gas and NGL sales
2,981

 
1,627

Inventory and prepaid expenses
136

 
(353
)
Accounts payable and accrued liabilities
(10,638
)
 
(24,046
)
Revenue payable
(21,506
)
 
26,660

Production taxes payable
22,919

 
24,845

Accrued interest payable
(4,429
)
 
(4,702
)
Asset retirement expenditures
(4,558
)
 
(1,927
)
Net cash provided by operating activities
134,111

 
119,254

Cash flows from investing activities:
 
 
 
Oil and gas property additions
(188,027
)
 
(258,069
)
Sale of oil and gas properties
16,521

 

Gathering systems and facilities additions
(49,175
)
 
(5,996
)
Other property and equipment additions
(8,213
)
 
(1,157
)
Investment in unconsolidated subsidiaries
(4,929
)
 

Distributions from unconsolidated subsidiary, return of capital
1,448

 
137

Net cash (used in) provided by investing activities
(232,375
)
 
(265,085
)
Cash flows from financing activities:
 
 
 
Borrowings under credit facility
65,000

 
245,000

Repayments under credit facility
(25,000
)
 
(235,000
)
Proceeds from the issuance of 2026 Senior Notes

 
739,664

Repayments of 2021 Senior Notes

 
(550,000
)
Make-whole premium paid on 2021 Senior Notes

 
(35,600
)
Cash paid for repurchase of 2026 Senior Notes
(28,460
)
 

Preferred Unit issuance costs
(10
)
 

Repurchase of common stock
(32,212
)
 
(2,309
)
Payment of employee payroll withholding taxes
(454
)
 
(2,305
)
Dividends on Series A Preferred Stock
(2,721
)
 
(2,721
)
Debt and equity issuance costs
(94
)
 
(2,303
)
Net cash (used in) provided by financing activities
(23,951
)
 
154,426

Increase (decrease) in cash, cash equivalents and restricted cash
(122,215
)
 
8,595

Cash, cash equivalents and restricted cash at beginning of period
234,986

 
6,768

Cash, cash equivalents and restricted cash at end of the period
$
112,771

 
$
15,363





THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Table of Contents

Supplemental cash flow information:
 
 
 
Property and equipment included in accounts payable and accrued liabilities
$
143,168

 
$
137,443

Cash paid for interest
$
25,265

 
$
24,534

Accretion of beneficial conversion feature of Series A Preferred Stock
$
1,596

 
$
1,438

Preferred Units commitment fees and dividends paid-in-kind
$
3,975

 
$























































THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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EXTRACTION OIL & GAS, INC.
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Business and Organization

Extraction Oil & Gas, Inc. (the “Company” or “Extraction”) is an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of Colorado. The Company and its subsidiaries are focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, as well as the design and support of midstream assets to gather and process crude oil and gas production focused in the DJ Basin of Colorado. Extraction is a public company listed for trading on the NASDAQ Global Select Market under the symbol "XOG".

Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company and an unrestricted subsidiary of the Company, is focused on the construction of gathering systems and facilities operations to serve the development of acreage in the Company’s Hawkeye and Southwest Wattenberg areas. Midstream assets of Elevation are represented as the gathering systems and facilities line item within the condensed consolidated balance sheets. As of March 31, 2019, these gathering systems and facilities operations are not in service, therefore, there are no associated revenues for the three months then ended.

On November 19, 2018, the Company announced the Board of Directors had authorized a program to repurchase up to $100.0 million of the Company's common stock ("Stock Repurchase Program"). On April 1, 2019, the Company announced the Board of Directors had authorized an extension and increase in its ongoing Stock Repurchase Program ("Extended Stock Repurchase Program"). The Company had purchased approximately 13.0 million shares of its common stock for $63.2 million under the Stock Repurchase Program, prior to the Extended Stock Repurchase Program. The Company is authorized to repurchase an incremental $100.0 million in common stock from the date of the Extended Stock Repurchase Program, bringing the total amount authorized to be repurchased to approximately $163.2 million. The Company's Stock Repurchase Program does not obligate it to acquire any specific number of shares and will expire on December 31, 2019. The Company intends to conduct any open market stock repurchase activities in compliance with the safe harbor provisions of Rule 10b-18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). During the three months ended March 31, 2019, the Company repurchased approximately 7.7 million shares of its common stock for $31.5 million. Subsequent to March 31, 2019 through the date of this filing, the Company repurchased approximately 1.3 million additional shares of its common stock for $5.5 million.

Note 2—Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements

Basis of Presentation

The unaudited condensed consolidated financial statements include the accounts of the Company, including its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. The financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States (“GAAP”) and the Securities and Exchange Commission rules and regulation for interim financial reporting. In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of the condensed consolidated financial information, have been included. However, operating results for the period presented are not necessarily indicative of the results that may be expected for a full year. Interim condensed consolidated financial statements and the year-end balance sheet do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes included in the Company’s Annual Report.

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 2 to the Company’s consolidated financial statements in its Annual Report and are supplemented by the notes to the unaudited condensed consolidated financial statements in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report.


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Leases

The Company accounts for leases in accordance with Accounting Standards Codification ("ASC") 842, Leases, which it adopted on January 1, 2019, applying the modified retrospective transition approach as of the effective date of adoption (see "Recent Accounting Pronouncements" for impacts of adoption).

The Company enters into operating leases for certain drilling equipment, completions equipment, equipment ancillary to drilling and completions, office facilities, compressors and office equipment. Under ASC 842, a contract is or contains a lease when (i) the contract contains an explicitly or implicitly identified asset and (ii) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. The Company assess whether an arrangement is or contains a lease at inception of the contract. All leases (operating leases), other than those that qualify for the short-term recognition exemption, are recognized as of the lease commencement date on the balance sheet as a liability for its obligation related to the lease and a corresponding asset representing its right to use the underlying asset over the period of use.

The Company's leases have remaining terms up to nine years. Certain of our lease agreements contain options to extend or early terminate the agreement. The lease term used to calculate the lease asset and liability at commencement includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. When determining whether it is reasonably certain that the Company will exercise an option at commencement, it considers various economic factors, including capital expenditure strategies, the nature, length, and underlying terms of the agreement, as well as the uncertainty of the condition of leased equipment at the end of the lease term. Based on these determinations, the Company generally determines that the exercise of renewal options would not be reasonably certain in determining the expected lease term for leases, other than certain operating compressor leases.

The discount rate used to calculate the present value of the future minimum lease payments is the rate implicit in the lease, when readily determinable. As the Company's leases generally do not provide an implicit rate, the Company uses its incremental borrowing rate based on its revolving credit facility, which includes consideration of the nature, term, and geographic location of the leased asset.

Certain of the Company's leases include variable lease payments, including payments that depend on an index or rate, as well as variable payments for items such as property taxes, insurance, maintenance, and other operating expenses associated with leased assets. Payments that vary based on an index or rate are included in the measurement of the Company's lease assets and liabilities at the rate as of the commencement date. All other variable lease payments are excluded from the measurement of the Company's lease assets and liabilities and are recognized in the period in which the obligation for those payments is incurred. The Company's lease agreements do not contain any material residual value guarantees or material restrictive covenants.

The Company has elected, for all classes of underlying assets, to not apply the balance sheet recognition requirements of ASC 842 to leases with a term of one year or less, and instead, recognize the lease payments in the unaudited condensed consolidated statements of operations on a straight-line basis over the lease term. The Company has also made the election, for its certain drilling equipment, completions equipment, equipment ancillary to drilling and completions, compressors and office equipment classes of underlying assets, to account for lease and non-lease components in a contract as a single lease component.


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For the three months ended March 31, 2019, lease costs, which represent the straight-line lease expense of right-of-use ("ROU") assets and short-term leases, were as follows (in thousands):
 
Three Months Ended March 31, 2019
Lease Costs included in the Condensed Consolidated Balance Sheets
 
Proved oil and gas properties, including drilling, completions and ancillary equipment (1)
$
57,200

 
 
Lease Costs included in the Condensed Consolidated Statements of Operations
 
Lease operating expenses (2)
$
5,792

General and administrative expenses (3)
804

Total operating lease costs
6,596

 
 
Total lease costs
$
63,796

 
(1) Represents short-term lease capital expenditures related to drilling rigs, completions equipment and other equipment ancillary to the drilling and completion of wells.
(2) Includes $2.1 million of lease costs and $0.1 million of variable costs associated with operating leases.
(3) Includes $0.4 million of lease costs and $0.3 million of variable costs associated with operating leases, as well as $0.1 million of sublease income.

Supplemental cash flow information related to operating leases for the three months ended March 31, 2019, was as follows (in thousands):
 
Three Months Ended March 31, 2019
Cash paid for amounts included in the measurements of lease liabilities
 
Operating cash flows from operating leases
$
(2,852
)
Right-of-use assets obtained in exchange for lease obligations
 
Operating leases
$
283


Supplemental balance sheet information related to operating leases as of March 31, 2019, were as follows (in thousands, except lease term and discount rate):
 
Classification
 
As of March 31, 2019
Operating Leases
 
 
 
Operating lease right-of-use assets
Other non-current assets
 
$
23,877

Current operating lease liabilities
Accounts payable and accrued liabilities
 
9,987

Non-current operating lease liabilities
Other non-current liabilities
 
19,628

Total operating lease liabilities
 
 
$
29,615

 
 
 
 
Weighted Average Remaining Lease Term in Years
 
 
 
Operating Leases
 
 
5.8

Weighted Average Discount Rate
 
 
 
Operating Leases
 
 
4.7
%


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As of March 31, 2019, the Company had an insignificant amount of additional operating leases that have not yet commenced, of which none included involvement with the construction or design of the underlying asset.

Recent Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, which requires lessee recognition on the balance sheet of a right of use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018. The FASB subsequently issued ASU No. 2017-13, ASU No. 2018-01, ASU No. 2018-10, ASU No. 2018-11 and ASU No. 2019-01, which provided additional implementation guidance. The Company adopted the accounting standard using a modified retrospective transition approach, which applies the provisions of the new guidance at the effective date without adjusting the comparative periods presented. The Company has elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, requires no reassessment of whether existing contracts are or contain leases as well as no reassessment of lease classification for existing leases upon adoption. The Company has also elected the optional practical expedient permitted under the transition guidance within the new standard related to land easements that allows it to carry forward its current accounting treatment for land easements on existing agreements upon adoption. The Company made an accounting policy election to keep leases with an initial term of twelve months or less off of the consolidated balance sheet.

The adoption of this guidance resulted in the recognition of right-of-use ("ROU") assets of approximately $26.3 million, and current and non-current lease liabilities for operating leases of approximately $10.1 million and $21.1 million, respectively, as of January 1, 2019, including immaterial reclassifications of prepaid rent, deferred rent and lease incentive liability balances. The adoption of this guidance did not have a material impact to the Company's cash flows from operating, investing, or financing activities.

In August 2018, the FASB issued Accounting Standards Update ASU No. 2018-13, which improves the disclosure requirements on fair value measurements. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.

Other than as disclosed above or in the Company’s Annual Report, there are no other accounting standards applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company through the date of this filing.

Note 3—Acquisitions and Divestitures

March 2019 Divestiture

On March 27, 2019, the Company completed the sale of its interests in approximately 5,000 net acres of leasehold and producing properties for aggregate sales proceeds of approximately $22.4 million. The effective date for the March 2019 Divestiture was July 1, 2018 with purchase price adjustments calculated as of the closing date of $5.9 million, resulting in net proceeds of $16.5 million. No gain or loss was recognized for the March 2019 Divestiture. The Company continues to explore divestitures, as part of our ongoing initiative to divest of non-strategic assets.

December 2018 Divestitures

In December 2018, the Company completed various sales of its interests in approximately 31,200 net acres of leasehold and primarily non-producing properties, for aggregate sales proceeds of approximately $8.5 million, subject to customary purchase price adjustments, and recognized a loss of $6.1 million for the year ended December 31, 2018.

August 2018 Divestiture

On August 3, 2018, Elevation received proceeds of $83.6 million and recognized a gain of $83.6 million for the year ended December 31, 2018, upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of which Elevation held a 10% membership interest. The Company acquired its interest in exchange for the contribution of an acreage dedication, which is considered a nonfinancial asset.

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April 2018 Divestitures

In April 2018, the Company completed various sales of its interests in approximately 15,100 net acres of leasehold and primarily non-producing properties for aggregate sales proceeds of approximately $72.3 million and recognized a gain of $59.3 million for the year ended December 31, 2018.

April 2018 Acquisition

On April 19, 2018, the Company acquired an unaffiliated oil and gas company's interest in approximately 1,000 net acres of non-producing leasehold primarily located in Arapahoe County, Colorado, (the "April 2018 Acquisition"). Upon closing the seller received approximately $9.4 million in cash. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.

January 2018 Acquisition

On January 8, 2018, the Company acquired an unaffiliated oil and gas company's interest in approximately 1,200 net acres of non-producing leasehold located in Arapahoe County, Colorado, (the "January 2018 Acquisition"). Upon closing the seller received approximately $11.6 million in cash. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.



Note 4—Long‑Term Debt

As of the dates indicated, the Company’s long‑term debt consisted of the following (in thousands):

 
March 31,
2019
 
December 31,
2018
Credit facility due August 16, 2022 (or an earlier time as set forth in the credit facility)
$
325,000

 
$
285,000

2024 Senior Notes due May 15, 2024
400,000

 
400,000

2026 Senior Notes due February 1, 2026
714,223

 
750,000

Unamortized debt issuance costs on Senior Notes
(16,253
)
 
(17,341
)
Total long-term debt
1,422,970

 
1,417,659

Less: current portion of long-term debt

 

Total long-term debt, net of current portion
$
1,422,970

 
$
1,417,659


Credit Facility

In August 2017, the Company entered into an amendment and restatement of its existing credit facility (prior to amendment and restatement, the "Prior Credit Facility"), to provide aggregate commitments of $1.5 billion with a syndicate of banks, which is subject to a borrowing base. The credit facility matures on the earlier of (a) August 16, 2022, (b) April 15, 2021, if (and only if) (i) the Series A Preferred Stock of the Company (the "Series A Preferred Stock") have not been converted into common equity or redeemed prior to April 15, 2021, and (ii) prior to April 15, 2021, the maturity date of the Series A Preferred Stock has not been extended to a date that is no earlier than six months after August 16, 2022 or (c) the earlier termination in whole of the commitments. No principal payments are generally required until the credit agreement matures or in the event that the borrowing base falls below the outstanding balance.

In January 2019, the Company amended its revolving credit facility to permit prepayments and redemptions of its unsecured bonds, subject to certain term, conditions and financial thresholds.

As of March 31, 2019, the credit facility was subject to a borrowing base of $1.2 billion, subject to current elected commitments of $650.0 million. As of March 31, 2019 and December 31, 2018, the Company had outstanding borrowings of $325.0 million and $285.0 million, respectively. As of March 31, 2019 and December 31, 2018, the Company had standby letters of credit of $35.7 million, which reduces the availability of the undrawn borrowing base. At March 31, 2019, the undrawn balance under the credit facility was $325.0 million. As of the date of this filing, the Company has $375.0 million borrowings outstanding under the credit facility.


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The amount available to be borrowed under the Company's revolving credit facility is subject to a borrowing base that is redetermined semiannually on each May 1 and November 1, and will depend on the volumes of the Company's proved oil and gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under the Company's revolving credit facility.

Interest on the credit facility is payable at one of the following two variable rates as selected by the Company: a base rate based on the Prime Rate or the Eurodollar rate, based on LIBOR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the facility as outlined in the pricing grid below. Additionally, the credit facility provides for a commitment fee of 0.375% to 0.50%, depending on borrowing base usage. The grid below shows the Base Rate Margin and Eurodollar Margin depending on the applicable Borrowing Base Utilization Percentage (as defined in the credit facility) as of the date of this filing:

Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage
 
Utilization
 
Eurodollar
Margin
 
Base Rate
Margin
 
Commitment
Fee Rate
Level 1
 
< 25%
 
1.50
%
 
0.50
%
 
0.375
%
Level 2
 
≥ 25% < 50%
 
1.75
%
 
0.75
%
 
0.375
%
Level 3
 
≥ 50% < 75%
 
2.00
%
 
1.00
%
 
0.500
%
Level 4
 
≥ 75% < 90%
 
2.25
%
 
1.25
%
 
0.500
%
Level 5
 
≥ 90%
 
2.50
%
 
1.50
%
 
0.500
%

The credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. Additionally, the credit facility limits the Company entering into hedges in excess of 85% of its anticipated production volumes.

The credit facility also contains financial covenants requiring the Company to comply with a current ratio of its consolidated current assets (includes availability under the revolving credit facility and unrestricted cash and excludes derivative assets) to its consolidated current liabilities (excludes obligations under the revolving credit facility, senior notes and certain derivative liabilities), of not less than 1.0 to 1.0 and to maintain, on the last day of each quarter, a ratio of consolidated debt less cash balances to its consolidated EBITDAX (EBITDAX is defined as net income adjusted for certain cash and non-cash items including DD&A, exploration expense, gains/losses on derivative instruments, amortization of certain debt issuance costs, non-cash compensation expense, interest expense and prepayment premiums on extinguishment of debt) for the four fiscal quarter period most recently ended, of not greater than 4.0:1.0. The Company was in compliance with all financial covenants under the credit facility as of March 31, 2019 and through the filing of this report.

Any borrowings under the credit facility are collateralized by substantially all of the assets of the Company and certain of its subsidiaries, including oil and gas properties, personal property and the equity interests of those subsidiaries. The Company has entered into oil and natural gas hedging transactions with several counterparties that are also lenders under the credit facility. The Company’s obligations under these hedging contracts are secured by the collateral securing the credit facility. Elevation is a separate entity and the assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other subsidiaries. As of March 31, 2019, $90.9 million of cash was held by Elevation and is earmarked for construction of pipeline infrastructure to serve the development of acreage in its Hawkeye and Southwest Wattenberg areas.

2021 Senior Notes

In July 2016, the Company issued at par $550.0 million principal amount of 7.875% Senior Notes due July 15, 2021 (the “2021 Senior Notes” and the offering, the “2021 Senior Notes Offering”). The 2021 Senior Notes bore an annual interest rate of 7.875%. The interest on the 2021 Senior Notes was payable on January 15 and July 15 of each year commencing on January 15, 2017. The Company received net proceeds of approximately $537.2 million after deducting discounts and fees.

Concurrent with the 2026 Senior Notes Offering (as defined below), the Company commenced a cash tender offer to purchase any and all of its 2021 Senior Notes. On January 24, 2018, the Company received approximately $500.6 million aggregate principal amount of the 2021 Senior Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018, the Company made a cash payment of approximately $534.2 million, which includes a principal of

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approximately $500.6 million, a make-whole premium of approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million.

On February 17, 2018, the Company redeemed approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which included a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million.

2024 Senior Notes

In August 2017, the Company issued at par $400.0 million principal amount of 7.375% Senior Notes due May 15, 2024 (the “2024 Senior Notes” and the offering, the “2024 Senior Notes Offering”). The 2024 Senior Notes bear an annual interest rate of 7.375%. The interest on the 2024 Senior Notes is payable on May 15 and November 15 of each year which commenced on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting fees.

The Company's 2024 Senior Notes are its senior unsecured obligations and rank equally in right of payment with all of its other senior indebtedness and senior to any of its subordinated indebtedness. The Company's 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company's current subsidiaries and by certain future restricted subsidiaries that guarantees its indebtedness under a credit facility (the “2024 Senior Note Guarantors”). The notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under its revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of its future subsidiaries that do not guarantee the notes.

The 2024 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company's affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2024 Senior Notes (the “2024 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2024 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2024 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2024 Senior Notes may declare all outstanding 2024 Senior Notes to be due and payable immediately.

2026 Senior Notes

In January 2018, the Company issued at par $750.0 million principal amount of 5.625% Senior Notes due February 1, 2026 (the “2026 Senior Notes” and the offering, the “2026 Senior Notes Offering”). The 2026 Senior Notes bear an annual interest rate of 5.625%. The interest on the 2026 Senior Notes is payable on February 1 and August 1 of each year commencing on August 1, 2018. The Company received net proceeds of approximately $737.9 million after deducting fees. The Company used $534.2 million of the net proceeds from the 2026 Senior Notes Offering to fund the tender offer for its 2021 Senior Notes, $52.7 million to redeem any 2021 Senior Notes not tendered and the remainder for general corporate purposes.

The Company's 2026 Senior Notes are the Company's senior unsecured obligations and rank equally in right of payment with all of the Company's other senior indebtedness and senior to any of the Company's subordinated indebtedness. The Company's 2026 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company's current subsidiaries and by certain future restricted subsidiaries that guarantee the Company's indebtedness under a credit facility. The 2026 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under the Company's revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of certain of the Company's future restricted subsidiaries that do not guarantee the 2026 Senior Notes.
    
The 2026 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company’s and the Guarantors’ ability to make investments; declare or pay any dividend or make any other payment to holders of the

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Company’s or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2026 Senior Notes (the “2026 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2026 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2026 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2026 Senior Notes may declare all outstanding 2026 Senior Notes to be due and payable immediately.

Debt Issuance Costs

As of March 31, 2019, the Company had debt issuance costs, net of accumulated amortization, of $3.0 million related to its credit facility which has been reflected on the Company’s balance sheet within the line item other non‑current assets. As of March 31, 2019, the Company had debt issuance costs, net of accumulated amortization, of $16.3 million related to its 2024 and 2026 Senior Notes (collectively, the "Senior Notes") which has been reflected on the Company's consolidated balance sheet within the line item Senior Notes, net of unamortized debt issuance costs. Debt issuance costs include origination, legal, engineering and other fees incurred in connection with the Company’s credit facility and Senior Notes. For the three months ended March 31, 2019, the Company recorded amortization expense related to debt issuance costs of $1.5 million as compared to $10.4 million for the three months ended March 31, 2018. Debt issuance costs for the three months ended March 31, 2018 included $9.4 million of acceleration of amortization expense upon the repayment of the Company's 2021 Senior Notes. The repayment of the Company's 2021 Senior Notes had no impact to amortization expense for the three months ended March 31, 2019.

Interest Incurred on Long‑Term Debt

For the three months ended March 31, 2019, the Company incurred interest expense on long‑term debt of $20.8 million as compared to $19.9 million for the three months ended March 31, 2018. For the three months ended March 31, 2019, the Company capitalized interest expense on long term debt of $2.0 million as compared to $2.6 million for the three months ended March 31, 2018, which has been reflected in the Company’s condensed consolidated financial statements. Also included in interest expense for the three months ended March 31, 2018 was a make-whole premium of $35.6 million related to the Company's repayment of its 2021 Senior Notes in January and February 2018. The repayment of the Company's 2021 Senior Notes had no impact to interest expense for the three months ended March 31, 2019.

Senior Note Repurchase Program

On January 4, 2019, the Board of Directors authorized a program, subject to the amendment to the Company's revolving credit facility, to repurchase up to $100.0 million of the Company’s Senior Notes. The Company’s Senior Notes Repurchase Program does not obligate it to acquire any specific nominal amount of Senior Notes. For the three months ended March 31, 2019, the Company repurchased 2026 Senior Notes with a nominal value of $35.8 million for $28.5 million in connection with the Senior Notes Repurchase Program. Interest expense for the three months ended March 31, 2019 included $7.3 million of gain on debt repurchase, related to the Company's Senior Note Repurchase Program. The Senior Note Repurchase Program had no impact to interest expense for three months ended March 31, 2018. Subsequent to March 31, 2019 through the date of this filing, the Company repurchased 2026 Senior Notes with a nominal value of $11.0 million for $8.4 million in connection with the Senior Notes Repurchase Program.


Note 5—Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps, put options and call options to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production.

A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

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A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of the Company’s purchased put options have deferred premiums. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement.

A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.

The Company combines swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging strategies. Some examples of the Company’s hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap.

The objective of the Company’s use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with eleven counterparties. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. There are no credit risk related contingent features or circumstances in which the features could be triggered in derivative instruments that are in a net liability position at the end of the reporting period.


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The Company’s commodity derivative contracts as of March 31, 2019 are summarized below:
 
2019
 
2020
 
2021
NYMEX WTI Crude Swaps:
 
 
 
 
 
Notional volume (Bbl)
5,550,000

 
2,400,000

 

Weighted average fixed price ($/Bbl)
$
55.69

 
$
60.01

 
$

NYMEX WTI Crude Purchased Puts:
 
 
 
 
 
Notional volume (Bbl)
4,200,000

 
8,100,000

 
1,200,000

Weighted average purchased put price ($/Bbl)
$
53.34

 
$
54.30

 
$
55.00

NYMEX WTI Crude Sold Calls:
 
 
 
 
 
Notional volume (Bbl)
4,200,000

 
8,100,000

 
1,200,000

Weighted average sold call price ($/Bbl)
$
61.68

 
$
61.75

 
$
63.05

NYMEX WTI Crude Sold Puts:
 
 
 
 
 
Notional volume (Bbl)
6,175,000

 
10,500,000

 
1,200,000

Weighted average sold put price ($/Bbl)
$
41.45

 
$
42.51

 
$
43.00

NYMEX HH Natural Gas Swaps:
 
 
 
 
 
Notional volume (MMBtu)
27,000,000

 
11,400,000

 

Weighted average fixed price ($/MMBtu)
$
2.75

 
$
2.74

 
$

NYMEX HH Natural Gas Purchased Puts:
 
 
 
 
 
Notional volume (MMBtu)

 
600,000

 

Weighted average purchased put price ($/MMBtu)
$

 
$
2.90

 
$

NYMEX HH Natural Gas Sold Calls:
 
 
 
 
 
Notional volume (MMBtu)

 
600,000

 

Weighted average sold call price ($/MMBtu)
$

 
$
3.48

 
$

CIG Basis Gas Swaps:
 
 
 
 
 
Notional volume (MMBtu)
28,800,000

 
21,600,000

 
$

Weighted average fixed basis price ($/MMBtu)
$
(0.74
)
 
$
(0.62
)
 



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The following tables detail the fair value of the Company’s derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for the presentation in the condensed consolidated balance sheets (in thousands):
 
 
As of March 31, 2019
Location on Balance Sheet
 
Gross Amounts of Recognized Assets and Liabilities
 
Gross Amounts Offsets in the Balance Sheet(1)
 
Net Amounts of Assets and Liabilities Presented in the Balance Sheet
 
Gross Amounts not Offset in the Balance Sheet(2)
 
Net Amounts(3)
Current assets (4)
 
$
42,708

 
$
(42,482
)
 
$
226

 
$
(388
)
 
$
226

Non-current assets
 
$
44,196

 
$
(43,808
)
 
$
388

 
$

 
$

Current liabilities (4)
 
$
(91,840
)
 
$
42,482

 
$
(49,358
)
 
$
388

 
$
(54,846
)
Non-current liabilities
 
$
(49,684
)
 
$
43,808

 
$
(5,876
)
 
$

 
$


 
 
As of December 31, 2018
Location on Balance Sheet
 
Gross Amounts of Recognized Assets and Liabilities
 
Gross Amounts Offsets in the Balance Sheet(1)
 
Net Amounts of Assets and Liabilities Presented in the Balance Sheet
 
Gross Amounts not Offset in the Balance Sheet(2)
 
Net Amounts(3)
Current assets (5)
 
$
115,852

 
$
(66,945
)
 
$
48,907

 
$
(192
)
 
$
57,147

Non-current assets
 
$
17,217

 
$
(8,785
)
 
$
8,432

 
$

 
$

Current liabilities (5)
 
$
(67,141
)
 
$
66,945

 
$
(196
)
 
$
192

 
$
(4
)
Non-current liabilities
 
$
(8,785
)
 
$
8,785

 
$

 
$

 
$

 
(1)
Agreements are in place with all of the Company’s financial trading counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.
(2)
Netting for balance sheet presentation is performed by current and non‑current classification. This adjustment represents amounts subject to an enforceable master netting arrangement, which are not netted on the condensed consolidated balance sheets. There are no amounts of related financial collateral received or pledged.
(3)
Net amounts are not split by current and non‑current. All counterparties in a net asset position are shown in the current asset line item and all counterparties in a net liability position are shown in the current liability line item.
(4)
Gross current liabilities include a deferred premium liability of $5.6 million related to the Company's deferred premiums. Gross current assets include a deferred premium asset of $0.8 million related to the Company's deferred premiums.
(5)
Gross current liabilities include a deferred premium liability of $7.7 million related to the Company's deferred put premiums. Gross current assets include a deferred premium asset of $0.8 million related to the Company's deferred put premiums.

The table below sets forth the commodity derivatives loss for the three months ended March 31, 2019 and 2018 (in thousands). Commodity derivatives loss is included under the other income (expense) line item in the condensed consolidated statements of operations.
 
  For the Three Months Ended March 31,
 
2019
 
2018
Commodity derivatives loss
$
(122,091
)
 
$
(50,328
)


Note 6—Asset Retirement Obligations

The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut‑in wells at the end of their productive lives in accordance with applicable local, state and federal laws, and applicable lease terms. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates,

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inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costs are depleted with proved oil and gas properties using the unit of production method.

The following table summarizes the activities of the Company’s asset retirement obligations for the period indicated (in thousands):
 
For the Three Months Ended March 31, 2019
Balance beginning of period
$
69,791

Liabilities incurred or acquired
105

Liabilities settled
(4,983
)
Revisions in estimated cash flows
3,895

Accretion expense
1,231

Balance end of period
$
70,039



Note 7—Fair Value Measurements

ASC 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1: Quoted prices are available in active markets for identical assets or liabilities;
Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;
Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between levels during any periods presented below.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2019 and December 31, 2018 by level within the fair value hierarchy (in thousands):

 
Fair Value Measurements at
March 31, 2019 Using
 
Level 1
 
Level 2
 
Level 3
 
Total
Financial Assets:
 
 
 
 
 
 
 
Commodity derivative assets
$

 
$
614

 
$

 
$
614

Financial Liabilities:
 
 
 
 
 
 
 
Commodity derivative liabilities
$

 
$
55,234

 
$

 
$
55,234


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Fair Value Measurements at
December 31, 2018 Using
 
Level 1
 
Level 2
 
Level 3
 
Total
Financial Assets:
 
 
 
 
 
 
 
Commodity derivative assets
$

 
$
57,339

 
$

 
$
57,339

Financial Liabilities:
 
 
 
 
 
 
 
Commodity derivative liabilities
$

 
$
196

 
$

 
$
196


The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above:

Commodity Derivative Instruments

The Company determines its estimate of the fair value of derivative instruments using a market-based approach that takes into account several factors, including quoted market prices in active markets, implied market volatility factors, quotes from third parties, the credit rating of each counterparty and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. Derivative instruments utilized by the Company consist of swaps, put options and call options. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximated fair value as it bears interest at variable rates over the term of the loan. The fair values of the 2024 Senior Notes and 2026 Senior Notes were derived from available market data. As such, the Company has classified the 2024 Senior Notes and 2026 Senior Notes as Level 2. Please refer to Note 4 - Long‑Term Debt for further information. The Company’s policy is to recognize transfers between levels at the end of the period. This disclosure (in thousands) does not impact the Company’s financial position, results of operations or cash flows.

 
At March 31, 2019
 
At December 31, 2018
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Credit Facility
$
325,000

 
$
325,000

 
$
285,000

 
$
285,000

2024 Senior Notes(1)
$
394,099

 
$
335,000

 
$
393,866

 
$
330,000

2026 Senior Notes(2)
$
703,871

 
$
553,523

 
$
738,793

 
$
558,750

 
(1)
The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $5.9 million and $6.1 million as of March 31, 2019 and December 31, 2018, respectively.
(2)
The carrying amount of the 2026 Senior Notes includes unamortized debt issuance costs of $10.4 million and $11.2 million unamortized debt issuance costs as of March 31, 2019 and December 31, 2018, respectively.

Non‑Recurring Fair Value Measurements

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property and goodwill. These assets and liabilities are not measured at fair value on a recurring basis, but are subject to fair value adjustments when facts and circumstances arise that indicate a need for remeasurement.

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The Company utilizes fair value on a non-recurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate, and at least annually, a possible decline in the recoverability of the carrying value of such property. The Company uses an income approach analysis based on the net discounted future cash flows of producing property. The future cash flows are based on Management’s estimates for the future. Unobservable inputs include estimates of oil and gas production, as the case may be, from the Company’s reserve reports, commodity prices based on the sales contract terms and forward price curves, operating and development costs and a discount rate based on a market-based weighted average cost of capital (all of which are Level 3 inputs within the fair value hierarchy). For the three months ended March 31, 2019, the Company recognized $8.2 million in impairment expense on its proved oil and gas properties related to impairment of assets in its northern field. The fair value did not exceed the Company's carrying amount associated with its proved oil and gas properties in its northern field. No impairment expense was recognized for the three months ended March 31, 2018 on proved oil and gas properties.

The Company’s other non-recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted cash flow approach using level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices, development costs and operating costs, based on market participant assumptions. The fair value of assets or liabilities associated with purchase price allocations is on a non-recurring basis and is not measured in periods after initial recognition.

Note 8—Income Taxes

The Company computes an estimated annual effective rate each quarter based on the current and forecasted operating results. The income tax expense or benefit associated with the interim period is computed using the most recent estimated annual effective rate applied to the year-to-date ordinary income or loss, plus the tax effect of any significant discrete or infrequently occurring items recorded during the interim period. The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income (loss) for the year, projections of the proportion of income earned and taxed in various jurisdictions, permanent differences and the likelihood of recovering deferred tax assets generated in the current year. The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is obtained, and additional information becomes known or as the tax environment changes.

The effective combined U.S. federal and state income tax rate for the three months ended March 31, 2019 was 23.6%. During the three months ended March 31, 2019, the Company recognized income tax benefit of $29.0 million. The effective rate for the three months ended March 31, 2019 differs from the statutory U.S. federal income tax rate of 21.0% primarily due to state income taxes and estimated permanent differences. The most significant difference during the three months ended March 31, 2019 was a discrete item regarding the tax deficiency of the stock-based compensation compared to the compensation recognized for financial reporting purposes. The Company anticipates the potential for increased periodic volatility in future effective tax rates from the impact of stock-based compensation tax deductions as they are treated as discrete tax items.

Note 9—Stock‑Based Compensation

Extraction Long Term Incentive Plan

In October 2016, the Company’s board of directors adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan (the “2016 Plan” or “LTIP”), pursuant to which employees, consultants and directors of the Company and its affiliates performing services for the Company are eligible to receive awards. The 2016 Plan provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, other stock-based awards, substitute awards, annual incentive awards and performance awards intended to align the interests of participants with those of stockholders. The Company reserved 20.2 million shares of common stock for issuance pursuant to awards under the LTIP. Extraction has granted awards under the LTIP to certain directors, officers and employees, including stock options, restricted stock units and performance stock awards.


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Restricted Stock Units

Restricted stock units granted under the LTIP (“RSUs”) generally vest over either a one or three-year service period, with 100% vesting in year one or 25%, 25% and 50% of the units vesting in year one, two and three, respectively. Grant date fair value was determined based on the value of Extraction’s common stock on the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost.

The Company recorded $6.9 million of stock-based compensation costs related to RSUs for the three months ended March 31, 2019, as compared to $6.0 million for the three months ended March 31, 2018. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of March 31, 2019, there was $25.1 million of total unrecognized compensation cost related to the unvested RSUs granted to certain directors, officers and employees that is expected to be recognized over a weighted average period of 1.1 years.

The following table summarizes the RSU activity from January 1, 2019 through March 31, 2019 and provides information for RSUs outstanding at the dates indicated.
 
Number of Shares
 
Weighted Average Grant Date
Fair Value
Non-vested RSUs at January 1, 2019
3,102,335

 
$
16.91

Granted
26,400

 
$
4.32

Forfeited
(10,825)

 
$
13.64

Vested
(345,334)

 
$
13.76

Non-vested RSUs at March 31, 2019
2,772,576

 
$
17.20


Stock Options

Expense on the stock options is recognized on a straight-line basis over the service period of the award less awards forfeited. The fair value of the stock options was measured at the grant date using the Black-Scholes valuation model. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. Expected volatility is based on the volatility of the historical stock prices of the Company’s peer group. The risk-free rates are based on the yields of U.S. Treasury instruments with comparable terms. A dividend yield and forfeiture rate of zero were assumed. Stock options granted under the LTIP vest ratably over three years and are exercisable immediately upon vesting through the tenth anniversary of the grant date. To fulfill options exercised, the Company will issue new shares.

The Company recorded $3.8 million of stock-based compensation costs related to the stock options for the three months ended March 31, 2019, as compared to $3.7 million for the three months ended March 31, 2018. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of March 31, 2019, there was $8.4 million of unrecognized compensation cost related to the stock options that is expected to be recognized over a weighted average period of 0.6 years.

The following table summarizes the stock option activity from January 1, 2019 through March 31, 2019 and provides information for stock options outstanding at the dates indicated.
 
Number of Options
 
Weighted Average Exercise Price
Non-vested Stock Options at January 1, 2019
1,748,148

 
$
18.50

Granted

 
$

Forfeited

 
$

Vested

 
$

Non-vested Stock Options at March 31, 2019
1,748,148

 
$
18.50



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Performance Stock Awards

The Company granted performance stock awards ("PSAs") to certain executives under the LTIP in October 2017 and March 2018. The number of shares of the Company's common stock that may be issued to settle PSAs ranges from zero to one times the number of PSAs awarded. Generally, the shares issued for PSAs are determined based on the satisfaction of a time-based vesting schedule and a weighting of one or more of the following: (i) absolute total stockholder return ("ATSR"), (ii) relative total stockholder return ("RTSR"), as compared to the Company's peer group and (iii) cash return on capital invested ("CROCI") measured over a three-year period and vest in their entirety at the end of the three-year measurement period. Any PSAs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion that is associated with the RTSR is based on a comparison of the Company's total shareholder return for the measurement period compared to that of a group of peer companies for the same measurement period. As the ATSR and RTSR vesting criteria are linked to the Company's share price, they each are considered a market condition for purposes of calculating the grant-date fair value of the awards. The vesting criterion that is associated with the CROCI is considered a performance condition for purposes of calculating the grant-date fair value of the awards.

The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. Those outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company's PSAs, the Company cannot predict with certainty the path its stock price or the stock prices of its peer will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSAs. Significant assumptions used in this simulation include the Company's expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period as well as the volatilities for each of the Company's peers.

The Company recorded $1.5 million of stock-based compensation costs related to PSAs for the three months ended March 31, 2019. The Company recorded $1.1 million of stock-based compensation related to PSAs for the three months ended March 31, 2018. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. The outstanding and unvested shares were included in the condensed consolidated statement of stockholders' equity within the stock-based compensation line item. As of March 31, 2019, there was $7.6 million of total unrecognized compensation cost related to the unvested PSAs granted to certain executives that is expected to be recognized over a weighted average period of 1.5 years.

The following table summarizes the PSA activity from January 1, 2019 through March 31, 2019 and provides information for PSAs outstanding at the dates indicated.
 
Number of Shares (1)
 
Weighted Average Grant Date
Fair Value
Non-vested PSAs at January 1, 2019
2,794,083

 
$
9.00

Granted
$

 
$

Forfeited

 
$

Vested

 
$

Non-vested PSAs at March 31, 2019
2,794,083

 
$
9.00

 
(1)
The number of awards assumes that the associated maximum vesting condition is met at the target amount. The final number of shares of the Company's common stock issued may vary depending on the performance multiplier, which ranges from zero to one, depending on the level of satisfaction of the vesting condition.

Incentive Restricted Stock Units

Officers of the Company contributed 2.7 million shares of common stock to Extraction Employee Incentive, LLC (“Employee Incentive”), which is owned solely by certain officers of the Company. Employee Incentive issued restricted stock units (“Incentive RSUs”) to certain employees. Incentive RSUs vested over a three-year service period, with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. On July 17, 2017, the partners of Employee Incentive

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amended the vesting schedule in which 25% vested immediately and the remaining Incentive RSUs vest 25%, 25% and 25% each six months thereafter, over the remaining 18-month service period. Grant date fair value was determined based on the value of Extraction’s common stock on the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost. As the vesting of any Incentive RSUs will be satisfied with shares of common stock that are already issued and outstanding, the Incentive RSUs do not have any impact on the Company’s diluted earnings per share calculation.

The Company recorded $0.8 million of stock-based compensation costs related to Incentive RSUs for the three months ended March 31, 2019. The Company recorded $4.9 million of stock-based compensation costs related to Incentive RSUs for the three months ended March 31, 2018. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of March 31, 2019, there is no remaining unrecognized compensation costs related to the Incentive RSUs granted to certain employees.

The following table summarizes the Incentive RSU activity from January 1, 2019 through March 31, 2019 and provides information for Incentive RSUs outstanding at the dates indicated.
 
Number of Shares
 
Weighted Average Grant Date
Fair Value
Non-vested Incentive RSUs at January 1, 2019
476,000

 
$
20.45

Granted

 
$

Forfeited

 

Vested
(476,000)

 
$
20.45

Non-vested Incentive RSUs at March 31, 2019

 


Note 10—Earnings (Loss) Per Share

Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) available to common shareholders by the weighted average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings of the Company.

The Company uses the “if-converted” method to determine potential dilutive effects of the Company’s outstanding Series A Preferred Stock (the “Series A Preferred Stock”) and the treasury method to determine the potential dilutive effects of outstanding restricted stock awards and stock options. The basic weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding for the three months ended March 31, 2019 and 2018.


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The components of basic and diluted EPS were as follows (in thousands, except per share data):
 
For the Three Months Ended
 
March 31,
 
2019
 
2018
Basic and Diluted Loss Per Share
 
 
 
Net Loss
$
(94,032
)
 
$
(51,995
)
Less: Noncontrolling Interest
(3,975
)
 

Less: Adjustment to reflect Series A Preferred Stock dividends
(2,721
)
 
(2,721
)
Less: Adjustment to reflect accretion of Series A Preferred Stock discount
(1,596
)
 
(1,438
)
Adjusted net loss available to common shareholders, basic and diluted
$
(102,324
)
 
$
(56,154
)
Denominator:
 
 
 
Weighted average common shares outstanding, basic and diluted (1) (2)
170,702

 
174,213

Loss Per Common Share
 
 
 
Basic and diluted
$
(0.60
)
 
$
(0.32
)
 
(1)
For the three months ended March 31, 2019, 8,017,004 potentially dilutive shares were not included in the calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards and stock options outstanding. Additionally, 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded, as they would have had an anti-dilutive effect on EPS.
(2)
For the three months ended March 31, 2018, 8,933,600 potentially dilutive shares were not included in the calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards and stock options outstanding. Additionally, 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded, as they would have had an anti-dilutive effect on EPS.

Note 11—Commitments and Contingencies

General

The Company is subject to contingent liabilities with respect to existing or potential claims, lawsuits, and other proceedings, including those involving environmental, tax and other matters, certain of which are discussed more specifically below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the estimates of future costs, which management currently believes will not have a material effect on the Company’s financial position, results of operations or cash flows.
 
As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost, or the Company may be required to pay damages if certain performance conditions are not met.

Leases

The Company has entered into operating leases for certain office facilities, compressors and office equipment. On January 1, 2019, the Company adopted ASC Topic 842, Leases, using the modified retrospective approach. Refer to Note 2Leases for additional information.


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Maturities of operating lease liabilities, associated with ROU assets and including imputed interest, as of March 31, 2019, were as follows (in thousands):
 
Operating Leases
2019 - remaining
$
8,489

2020
7,596

2021
3,013

2022
2,196

2023
2,246

Thereafter
10,574

Total lease payments
34,114

Less imputed interest (1)
(4,499
)
Present value of lease liabilities (2)
$
29,615

 
(1) Calculated using the estimated interest rate for each lease.
(2) Of the total present value of lease liabilities, $10.0 million was recorded in "Accounts payable and accrued liabilities" and $19.6 million was recorded in "Other non-current liabilities" on the condensed consolidated balance sheets.
    
As of December 31, 2018, minimum future contractual payments for operating leases under the scope of ASC 840 for certain office facilities and drilling rigs are as follows (in thousands):
 
Operating Leases
2019 - remaining
$
12,713

2020
3,371

2021
3,385

2022
3,360

2023
3,411

Thereafter
15,719

Total lease payments
$
41,959


Drilling RigsShort-Term Leases

As of March 31, 2019, the Company was subject to commitments on three drilling rigs, contracted through May 2019, September 2019, and November 2019 respectively. In the event of early termination of these contracts, the Company would be obligated to pay an aggregate amount of approximately $8.2 million as of March 31, 2019, as required under the terms of the contracts. These costs are capitalized within proved oil and gas properties on the condensed consolidated balance sheets and are included as short-term lease costs in Note 2—Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements, Leases.

Delivery Commitments

As of March 31, 2019, the Company’s oil marketer was subject to a firm transportation agreement that commenced in November 2016 and has a ten-year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. In May 2017, the Company amended its agreement with its oil marketer that requires it to sell all of its crude oil from an area of mutual interest in exchange for a make-whole provision that allows the Company to satisfy any minimum volume commitment deficiencies incurred by its oil marketer with future barrels of crude oil in excess of their minimum volume commitment through October 31, 2018. In December 2017, the Company extended the term of this agreement through October 31, 2019 and has posted a letter of credit in the amount of $35.0 million. The Company is currently in the process of amending and extending this agreement. The Company evaluates its contracts for loss contingencies and accrues for such losses, if the loss can be reasonably estimated and deemed probable.


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The Company has two long-term crude oil gathering commitments with an unconsolidated subsidiary, in which the Company has a minority ownership interest, and a long-term gas gathering agreement with a third party midstream provider. The summary of these minimum volume commitments as of March 31, 2019, was as follows (in thousands):
 
 Oil (MBbl)
 
Gas (MMcf)
 
Total (MBOE)
2019 - Remaining
188

 
5,185

 
1,053

2020
293

 
33,550

 
5,884

2021
340

 
46,540

 
8,097

2022
300

 
49,758

 
8,593

2023
312

 
41,850

 
7,287

Thereafter
1,276

 
74,420

 
13,679

Total
2,709

 
251,303

 
44,593


The aggregate amount of estimated remaining payments under these agreements is $413.0 million.

Also, in collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017, the Company agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan includes two new processing plants as well as the expansion of related gathering systems. The first plant commenced operations in August 2018 and the second plant is expected to be completed by mid-2019, although the exact start-up date is undetermined at this time. The Company’s share of these commitments will require 51.5 and 20.6 MMcf per day, respectively, to be delivered after the plants' in-service dates for a period of seven years thereafter. The Company may be required to pay a shortfall fee for any volumes under these commitments. These contractual obligations can be reduced by the Company’s proportionate share of the collective volumes delivered to the plants by other third-party incremental volumes available to the midstream provider at the new facilities that are in excess of the total commitments. The Company is also required for the first three years of each contract to guarantee a certain target profit margin on these volumes sold. The Company also has a long-term gas gathering agreement with a third party midstream provider that will commence in or around January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 Bcf in years one through ten. We may be required to pay an annual shortfall fee for any volume deficiencies under this commitment, calculated based on the weighted average sales price during the corresponding annual period. Under its current drilling plans, the Company expects to meet these volume commitments.

Legal Matters

From time to time, the Company is party to ongoing legal proceedings in the ordinary course of business. While the outcome of these proceedings cannot be predicted with certainty, the Company does not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on the Company's business, financial condition, results of operations or liquidity.


Note 12—Related Party Transactions

Office Lease with Related Affiliate

In April 2016, the Company subleased office space to Star Peak Capital, LLC, of which a member of the board of directors is an owner, for $1,400 per month. The sublease commenced on May 1, 2016 and expires on February 28, 2020.

2026 Senior Notes

Several holders of the 2026 Senior Notes are also 5% stockholders of the Company. As of the initial issuance in January 2018 of the $750.0 million principal amount on the 2026 Senior Notes, such stockholders held $56.2 million.





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Note 13—Segment Information

Beginning in the fourth quarter of 2018, the Company has two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). Prior to the fourth quarter of 2018, the Company had a single operating segment. The gathering systems and facilities operating segment is currently under development. Capital expenditures associated with gathering systems and facilities are being incurred to develop midstream infrastructure to support the Company's development of its oil and gas leasehold along with third-party activity.

The Company's exploration and production segment revenues are derived from third parties. The Company’s gathering and facilities segment is currently in the construction phase and no revenue generating activities have commenced.

Financial information of the Company's reportable segments was as follows for the three months ended March 31, 2019 and 2018 (in thousands).
 
For the Three Months Ended March 31, 2019
 
Exploration and Production
 
Gathering and Facilities
 
Elimination of Intersegment Transactions
 
Consolidated Total
Revenues:
 
 
 
 
 
 
 
Revenues from external customers
$
221,917

 
$

 
$

 
$
221,917

Intersegment revenues

 

 

 

Total Revenues
$
221,917

 
$

 
$

 
$
221,917

 
 
 
 
 
 
 
 
Operating Expenses and Other Income (Expense):
 
 
 
 
 
 
 
Depletion, depreciation, amortization and accretion
$
(118,751
)
 
$
(19
)
 
$

 
$
(118,770
)
Interest income
154

 
625

 

 
779

Interest expense
(13,008
)
 

 

 
(13,008
)
Earnings in unconsolidated subsidiaries

 
338

 

 
338

Subtotal Operating Expenses and Other Income (Expense):
$
(131,605
)
 
$
944

 
$

 
$
(130,661
)
 
 
 
 
 
 
 
 
Segment Assets
$
3,813,513

 
$
284,200

 
$
(714
)
 
$
4,096,999

Capital Expenditures
$
158,622

 
$
58,863

 
$

 
$
217,485

Investment in Equity Method Investees
$

 
$
17,555

 
$

 
$
17,555

Segment EBITDAX
$
138,339

 
$
(152
)
 
$

 
$
138,187






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For the Three Months Ended March 31, 2018
 
Exploration and Production
 
Gathering and Facilities
 
Elimination of Intersegment Transactions
 
Consolidated Total
Revenues:
 
 
 
 
 
 
 
Revenues from external customers
$
230,215

 
$

 
$

 
$
230,215

Intersegment revenues

 

 

 

Total Revenues
$
230,215

 
$

 
$

 
$
230,215

 
 
 
 
 
 
 
 
Operating Expenses and Other Income (Expense):
 
 
 
 
 
 
 
Depletion, depreciation, amortization and accretion
$
(96,207
)
 
$

 
$

 
$
(96,207
)
Interest income
49

 

 

 
49

Interest expense
(63,302
)
 

 

 
(63,302
)
Earnings in unconsolidated subsidiaries

 
339

 

 
339

Subtotal Operating Expenses and Other Income (Expense):
$
(159,460
)
 
$
339

 
$

 
$
(159,121
)
 
 
 
 
 
 
 
 
Segment Assets
$
3,555,206

 
$
9,993

 
$

 
$
3,565,199

Capital Expenditures
$
247,704

 
$
5,574

 
$

 
$
253,278

Investment in Equity Method Investees
$

 
$
8,172

 
$

 
$
8,172

Segment EBITDAX
$
140,632

 
$
339

 
$

 
$
140,971









    




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The following table presents a reconciliation of Adjusted EBITDAX by segment to the GAAP financial measure of income (loss) before income taxes for the three months ended March 31, 2019 and 2018 (in thousands).
 
 
 
 
 
For the Three Months Ended March 31, 2019
 
For the Three Months Ended March 31, 2018
Reconciliation of Adjusted EBITDAX to Loss Before Income Taxes
 
 
 
Exploration and production segment EBITDAX
$
138,339

 
$
140,632

Gathering and facilities segment EBITDAX
(152
)
 
339

Subtotal of Reportable Segments
$
138,187

 
$
140,971

Less:
 
 
 
Depletion, depreciation, amortization and accretion
$
(118,770
)
 
$
(96,207
)
Impairment of long lived assets
(8,248
)
 

Exploration expenses
(6,194
)
 
(7,267
)
Gain on sale of oil and gas properties
222

 

Loss on commodity derivatives
(122,091
)
 
(50,328
)
Settlements on commodity derivative instruments
10,329

 
23,253

Premiums paid for derivatives that settled during the period
9,549

 
2,506

Stock-based compensation expense
(13,008
)
 
(15,721
)
Amortization of debt issuance costs
(1,497
)
 
(10,442
)
Make-whole premium on 2021 Senior Notes

 
(35,600
)
Gain on repurchase of 2026 Senior Notes
7,317

 

Interest expense
(18,828
)
 
(17,260
)
Loss Before Income Taxes
$
(123,032
)
 
$
(66,095
)



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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) contains "forward-looking statements." All statements, other than statements of historical facts, included or incorporated by reference herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as ''may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," ''will," "continue," ''potential," "should," "could," and similar terms and phrases. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

federal and state regulations and laws;
capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;
risks and restrictions related to our debt agreements;
our ability to use derivative instruments to manage commodity price risk;
realized oil, natural gas and NGL prices;
a decline in oil, natural gas and NGL production, and the impact of general economic conditions on the demand for oil, natural gas and NGL and the availability of capital;
unsuccessful drilling and completion activities and the possibility of resulting write-downs;
geographical concentration of our operations;
constraints in the DJ Basin of Colorado with respect to gathering, transportation and processing facilities and marketing;
our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil or natural gas in commercially viable quantities;
shortages of oilfield equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel;
adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;
incorrect estimates associated with properties we acquire relating to estimated proved reserves, the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of such acquired properties;
drilling operations associated with the employment of horizontal drilling techniques, and adverse weather and environmental conditions;
limited control over non-operated properties;
title defects to our properties and inability to retain our leases;
our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;
our ability to retain key members of our senior management and key technical employees;
risks relating to managing our growth, particularly in connection with the integration of significant acquisitions;
impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;
changes in tax laws;
effects of competition; and

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seasonal weather conditions.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas, and NGL that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers and management. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGL that are ultimately recovered.

In addition to the other information and risk factors set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2018 (our “Annual Report”) and in our other filings with the Securities Exchange Commission, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. Other than as set forth in this Quarterly Report, there have been no material changes in our risk factors from those described in our Annual Report.

All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this Quarterly Report. Except as required by law, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and related Notes included in Part I, Item 1 of this Quarterly Report. The following information updates the discussion of the Company’s financial condition provided in its Annual Report and analyzes the changes in the results of operations between the three months ended March 31, 2019 and 2018.

EXECUTIVE SUMMARY

We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the DJ Basin. We have developed an oil, natural gas and NGL asset base of proved reserves, as well as a portfolio of development drilling opportunities on high resource‑potential leasehold on contiguous acreage blocks in some of the most productive areas of what we consider to be the core of the DJ Basin. We are focused on growing our proved reserves and production primarily through the development of our large inventory of identified liquids‑rich horizontal drilling locations, as well as the design and support of midstream assets to gather and process crude oil and gas production focused in the DJ Basin.

Financial Results

For the three months ended March 31, 2019, crude oil, natural gas and NGL sales, coupled with the impact of settled derivatives, decreased to $202.0 million as compared to $204.5 million in the same prior year period due to a decrease of $5.04 in realized price per BOE, including settled derivatives, partially offset by an increase in sales volumes of 1,037 MBoe.

For the three months ended March 31, 2019, we had net loss of $94.0 million as compared to net loss of $52.0 million for the three months ended March 31, 2018. The change to net loss for the three months ended March 31, 2019 from the three months ended March 31, 2018 was primarily driven by a decrease in sales revenues of $8.3 million, an increase in operating expenses of $28.0 million and an increase in commodity derivative loss of $71.8 million, partially offset by a decrease in interest expense of $50.3 million related to the redemption of the Company's 2021 Senior Notes during the three months ended March 31, 2018.

Adjusted EBITDAX was $138.2 million for the three months ended March 31, 2019 as compared to $141.0 million for the three months ended March 31, 2018, reflecting a 2.0% decrease. Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “—Adjusted EBITDAX.”


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Operational Results

During the three months ended March 31, 2019, our aggregate drilling, completion, and leasehold capital expenditures, totaled $158.6 million, of which $139.5 million was drilling and completion additions and $19.1 million was leasehold and surface acreage additions. This excludes the impact of the increase in outstanding elections of $11.6 million. In addition, Elevation Midstream, LLC, our wholly owned midstream subsidiary, incurred $58.9 million of capital expenditures during the three months ended March 31, 2019. These capital expenditures are funded entirely by the Elevation Midstream, LLC Securities Purchase Agreement.

During the three months ended March 31, 2019, we drilled 31 gross (21 net) wells with an average length of approximately 6,900 feet and completed 40 gross (31 net) wells with an average lateral length of approximately 7,300 feet. We turned to sales 7 gross (6 net) wells with an average lateral length of approximately 9,500 feet. We also added 8 net drilled wells, 1 net completed well and 1 net well to sales during the period through strategic swaps, polling completion, etc.

Recent Developments

Senate Bill 19-181 "Protect Public Welfare Oil And Gas Operations"

On April 16, 2019, Senate Bill 19-181 (“SB181”) became law, increasing the regulatory authority of local governments in Colorado over the surface impacts of oil and gas development in a reasonable manner. Among other things, SB181 (i) repeals a prior law restricting local government land use authority over oil and gas mineral extraction areas to areas designated by the Colorado Oil and Gas Conservation Commission, (ii) directs the Colorado Air Quality Control Commission to review its leak detection and repair rules and to adopt rules to minimize emissions of certain air pollutants, (iii) clarifies that local governments have authority to regulate the siting of oil and gas locations in a reasonable manner, including the ability to inspect oil and gas facilities, impose fines for leaks, spills, and emissions, and impose fees on operators or owners to cover regulation and enforcement costs, (iv) allows local governments or oil and gas operators to request a technical review board to evaluate the effect of the local government’s preliminary or final determination on the operator’s application and (v) repeals an exemption for oil and gas production from counties’ authority to regulate noise. Although industry trade associations opposed SB181, management believes that Extraction can continue to successfully operate our business. However, the enactment of SB181 could lead to delays and additional costs to our business.

March 2019 Divestiture

              On March 27, 2019, we completed the sale of our interests in approximately 5,000 net acres of leasehold and producing properties primarily in Weld County, Colorado (the "March 2019 Divestiture") for aggregate sales proceeds of approximately $22.4 million. The effective date for the March 2019 Divestiture was July 1, 2018 with purchase price adjustments calculated as of the closing date of $5.9 million, resulting in net proceeds of $16.5 million. We continue to explore divestitures, as part of our ongoing initiative to divest of non-strategic assets.

January 2019 Credit Facility Amendment

On January 8, 2019, we amended our revolving credit facility to permit prepayments and redemptions of our unsecured bonds, subject to certain term, conditions and financial thresholds.

Senior Notes Repurchase Program

On January 4, 2019, our Board of Directors authorized a program, subject to the amendment to our revolving credit facility, to repurchase up to $100.0 million of our Senior Notes (“Senior Notes Repurchase Program”). Our Senior Notes Repurchase Program does not obligate us to acquire any specific nominal amount of Senior Notes. For the three months ended March 31, 2019, we repurchased 2026 Senior Notes with a nominal value of $35.8 million for $28.5 million in connection with the Senior Notes Repurchase Program. Subsequent to March 31, 2019 through the date of this filing, we repurchased 2026 Senior Notes with a nominal value of $11.0 million for $8.4 million in connection with the Senior Notes Repurchase Program.


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Stock Repurchase Program

On November 19, 2018, we announced the Board of Directors had authorized a program to repurchase up to $100.0 million of our common stock ("Stock Repurchase Program"). On April 1, 2019, we announced the Board of Directors had authorized an extension and increase in our ongoing Stock Repurchase Program ("Extended Stock Repurchase Program"). We have purchased approximately 13.0 million shares of its common stock for $63.2 million under the Stock Repurchase Program, prior to the Extended Stock Repurchase Program. We are authorized to repurchase an incremental $100.0 million in common stock from the date of the Extended Stock Repurchase Program, bringing the total amount authorized to be repurchased to approximately $163.2 million. Our Stock Repurchase Program does not obligate us to acquire any specific number of shares and will expire on December 31, 2019. We intend to conduct any open market stock repurchase activities in compliance with the safe harbor provisions of Rule 10b-18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). During the three months ended March 31, 2019, we repurchased approximately 7.7 million shares of our common stock for $31.5 million. Subsequent to March 31, 2019 through the date of this filing, we repurchased approximately 1.3 million additional shares of our common stock for $5.5 million.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and gas operations, including: