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 June 30, 2018
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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark 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. (Check one):

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

The total number of shares of common stock, par value $0.01 per share, outstanding as of August 3, 2018 was 175,479,079.

 



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.



2

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.





3

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)
 
June 30,
2018
 
December 31,
2017
ASSETS
 
 
 
Current Assets:
 
 
 
Cash and cash equivalents
$
68,249

 
$
6,768

Accounts receivable
 
 
 
Trade
42,118

 
46,047

Oil, natural gas and NGL sales
93,367

 
93,301

Inventory and prepaid expenses
24,308

 
13,017

Commodity derivative asset
15,313

 
4,132

Total Current Assets
243,355

 
163,265

Property and Equipment (successful efforts method), at cost:
 
 
 
Proved oil and gas properties
3,564,549

 
3,011,526

Unproved oil and gas properties
684,375

 
686,968

Wells in progress
113,019

 
127,418

Less: accumulated depletion, depreciation and amortization
(908,169
)
 
(709,662
)
Net oil and gas properties
3,453,774

 
3,116,250

Elevation gathering systems and facilities
26,417

 
4,889

Other property and equipment, net of accumulated depreciation
30,186

 
32,429

Net Property and Equipment
3,510,377

 
3,153,568

Non-Current Assets:
 
 
 
Commodity derivative asset
266

 

Goodwill and other intangible assets, net of accumulated amortization
55,757

 
55,453

Other non-current assets
14,305

 
12,383

Total Non-Current Assets
70,328

 
67,836

Total Assets
$
3,824,060

 
$
3,384,669

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
Current Liabilities:
 
 
 
Accounts payable and accrued liabilities
$
252,051

 
$
211,581

Revenue payable
87,943

 
52,805

Production taxes payable
63,236

 
37,444

Commodity derivative liability
153,567

 
67,428

Accrued interest payable
22,411

 
23,807

Asset retirement obligations
12,792

 
6,873

Total Current Liabilities
592,000

 
399,938

Non-Current Liabilities:
 
 
 
Credit facility
190,000

 
90,000

Senior Notes, net of unamortized debt issuance costs
1,131,579

 
933,361

Production taxes payable
51,931

 
57,982

Commodity derivative liability
6,245

 
17,274

Other non-current liabilities
7,858

 
5,973

Asset retirement obligations
56,838

 
62,667

Deferred tax liability
32,426

 
42,326

Total Non-Current Liabilities
1,476,877

 
1,209,583

Total Liabilities
2,068,877

 
1,609,521

Commitments and Contingencies—Note 11

 

Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 issued and outstanding
161,298

 
158,383

Stockholders' Equity:
 
 
 
Common stock, $0.01 par value; 900,000,000 shares authorized; 175,797,671 and 172,059,814 issued and outstanding
1,718

 
1,718

Additional paid-in capital
2,137,371

 
2,114,795

Treasury stock, at cost, 331,305 and 165,385 shares
(4,414
)
 
(2,105
)
Accumulated deficit
(540,790
)
 
(497,643
)
Total Stockholders' Equity
1,593,885

 
1,616,765

Total Liabilities and Stockholders' Equity
$
3,824,060

 
$
3,384,669

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

4

Table of Contents

EXTRACTION OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)
 
For the Three Months Ended June 30,
 
  For the Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Revenues:
 
 
 
 
 
 
 
Oil sales
$
213,481

 
$
85,394

 
$
393,744

 
$
137,522

Natural gas sales
19,807

 
18,526

 
43,888

 
38,423

NGL sales
26,908

 
15,846

 
52,779

 
33,460

Total Revenues
260,196

 
119,766

 
490,411

 
209,405

Operating Expenses:
 
 
 
 
 
 
 
Lease operating expenses
20,774

 
14,125

 
41,477

 
26,161

Transportation and gathering
9,959

 
10,040

 
17,498

 
20,327

Production taxes
24,389

 
10,511

 
44,712

 
16,964

Exploration expenses
3,021

 
6,438

 
10,288

 
17,250

Depletion, depreciation, amortization and accretion
106,774

 
68,610

 
202,981

 
119,263

Impairment of long lived assets
128

 

 
128

 
675

(Gain) loss on sale of property and equipment
(59,902
)
 

 
(59,902
)
 
451

Acquisition transaction expenses

 

 

 
68

General and administrative expenses
34,231

 
23,487

 
65,200

 
49,175

Total Operating Expenses
139,374

 
133,211

 
322,382

 
250,334

Operating Income (Loss)
120,822

 
(13,445
)
 
168,029

 
(40,929
)
Other Income (Expense):
 
 
 
 
 
 
 
Commodity derivatives gain (loss)
(89,511
)
 
33,876

 
(139,839
)
 
84,298

Interest expense
(19,202
)
 
(9,021
)
 
(82,504
)
 
(18,681
)
Other income
939

 
250

 
1,267

 
818

Total Other Income (Expense)
(107,774
)
 
25,105

 
(221,076
)
 
66,435

Income (Loss) Before Income Taxes
13,048

 
11,660

 
(53,047
)
 
25,506

Income tax (expense) benefit
(4,200
)
 
(4,420
)
 
9,900

 
(9,550
)
Net Income (Loss)
$
8,848

 
$
7,240

 
$
(43,147
)
 
$
15,956

Income (Loss) Per Common Share (Note 10)
 
 
 
 
 
 
 
Basic and diluted
$
0.03

 
$
0.02

 
$
(0.29
)
 
$
0.05

Weighted Average Common Shares Outstanding
 
 
 
 
 
 
 
Basic and diluted
175,762

 
171,835

 
174,992

 
171,835













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

5

Table of Contents

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

 
Common Stock
 
Treasury Stock
 
 
 
 
 
 
 
Shares
 
Amount
 
Shares
 
Amount
 
Additional
Paid in
Capital
 
Retained
Deficit
 
Total Stockholders'
Equity
Balance at January 1, 2018
172,060

 
$
1,718

 
165

 
$
(2,105
)
 
$
2,114,795

 
$
(497,643
)
 
$
1,616,765

Stock-based compensation
2,794

 

 

 

 
33,464

 

 
33,464

Series A Preferred Stock dividends

 

 

 

 
(5,443
)
 

 
(5,443
)
Accretion of beneficial conversion feature on Series A Preferred Stock

 

 

 

 
(2,914
)
 

 
(2,914
)
Repurchase of common stock

 

 
166

 
(2,309
)
 

 

 
(2,309
)
Shares issued under LTIP, including payment of tax withholdings using withheld shares
944

 

 

 

 
(2,531
)
 

 
(2,531
)
Net loss

 

 

 

 

 
(43,147
)
 
(43,147
)
Balance at June 30, 2018
175,798

 
$
1,718

 
331

 
$
(4,414
)
 
$
2,137,371

 
$
(540,790
)
 
$
1,593,885




































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

6

Table of Contents

EXTRACTION OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
 
  For the Six Months Ended June 30,
 
2018
 
2017
Cash flows from operating activities:
 
 
 
Net income (loss)
$
(43,147
)
 
$
15,956

Reconciliation of net income (loss) to net cash provided by operating activities:
 
 
 
Depletion, depreciation, amortization and accretion
202,981

 
119,263

Abandonment and impairment of unproved properties
5,922

 
4,560

Impairment of long lived assets
128

 
675

(Gain) loss on sale of property and equipment
(59,902
)
 
451

Amortization of debt issuance costs
11,368

 
1,712

Deferred rent
280

 
(156
)
Commodity derivatives (gain) loss
139,839

 
(84,298
)
Settlements on commodity derivatives
(54,279
)
 
(13,240
)
Premiums paid on commodity derivatives
(17,271
)
 

Earnings in unconsolidated subsidiaries
(1,043
)
 
10

Distributions from unconsolidated subsidiaries
626

 

Make-whole premium paid on 2021 Senior Notes
35,600

 

Deferred income tax expense (benefit)
(9,900
)
 
9,550

Stock-based compensation
33,464

 
28,597

Changes in current assets and liabilities:
 
 
 
Accounts receivable—trade
5,101

 
(618
)
Accounts receivable—oil, natural gas and NGL sales
(66
)
 
(10,977
)
Inventory and prepaid expenses
(812
)
 
(103
)
Accounts payable and accrued liabilities
(10,248
)
 
(3,186
)
Revenue payable
35,138

 
1,336

Production taxes payable
19,741

 
(3,109
)
Accrued interest payable
(1,396
)
 
356

Asset retirement expenditures
(5,034
)
 
(952
)
Net cash provided by operating activities
287,090

 
65,827

Cash flows from investing activities:
 
 
 
Oil and gas property additions
(519,154
)
 
(572,105
)
Acquired oil and gas properties

 
(17,225
)
Sale of property and equipment
72,345

 
2,000

Elevation gathering systems and facilities additions
(16,055
)
 

Other property and equipment additions
(2,712
)
 
(5,790
)
Investment in unconsolidated subsidiaries
(293
)
 

Net cash used in investing activities
(465,869
)
 
(593,120
)
Cash flows from financing activities:
 
 
 
Borrowings under credit facility
430,000

 

Repayments under credit facility
(330,000
)
 

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
)
 

Repurchase of shares
(2,309
)
 

Payment of employee payroll withholding taxes
(2,531
)
 

Dividends on Series A Preferred Stock
(5,443
)
 
(4,958
)
Debt issuance costs
(3,055
)
 
(109
)
Equity issuance costs
(466
)
 
(1,487
)
Net cash provided by (used in) financing activities
240,260

 
(6,554
)
Increase (decrease) in cash, cash equivalents and restricted cash
61,481

 
(533,847
)
Cash, cash equivalents and restricted cash at beginning of period
6,768

 
630,936

Cash, cash equivalents and restricted cash at end of the period
$
68,249

 
$
97,089

Supplemental cash flow information:
 
 
 
Property and equipment included in accounts payable and accrued liabilities
$
197,577

 
$
134,483

Cash paid for interest
$
41,607

 
$
22,256

Issuance of promissory note to unconsolidated subsidiary
$
35,329

 
$

Extinguishment of promissory note in exchange for equity with unconsolidated subsidiary
$
(35,329
)
 
$

Accretion of beneficial conversion feature of Series A Preferred Stock
$
2,914

 
$
2,627

Non-cash contribution to unconsolidated subsidiary
$

 
$
8,191

Increase in dividend payable
$

 
$
485

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

7

Table of Contents

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".

On July 3, 2018, Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company and subsidiary of the Company, entered into a securities purchase agreement (the “Securities Purchase Agreement”) with a third party (the "Purchaser"), pursuant to which Elevation agreed to sell 150,000 Preferred Units (the “Elevation Preferred Units”) of Elevation at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $150.0 million (the “Private Placement”), in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The Private Placement closed on July 3, 2018 (the “Closing Date”) and resulted in net proceeds of approximately $141.9 million, $25.4 million of which was a reimbursement for previously incurred midstream capital expenditures and general and administrative expenses. These Preferred Units are non-recourse to Extraction.

During the twenty-eight months following the Closing Date (the “Commitment Period”), subject to the satisfaction of certain financial and operational metrics and certain other customary closing conditions, Elevation has the right to require the Purchaser to purchase additional Elevation Preferred Units on the terms set forth in the Securities Purchase Agreement. Elevation may require the Purchaser to purchase additional Elevation Preferred Units, in increments of at least $25.0 million, up to an aggregate amount of $350.0 million. During the Commitment Period, Elevation is required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn amounts of such additional $350.0 million commitment.

The Elevation Preferred Units will entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum (the “Dividend”). In respect of quarters ending prior to and including June 30, 2020, the Dividend is payable in cash or in kind at the election of Elevation. After June 30, 2020, the Dividend is payable solely in cash.

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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Table of Contents

Recent Accounting Pronouncements

In May 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-09, which provides clarification and reduces both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718 Compensation - Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures.

In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures.

In January 2017, the FASB issued ASU No. 2017-04, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for interim and annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements and related disclosures.

In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures; however, this standard may result in more transactions being accounted for as asset acquisitions rather than business combinations.

In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment was effective retrospectively for reporting periods beginning after December 15, 2017. The Company adopted this ASU on January 1, 2018 and the retrospective adoption increased the Company's beginning and ending cash balances within the statement of cash flows for the three months ended March 31, 2017. The adoption had no other material impact on the cash flow statement and had no impact on the Company's results of operations or financial position.

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets to the consolidated statement of cash flows:
 
As of
 
June 30,
 
December 31,
 
June 30,
 
December 31,
 
2018
 
2017
 
2017
 
2016
Cash and cash equivalents
$
68,249

 
$
6,768

 
$
88,689

 
$
588,736

Restricted cash included in cash held in escrow

 

 
8,400

 
42,200

 
$
68,249

 
$
6,768

 
$
97,089

 
$
630,936


In August 2016, the FASB issued ASU No. 2016-15, which addresses eight specific cash flow issues, including presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted this ASU on January 1, 2018, which requires current period make-whole premiums to be presented in financing activities in the statement of cash flows and prior period debt prepayment costs to be reclassified from operating activities to financing activities in the statement of cash flows; however, there will be no impact to the total change in cash and cash equivalents from period to period.

In February 2016, the FASB issued 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

9

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flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. The FASB subsequently issued ASU No. 2017-13, ASU No. 2018-01, ASU No. 2018-10 and ASU No. 2018-11, which provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on the consolidated financial statements and related disclosures. As a part of the assessment work to-date, the Company has engaged an external consulting firm, is evaluating agreements under this ASU, and is assessing the completeness of the lease population.

In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model, referred to as ASC 606 - Revenue from Contracts with Customers, designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and was effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, ASU No. 2017-13 and ASU No. 2017-14, which provided additional implementation guidance. Refer to —Adoption of ASC 606 for more information.

Adoption of ASC 606

On January 1, 2018, the Company adopted ASC 606 - Revenue from Contracts with Customers ("ASC 606"). The Company adopted ASC 606 using the modified retrospective method to apply the new standard to all new contracts entered into on or after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.

The impact of adoption in the current period results are as follows (in thousands):
 
For the Three Months Ended
June 30, 2018
 
For the Six Months Ended
June 30, 2018
 
Under ASC 606
 
Under ASC 605
 
Change
 
Under ASC 606
 
Under ASC 605
 
Change
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Oil sales
$
213,481

 
$
213,481

 
$

 
$
393,744

 
$
393,744

 
$

Natural gas sales
19,807

 
27,603

 
(7,796
)
 
43,888

 
54,944

 
(11,056
)
NGL sales
26,908

 
38,646

 
(11,738
)
 
52,779

 
69,401

 
(16,622
)
Total Revenues
260,196

 
279,730

 
(19,534
)
 
490,411

 
518,089

 
(27,678
)
Operating Expenses:
 
 
 
 
 
 
 
 
 
 
 
Transportation and gathering
$
9,959

 
$
29,493

 
$
(19,534
)
 
$
17,498

 
$
45,176

 
$
(27,678
)
Net Income (Loss)
$
8,848

 
$
8,848

 
$

 
$
(43,147
)
 
$
(43,147
)
 
$


Changes to sales of natural gas and NGL, and transportation and gathering expenses are due to the conclusion that certain midstream processing entities are the Company's customer in natural gas processing and marketing agreements in accordance with the five-step process in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the Company determined it was the principal, the midstream processor was the agent and the third-party end user was its customer. As a result, the Company modified its presentation of revenues and operating expenses for these agreements. Revenues related to these agreements are now presented on a net basis for proceeds expected to be received from the midstream processing entity.

Transportation and gathering expense related to other agreements incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities will continue to be presented as transportation and gathering expense.

Revenues from Contracts with Customers

Sales of oil, natural gas and NGL are recognized at the point control of the commodity is transferred to the customer and collectability is reasonably assured. The majority of the Company's contracts' pricing provisions are tied to a commodity market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas and NGL fluctuates to remain competitive with the other available oil, natural gas and NGL supplies.

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Oil Sales

Under the Company's crude purchase and marketing contracts, the Company generally sells oil production at the wellhead and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead at the net price received.

The Company utilizes the sales method to account for producer imbalances, which continues to be applicable under ASC 606. As of June 30, 2018, the Company has an oil imbalance of 159 MBbl, which the Company intends to settle with the counterparty in crude oil barrels.

Natural Gas and NGL Sales

Under the Company's natural gas processing contracts, the Company delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity's system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGL and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction, and the point at which control of the hydrocarbons transfer to the customer. For those contracts where the Company has concluded the midstream processing entity is the Company's agent and the third-party end user is its customer (generally the Company's fixed-fee gathering and processing agreements), the Company recognizes revenue on a gross basis, with transportation and gathering expense presented as an operating expense in the consolidated statements of operations. Alternatively, for those contracts where the Company has concluded the midstream processing entity is its customer and controls the hydrocarbons (generally the Company's percentage of proceeds gathering and processing agreements), the Company recognizes natural gas and NGL revenues based on the net amount of the proceeds received from the midstream processing company.

In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGL in-kind at the tailgate of the midstream entity's processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when the control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering and processing expense attributable to the gas processing contracts, as well as any transportation expense incurred to deliver the product to the purchaser, are presented as transportation and gathering expense in the consolidated statements of operations.

Performance Obligations

A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price of a contract that has an original expected duration of one year or less.

For the Company's product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14(a), which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

The Company records revenue on its oil, natural gas and NGL sales at the time production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products. The Company records the differences between the revenue estimated and the actual amounts received for product sales in the month that payment is received from the customer. The Company has internal controls over its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the period from January 1, 2018 to June 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.


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Contract Balances

Under the Company's various sales contracts, the Company invoices customers once its performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's product sales contracts do not give rise to contract assets or liabilities under ASC 606.

The following table presents the Company's revenues disaggregated by revenue source. Transportation and gathering costs in the following table are not all of the transportation and gathering expenses that the Company incurs, only the expenses that are netted against revenues pursuant to ASC 606. Prior period amounts have not been adjusted under the modified retrospective method.
 
  For the Three Months
Ended June 30,
 
  For the Six Months
Ended June 30,
 
2018
 
2017
 
2018
 
2017
Revenues:
 
 
 
 
 
 
 
Oil sales
$
213,481

 
$
85,394

 
$
393,744

 
$
137,522

Natural gas sales
27,603

 
18,526

 
54,944

 
38,423

NGL sales
38,646

 
15,846

 
69,401

 
33,460

Transportation and gathering included in revenues
(19,534
)
 

 
(27,678
)
 

Total Revenues
$
260,196

 
$
119,766

 
$
490,411

 
$
209,405


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.


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Note 3—Acquisitions and Divestitures

August 2018 Divestiture

On August 3, 2018, Elevation received $83.6 million 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 nonfinancial assets.

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, subject to customary purchase price adjustments, and recognized a gain of $59.9 million for the three and six months ended June 30, 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.

November 2017 Acquisition

On November 15, 2017, the Company acquired an unaffiliated oil and gas company's interest in approximately 36,600 net acres of leasehold and primarily non-producing properties located in Arapahoe County, Colorado, (the "November 2017 Acquisition"). Upon closing the seller received $214.3 million in cash, subject to customary purchase price adjustments. The Company also paid $12.2 million for the final settlement payment in April 2018 in conjunction with the November 2017 Acquisition. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.

July 2017 Acquisition

On July 7, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 12,500 net acres of leasehold, and primarily non-producing properties and producing properties located primarily in Adams County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the "July 2017 Acquisition"). Upon closing the seller received total consideration of $84.0 million in cash, subject to customary purchase price adjustments. The effective date for the July 2017 Acquisition is July 1, 2017. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.

June 2017 Acquisition

On June 8, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 160 net acres of leasehold and related producing properties located in Weld County, Colorado (the “June 2017 Acquisition”). The Company paid approximately $13.4 million in cash consideration in connection with the closing of the June 2017 Acquisition. The effective date for the acquisition was January 1, 2017, with purchase price adjustments calculated as of the closing date of June 8, 2017. The acquisition increased the Company's interest in existing operated wells. The acquired producing properties contributed $0.8 million and $1.8 million of revenue and $0.7 million and $1.3 million of earnings, respectively, for three and six months ended June 30, 2018. The acquired producing properties contributed de minimis revenue and earnings for the three and six months ended June 30, 2017. No significant transaction costs related to the acquisition were incurred for the three and six months ended June 30, 2018 and 2017.


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The June 2017 Acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of June 8, 2017. In August 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price
 
June 8, 2017
Consideration given
 
 
Cash
 
$
13,395

Total consideration given
 
$
13,395

Allocation of Purchase Price
 
 
Proved oil and gas properties
 
$
13,495

Total fair value of oil and gas properties acquired
 
$
13,495

Asset retirement obligations
 
$
(100
)
Fair value of net assets acquired
 
$
13,395


Pro Forma Financial Information (Unaudited)

For the three and six months ended June 30, 2017, the following pro forma financial information represents the combined results for the Company and the properties acquired in the June 2017 Acquisition as if the acquisition had occurred on January 1, 2017. The June 2017 Acquisition has no impact on the historical results of the Company for the three and six months ended June 30, 2018. For purposes of pro forma financial information, it was assumed that the June 2017 Acquisition was funded through cash. For the three and six months ended June 30, 2017, the pro forma financial information includes effects of adjustments for DD&A expense of $1.6 million and income tax expense of $0.6 million.

The following pro forma results (in thousands, except per share data) do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. Asset acquisitions are not included in pro forma financial information, as it is not required. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

 
For the Three Months Ended June 30,
 
  For the Six Months Ended June 30,
 
2017
 
2017
Revenues
$
121,930

 
$
211,569

Operating expenses
$
135,090

 
$
252,213

Net income
$
7,417

 
$
16,133

Income per common share, basic and diluted
$
0.02

 
$
0.05




Note 4—Long‑Term Debt

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

 
June 30,
2018
 
December 31,
2017
Credit facility due August 16, 2022 (or an earlier time as set forth in the credit facility)
$
190,000

 
$
90,000

2021 Senior Notes due July 15, 2021

 
550,000

2024 Senior Notes due May 15, 2024
400,000

 
400,000

2026 Senior Notes due February 1, 2026
750,000

 

Unamortized debt issuance costs on Senior Notes
(18,421
)
 
(16,639
)
Total long-term debt
1,321,579

 
1,023,361

Less: current portion of long-term debt

 

Total long-term debt, net of current portion
$
1,321,579

 
$
1,023,361



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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 2018, the Company amended its revolving credit facility to (i) increase the borrowing base from $525.0 million to $750.0 million, subject to the current elected commitments of $650.0 million, (ii) increase the maximum amount for the letter of credit issued in favor of a purchaser of its crude oil from $25.0 million to $35.0 million, and (iii) amend certain provisions of the credit agreement, including the commitments and allocations of each lender. In connection with the 2026 Senior Notes Offering (as defined below), the borrowing base was automatically reduced to $700.0 million; however, the current elected commitments remained at $650.0 million.

In February 2018, the Company entered into a consent agreement and amended its revolving credit facility to (i) provide for consent by the lenders to (a) the designation of Elevation Midstream, LLC as an unrestricted subsidiary and (b) the transfer of certain assets by the Company and one of the guarantors to such unrestricted subsidiary; and (ii) amend certain provisions of the credit agreement, including the incurrence of indebtedness covenant to permit certain indebtedness in connection with certain transportation service agreements with such unrestricted subsidiary.
    
In May 2018, the Company amended its revolving credit facility to (i) increase the borrowing base from $700.0 million to $800.0 million, subject to current elected commitments of $650.0 million and (ii) reduce each of the applicable interest rate margins for borrowings by 0.50%.

As of June 30, 2018, the credit facility was subject to a borrowing base of $800.0 million, subject to current elected commitments of $650.0 million. As of June 30, 2018 and, with respect to the Prior Credit Facility, December 31, 2017, the Company had outstanding borrowings of $190.0 million and $90.0 million, respectively. As of June 30, 2018 and, with respect to the Prior Credit Facility, December 31, 2017, the Company had standby letters of credit of $35.7 million and $25.7 million, respectively. At June 30, 2018, the undrawn balance under the credit facility was $460.0 million. As of the date of this filing, the Company has $265.0 million borrowings outstanding under the credit facility.

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
%


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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 June 30, 2018 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.

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 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.


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Table of Contents

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 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 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 June 30, 2018, the Company had debt issuance costs, net of accumulated amortization, of $4.1 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 June 30, 2018, the Company had debt issuance costs, net of accumulated amortization, of $18.4 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 and six months ended June 30, 2018, the Company recorded amortization expense related to debt issuance costs of $0.9 million and $11.4 million, respectively, as compared to $0.9 million and $1.7 million for the three and six months ended June 30, 2017, respectively. Debt issuance costs for the six months ended June 30, 2018 include $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 June 30, 2018.

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Interest Incurred on Long‑Term Debt

For the three and six months ended June 30, 2018, the Company incurred interest expense on long‑term debt of $20.4 million and $40.2 million, respectively, as compared to $11.3 million and $22.6 million for the three and six months ended June 30, 2017, respectively. For the three and six months ended June 30, 2018, the Company capitalized interest expense on long term debt of $2.1 million and $4.7 million, respectively, as compared to $3.2 million and $5.6 million for the three and six months ended June 30, 2017, respectively, which has been reflected in the Company’s condensed consolidated financial statements. Also included in interest expense for the six months ended June 30, 2018 is 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 June 30, 2018.

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.

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 twelve 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 June 30, 2018 are summarized below:
 
2018
 
2019
NYMEX WTI Crude Swaps:
 
 
 
Notional volume (Bbl)
2,100,000

 

Weighted average fixed price ($/Bbl)
$
52.91

 
$

NYMEX WTI Crude Purchased Puts:
 
 
 
Notional volume (Bbl)
4,500,000

 
8,700,000

Weighted average purchased put price ($/Bbl)
$
49.81

 
$
51.19

NYMEX WTI Crude Sold Calls:
 
 
 
Notional volume (Bbl)
4,500,000

 
8,700,000

Weighted average sold call price ($/Bbl)
$
58.33

 
$
64.37

NYMEX WTI Crude Sold Puts:
 
 
 
Notional volume (Bbl)
6,600,000

 
8,700,000

Weighted average sold put price ($/Bbl)
$
40.00

 
$
41.69

NYMEX HH Natural Gas Swaps:
 
 
 
Notional volume (MMBtu)
19,800,000

 
12,000,000

Weighted average fixed price ($/MMBtu)
$
3.03

 
$
2.79

NYMEX HH Natural Gas Purchased Puts:
 
 
 
Notional volume (MMBtu)
1,200,000

 

Weighted average purchased put price ($/MMBtu)
$
3.00

 
$

NYMEX HH Natural Gas Sold Calls:
 
 
 
Notional volume (MMBtu)
1,200,000

 

Weighted average sold call price ($/MMBtu)
$
3.15

 
$

CIG Basis Gas Swaps:
 
 
 
Notional volume (MMBtu)
21,460,000

 
6,000,000

Weighted average fixed basis price ($/MMBtu)
$
(0.68
)
 
$
(0.78
)


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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 June 30, 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
 
$
86,397

 
$
(71,084
)
 
$
15,313

 
$
(1,389
)
 
$
14,190

Non-current assets
 
$
15,084

 
$
(14,818
)
 
$
266

 
$

 
$

Current liabilities
 
$
(224,651
)
 
$
71,084

 
$
(153,567
)
 
$
1,389

 
$
(158,423
)
Non-current liabilities
 
$
(21,063
)
 
$
14,818

 
$
(6,245
)
 
$

 
$


 
 
As of December 31, 2017
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
 
$
22,118

 
$
(17,986
)
 
$
4,132

 
$

 
$
4,132

Non-current assets
 
$
13,686

 
$
(13,686
)
 
$

 
$

 
$

Current liabilities
 
$
(85,414
)
 
$
17,986

 
$
(67,428
)
 
$

 
$
(84,702
)
Non-current liabilities
 
$
(30,960
)
 
$
13,686

 
$
(17,274
)
 
$

 
$

 
(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.

The table below sets forth the commodity derivatives gain (loss) for the three and six months ended June 30, 2018 and 2017 (in thousands). Commodity derivatives gain (loss) is included under the other income (expense) line item in the condensed consolidated statements of operations.
 
For the Three Months Ended June 30,
 
  For the Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Commodity derivatives gain (loss)
$
(89,511
)
 
$
33,876

 
$
(139,839
)
 
$
84,298



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, 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.


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The following table summarizes the activities of the Company’s asset retirement obligations for the period indicated (in thousands):
 
For the Six Months Ended June 30, 2018
 
For the Year Ended December 31, 2017
Balance beginning of period
$
69,540

 
$
56,108

Liabilities incurred or acquired
1,066

 
9,802

Liabilities settled
(5,178
)
 
(4,169
)
Revisions in estimated cash flows
1,438

 
2,630

Accretion expense
2,764

 
5,169

Balance end of period
$
69,630

 
$
69,540



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 June 30, 2018 and December 31, 2017 by level within the fair value hierarchy (in thousands):

 
Fair Value Measurements at
June 30, 2018 Using
 
Level 1
 
Level 2
 
Level 3
 
Total
Financial Assets:
 
 
 
 
 
 
 
Commodity derivative assets
$

 
$
15,579

 
$

 
$
15,579

Financial Liabilities:
 
 
 
 
 
 
 
Commodity derivative liabilities
$

 
$
159,812

 
$

 
$
159,812


 
Fair Value Measurements at
December 31, 2017 Using
 
Level 1
 
Level 2
 
Level 3
 
Total
Financial Assets:
 
 
 
 
 
 
 
Commodity derivative assets
$

 
$
4,132

 
$

 
$
4,132

Financial Liabilities:
 
 
 
 
 
 
 
Commodity derivative liabilities
$

 
$
84,702

 
$

 
$
84,702



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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 2021 Senior Notes, 2024 Senior Notes and 2026 Senior Notes were derived from available market data. As such, the Company has classified the 2021 Senior Notes, 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 June 30, 2018
 
At December 31, 2017
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Credit Facility
$
190,000

 
$
190,000

 
$
90,000

 
$
90,000

2021 Senior Notes(1)
$

 
$

 
$
540,382

 
$
583,000

2024 Senior Notes(2)
$
393,414

 
$
419,000

 
$
392,979

 
$
427,000

2026 Senior Notes(3)
$
738,165

 
$
725,625

 
$

 
$

 
(1)
The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs of $9.6 million as of December 31, 2017. There were no unamortized debt issuance costs as of June 30, 2018.
(2)
The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $6.6 million and $7.0 million as of June 30, 2018 and December 31, 2017, respectively.
(3)
The carrying amount of the 2026 Senior Notes includes unamortized debt issuance costs of $11.8 million as of June 30, 2018. There were no unamortized debt issuance costs as of December 31, 2017.

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.

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 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

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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). No impairment expense was recognized for the three and six months ended June 30, 2018 and 2017 on proved oil and gas properties.

The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other. Goodwill represents the excess of the purchase price over the estimated value of the net assets acquired in business combinations. The Company tests goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents the Company’s oil and gas operations in its core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of the Company’s common shares could change the estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed an assessment as of September 30, 2017, which concluded the fair value of the reporting unit was greater than its carrying amount. The Company performed a qualitative assessment as of June 30, 2018, which concluded the fair value of the reporting unit was greater than its carrying amount.

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, please refer to Note 3 — Acquisitions and Divestitures. 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 six months ended June 30, 2018 was 18.7%. During the six months ended June 30, 2018, the Company recognized income tax benefit of $9.9 million. The effective rate for the six months ended June 30, 2018 differs from the statutory U.S. federal income tax rate of 21.0% primarily due to state income taxes and estimated permanent differences. Included as a discrete item during the six months ended June 30, 2018 is the tax deficiency related to equity compensation in excess of compensation recognized for financial reporting. 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.

On December 22, 2017, the Tax Cut and Jobs Act (the "TCJA") was enacted, making significant changes to the Internal Revenue Code. The Company calculated its best estimate of the impact of the TCJA in its December 31, 2017 income tax provision in accordance with its understanding of the TCJA and guidance available as of the date of this filing. The Company will continue to assess the income tax effects of the TCJA during 2018. The Company anticipates completing the analysis of the impacts of the TCJA within the one year measurement period provided for under the Security and Exchange Commission's Staff Accounting Bulletin No. 118. During the six months ended June 30, 2018, the Company made a reasonable estimate and recorded an additional provisional deferred tax asset related to stock-based compensation. There were no additional estimates associated with the TCJA included in the income tax benefit for six months ended June 30, 2018.



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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.

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. As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09.

The Company recorded $7.5 million and $13.6 million of stock-based compensation costs related to RSUs for the three and six months ended June 30, 2018, respectively, as compared to $7.8 million and $15.8 million for the three and six months ended June 30, 2017, respectively. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of June 30, 2018, there was $45.6 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 1.8 years.

The following table summarizes the RSU activity from January 1, 2018 through June 30, 2018 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, 2018
2,906,473

 
$
19.51

Granted
1,099,468

 
$
12.82

Forfeited
(41,425)

 
$
16.12

Vested
(218,013)

 
$
15.90

Non-vested RSUs at June 30, 2018
3,746,503

 
$
17.78


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 were 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 and $7.5 million of stock-based compensation costs related to the stock options for the three and six months ended June 30, 2018, respectively, as compared to $3.3 million and $6.6 million for the three and six months ended June 30, 2017, respectively. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of June 30, 2018, there was $19.7 million of unrecognized compensation cost related to the stock options that is expected to be recognized over a weighted average period of 1.3 years.


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The following table summarizes the stock option activity from January 1, 2018 through June 30, 2018 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, 2018
3,496,290

 
$
18.50

Granted

 
$

Forfeited

 
$

Vested

 
$

Non-vested Stock Options at June 30, 2018
3,496,290

 
$
18.50


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 ATSR and RTSR is based on a comparison of the Company's 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 and $2.6 million of stock-based compensation costs related to PSAs for the three and six months ended June 30, 2018, respectively. The Company did not record any stock-based compensation related to PSAs for the three and six months ended June 30, 2017. 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 June 30, 2018, there was $12.3 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 2.2 years.


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The following table summarizes the PSA activity from January 1, 2018 through June 30, 2018 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, 2018
832,163

 
$
8.85

Granted
1,961,920

 
$
9.06

Forfeited

 
$

Vested

 
$

Non-vested PSAs at June 30, 2018
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 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 of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09. 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 $4.9 million and $9.8 million of stock-based compensation costs related to Incentive RSUs for the three and six months ended June 30, 2018, respectively. The Company recorded $1.8 million and $6.2 million of stock-based compensation costs related to Incentive RSUs for the three and six months ended June 30, 2017. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of June 30, 2018, there was $10.7 million of total unrecognized compensation cost related to the unvested Incentive RSUs granted to certain employees that is expected to be recognized over a weighted average period of 0.5 years.

The following table summarizes the Incentive RSU activity from January 1, 2018 through June 30, 2018 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, 2018
1,496,175

 
$
20.45

Granted

 
$

Forfeited
(37,350)

 
$
20.45

Vested
(498,725)

 
$
20.45

Non-vested Incentive RSUs at June 30, 2018
960,100

 
$
20.45


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

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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 and six months ended June 30, 2018 and 2017.

The components of basic and diluted EPS were as follows (in thousands, except per share data):
 
For the Three Months Ended June 30,
 
For the Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Basic and Diluted Income (Loss) Per Share
 
 
 
 
 
 
 
Net Income (Loss)
$
8,848

 
$
7,240

 
$
(43,147
)
 
$
15,956

Less: Adjustment to reflect Series A Preferred Stock dividend
(2,721
)
 
(2,722
)
 
(5,443
)
 
(5,443
)
Less: Adjustment to reflect accretion of Series A Preferred Stock discount
(1,476
)
 
(1,331
)
 
(2,914
)
 
(2,627
)
Adjusted net income (loss) available to common shareholders, basic and diluted
$
4,651

 
$
3,187

 
$
(51,504
)
 
$
7,886

Denominator:
 
 
 
 
 
 
 
Weighted average common shares outstanding, basic and diluted (1) (2)
175,762

 
171,835

 
174,992

 
171,835

Income (Loss) Per Common Share
 
 
 
 
 
 
 
Basic and diluted
$
0.03

 
$
0.02

 
$
(0.29
)
 
$
0.05

 
(1)
For the three months ended June 30, 2018, 413,154 dilutive restricted stock awards were excluded from the calculation above, as the impact of these awards were inconsequential to dilutive weighted average shares outstanding and dilutive EPS. Additionally, 5,244,428 common shares for stock options were excluded as they were out-of-the-money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were excluded, as they would have had an anti-dilutive effect on EPS. For the six months ended June 30, 2018, 8,990,931 potentially dilutive shares were not included in the calculation above, as they would have 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.
(2)
For the three months ended June 30, 2017, 8,571,683 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. For the six months ended June 30, 2017, 359,338 dilutive restricted stock awards were excluded from the calculation above, as the impact of these awards were inconsequential to dilutive weighted average shares outstanding and dilutive EPS. Additionally, 4,500,000 common shares for stock options were excluded as they were out-of-the-money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were excluded, as they would have had an anti-dilutive effect on EPS.

Note 11—Commitments and Contingencies

Leases

The Company leases two office spaces in Denver, Colorado, two office spaces in Greeley, Colorado and one office space in Houston, Texas under separate operating lease agreements. The Denver, Colorado leases expire on February 29, 2020 and May 31, 2026, respectively. The Greeley and Houston leases expire on August 31, 2019, June 30, 2019 and January 31, 2022, respectively. Total rental commitments under non‑cancelable leases for office space were $34.4 million at June 30, 2018. The future minimum lease payments under these non‑cancelable leases are as follows: $1.6 million in 2018, $3.5 million in 2019, $3.4 million in 2020, $3.4 million in 2021, $3.4 million in 2022 and $19.1 million thereafter. Rent expense was $0.9 million and $1.7 million for the three and six months ended June 30, 2018, respectively, as compared to $0.6 million and $1.2 million for the three and six months ended June 30, 2017, respectively.

On June 4, 2015, the Company subleased the remaining term of one of its Denver office leases that expires February 29, 2020. The sublease will decrease the Company’s future lease payments by $0.4 million.


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Drilling Rigs

As of June 30, 2018, the Company was subject to commitments on three drilling rigs. In the event of early termination of these contracts, the Company would be obligated to pay an aggregate amount of approximately $9.3 million as of June 30, 2018, as required under the terms of the contracts.

Delivery Commitments

As of June 30, 2018, 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 evaluates its contracts for loss contingencies and accrues for such losses, if the loss can be reasonably estimated and deemed probable. The Company also has two long-term crude oil gathering commitments with an unconsolidated subsidiary, in which the Company has a minority ownership interest. The first agreement commenced in November 2016 and has a term of ten years for an average of 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The second agreement will commence in or around July 2019 and has a term of ten years for an average of 8,000 Bbl/d in year one, 20,000 Bbl/d in year two, 35,000 Bbl/d in year three, 40,000 Bbl/d in years four through eight, 30,000 Bbl/d in year nine and 25,000 Bbl/d in year ten. The aggregate amount of estimated remaining payments under these agreements is $991.4 million.

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. Under its current drilling plans, the Company expects to meet these volume commitments.

Acquisition of Undeveloped Leasehold Acreage

The Company was party to an agreement during 2017 with an unrelated third party for which it has paid $247.6 million through June 30, 2018 to complete its leasing program of approximately 38,800 net acres of undeveloped leasehold.

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.


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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.

2021 Senior Notes

Several lenders of the 2021 Senior Notes are also 5% stockholders of the Company. As of the initial issuance in July 2016 of the $550.0 million principal amount on the 2021 Senior Notes, such stockholders held $63.5 million.

2024 Senior Notes

Several lenders of the 2024 Senior Notes are also 5% stockholders of the Company. As of the initial issuance in August 2017 of the $400.0 million principal amount on the 2024 Senior Notes, such stockholders held $54.9 million.

2026 Senior Notes

Several lenders 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.

Series A Preferred Stock

Several holders of the Series A Preferred Stock are also 5% stockholders of the Company. As of the initial issuance in October 2016 of the $185.3 million of Series A Preferred Stock, such stockholders held $105.0 million.


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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, 2017 (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. 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 and six months ended June 30, 2018 and 2017.

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.

Financial Results

For the three and six months ended June 30, 2018, crude oil, natural gas and NGL sales, coupled with the impact of settled derivatives, increased to $224.4 million and $428.3 million, respectively, as compared to $119.9 million and $200.5 million, respectively, in the same prior year periods due to an increase in sales volumes of 2,674 MBoe and 5,869 MBoe, respectively. The increase in crude oil, natural gas and NGL sales for the three and six months ended June 30, 2018 as compared to the same prior year periods was also due to an increase of $3.69 and $4.67, respectively, in realized price per BOE, including settled derivatives.

For the three and six months ended June 30, 2018, we had net income of $8.8 million and net loss of $43.1 million, respectively, as compared to net income of $7.2 million and $16.0 million for the three and six months ended June 30, 2017, respectively. The change to net income for the three months ended June 30, 2018 from the three months ended June 30, 2017 was primarily driven by an increase in sales revenues of $140.4 million, an increase in operating expenses of $6.2 million, which includes the gain on sale of property and equipment of $59.9 million, and an increase in commodity derivative loss of $123.4 million. The change from net income to loss for the six months ended June 30, 2018 from the six months ended June 30, 2017 was primarily driven by an increase in commodity derivative loss of $224.1 million, an increase in operating expenses of $72.0 million, which includes the gain on sale of property and equipment of $59.9 million, an increase in interest expense of $63.8 million, which includes a make-whole premium of $35.6 million and $9.4 million of acceleration of amortization expense upon the repayment of the Company's 2021 Senior Notes, partially offset by an increase in sales revenues of $281.0 million.

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Adjusted EBITDAX was $153.1 million and $294.1 million for the three and six months ended June 30, 2018, respectively, as compared to $74.9 million and $117.3 million for the three and six months ended June 30, 2017, respectively, reflecting a 104.5% and 150.7% increase, respectively. 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.”

Operational Results

During the three months ended June 30, 2018, our aggregate drilling, completion, and leasehold capital expenditures, excluding outstanding elections, totaled $280.4 million, of which $246.8 million was drilling and completion additions and $33.6 million was leasehold and surface acreage additions. In addition, Elevation Midstream, LLC, our wholly owned midstream subsidiary, incurred $14.4 million of capital expenditures during the three months ended June 30, 2018. These capital expenditures are funded entirely by the Elevation Midstream, LLC Securities Purchase Agreement. See "Recent Developments" for more information

During the three months ended June 30, 2018, we reached total depth on 40 gross (29 net) wells with an average lateral length of approximately 7,725 feet and completed 61 gross (46 net) wells with an average lateral length of approximately 7,580 feet. We turned to sales 26 gross (19 net) wells with an average lateral length of approximately 5,586 feet. We completed 2,699 total fracturing stages during the quarter while pumping approximately 674 million pounds of proppant.

Recent Developments

August 2018 Divestiture

On August 3, 2018, Elevation Midstream, LLC ("Elevation"), a Delaware limited liability company and subsidiary of the Company, received $83.6 million upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of which Elevation held a 10% membership interest. Elevation acquired its interest in exchange for the contribution of nonfinancial assets.

Elevation Midstream, LLC Securities Purchase Agreement

On July 3, 2018, Elevation entered into a securities purchase agreement (the “Securities Purchase Agreement”) with a third party (the "Purchaser"), pursuant to which Elevation agreed to sell 150,000 Preferred Units (the “Elevation Preferred Units”) of Elevation at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $150.0 million (the “Private Placement”), in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The Private Placement closed on July 3, 2018 (the “Closing Date”) and resulted in net proceeds of approximately $141.9 million, $25.4 million of which was a reimbursement for previously incurred midstream capital expenditures and general and administrative expenses. These Preferred Units are non-recourse to Extraction.

During the twenty eight months following the Closing Date (the “Commitment Period”), subject to the satisfaction of certain financial and operational metrics and certain other customary closing conditions, Elevation has the right to require the Purchaser to purchase additional Elevation Preferred Units on the terms set forth in the Securities Purchase Agreement. Elevation may require the Purchaser to purchase additional Elevation Preferred Units, in increments of at least $25.0 million, up to an aggregate amount of $350.0 million. During the Commitment Period, Elevation is required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn amounts of such additional $350.0 million commitment.

As part of the transaction, Extraction also committed to Elevation that it would drill at least 425 wells in the acreage dedicated to Elevation by December 21, 2023, subject to reduction if Extraction does not sell the full amount of additional Elevation Preferred Units to the Purchaser. By way of comparison, Extraction plans to drill a total of approximately 170 wells during 2018.

The Elevation Preferred Units will entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum (the “Dividend”). In respect of quarters ending prior to and including June 30, 2020, the Dividend is payable in cash or in kind at the election of Elevation. After June 30, 2020, the Dividend is payable solely in cash.


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May 2018 Credit Facility Amendment

On May 23, 2018, we amended the revolving credit facility to, among other things, (i) increase the borrowing base from $700.0 million to $800.0 million, subject to current elected commitments of $650.0 million and (ii) reduce each of the applicable interest rate margins for borrowings under the credit facility by 0.50%.

April 2018 Divestitures

In April 2018, we completed various sales of our interests in approximately 15,100 net acres of leasehold and primarily non-producing properties, for aggregate sales proceeds of approximately $72.3 million, subject to customary purchase price adjustments. The majority of these assets were from our Other Rockies Area and we will continue to explore divestitures, as part of our ongoing initiative to divest of non-strategic assets.

April 2018 Acquisition

On April 19, 2018, we 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. The acquisition provided new development opportunities in the Core DJ Basin.

February 2018 Credit Facility Amendment

On February 27, 2018, we entered into a consent agreement and amended the revolving credit facility to (i) provide for consent by the lenders to (a) the designation of Elevation Midstream, LLC as an unrestricted subsidiary and (b) the transfer of certain assets by the Company and one of the guarantors to such unrestricted subsidiary; and (ii) amend certain provisions of the credit agreement, including the incurrence of indebtedness covenant to permit certain indebtedness in connection with certain transportation service agreements with such unrestricted subsidiary.

2026 Senior Notes

On January 25, 2018, we 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 Note 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. We received net proceeds of approximately $737.9 million after deducting discounts and fees. We used approximately $534.2 million of the net proceeds from the 2026 Senior Notes Offering to tender for our 7.875% Senior Notes due 2021 ("2021 Senior Notes"), $52.7 million to redeem any 2021 Senior Notes not tendered and the remainder will be used for general corporate purposes.

Tender Offer to Purchase 2021 Senior Notes

On January 25, 2018, we announced the results of our cash tender offer to purchase any and all of the outstanding aggregate principal amount of the 2021 Senior Notes. An aggregate principal amount of $500.6 million (91%) was tendered and paid, in addition to a make-whole premium of $32.6 million and accrued and unpaid interest of $1.0 million, on January 25, 2018. On February 17, 2018, we 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.

January 2018 Credit Facility Amendment

On January 5, 2018, we amended the revolving credit facility to (i) increase the borrowing base from $525.0 million to $750.0 million, subject to the current elected commitments of $650.0 million, (ii) increase the maximum amount for the letter of credit issued in favor of a purchaser of our crude oil from $25.0 million to $35.0 million, and (iii) amend certain provisions of the credit agreement, including the commitments and allocation of each lender. In connection with the 2026 Senior Notes Offering, the borrowing base was automatically reduced to $700.0 million; however, the current elected commitments remained $650.0 million.

January 2018 Acquisition


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On January 8, 2018, we 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 $11.6 million in cash. The acquisition provided new development opportunities in the Core DJ Basin.

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:

Sources of revenue;
Sales volumes;
Realized prices on the sale of oil, natural gas and NGL, including the effect of our commodity derivative contracts;
Lease operating expenses (“LOE”);
Capital expenditures; and
Adjusted EBITDAX (a Non-GAAP measure).
Sources of Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGL that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives. For the three months ended June 30, 2018, our revenues were derived 82% from oil sales, 8% from natural gas sales and 10% from NGL sales. For the three months ended June 30, 2017, our revenues were derived 71% from oil sales, 16% from natural gas sales and 13% from NGL sales. For the six months ended June 30, 2018, our revenues were derived 80% from oil sales, 9% from natural gas sales and 11% from NGL sales. For the six months ended June 30, 2017, our revenues were derived 66% from oil sales, 18% from natural gas sales and 16% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Sales Volumes

The following table presents historical sales volumes for our properties for the periods indicated:
 
For the Three Months Ended
June 30,
 
For the Six Months Ended
June 30,
 
2018
 
2017
 
2018
 
2017
Oil (MBbl)
3,531

 
2,101

 
6,776

 
3,312

Natural gas (MMcf)
11,370

 
6,402

 
21,774

 
12,761

NGL (MBbl)
1,268

 
852

 
2,488

 
1,585

Total (MBoe)
6,694

 
4,020

 
12,893

 
7,024

Average net sales (BOE/d)
73,563

 
44,172

 
71,231

 
38,807


As reservoir pressure declines, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through organic growth as well as acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including takeaway capacity in our areas of operation and our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please read “Risks Related to the Oil, Natural Gas and NGL Industry and Our Business” in Item 1A. of our Annual Report for a further description of the risks that affect us.

Realized Prices on the Sale of Oil, Natural Gas and NGL

Our results of operations depend upon many factors, particularly the price of oil, natural gas and NGL and our ability to market our production effectively. Oil, natural gas and NGL prices are among the most volatile of all commodity prices. For example, during the period from January 1, 2014 to June 30, 2018, NYMEX West Texas Intermediate oil prices ranged from a high of $107.26 per Bbl to a low of $26.21 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu during the same period. Declines in, and continued depression of, the price of

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oil and natural gas occurring during 2015 and continuing into 2017, and the subsequent increase during 2018 are due to a combination of factors including increased U.S. supply, global economic concerns and geopolitical risks. These price variations can have a material impact on our financial results and capital expenditures.

Oil pricing is predominately driven by the physical market, supply and demand, financial markets and national and international politics. The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. In the DJ Basin, oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials.

Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGL. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. The price we receive for our natural gas produced in the DJ Basin is based on CIG prices, adjusted for certain deductions.

Our price for NGL produced in the DJ Basin is based on a combination of prices from the Conway hub in Kansas and Mont Belvieu in Texas where this production is marketed.

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The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil, natural gas and NGL normally sells at a discount to the NYMEX WTI and NYMEX Henry Hub price, as applicable.

 
For the Three Months Ended
June 30,
 
For the Six Months Ended
June 30,
 
2018
 
2017
 
2018
 
2017
Oil
 
 
 
 
 
 
 
NYMEX WTI High ($/Bbl)
$
74.15

 
$
53.40

 
$
74.15

 
$
54.45

NYMEX WTI Low ($/Bbl)
$
62.06

 
$
42.53

 
$
59.19

 
$
42.53

NYMEX WTI Average ($/Bbl)
$
67.91

 
$
48.15

 
$
65.46

 
$
49.95

Average Realized Price ($/Bbl)
$
60.46

 
$
40.64

 
$
58.11

 
$
41.52

Average Realized Price, with derivative settlements ($/Bbl)
$
48.89

 
$
40.70

 
$
47.28

 
$
39.14

Average Realized Price as a % of Average NYMEX WTI
89.0
%
 
84.4
%
 
88.8
%
 
83.1
%
Differential ($/Bbl) to Average NYMEX WTI
$
(7.45
)
 
$
(7.51
)
 
$
(7.35
)
 
$
(8.43
)
Natural Gas
 
 
 
 
 
 
 
NYMEX Henry Hub High ($/MMBtu)
$
3.02

 
$
3.42

 
$
3.63

 
$
3.42

NYMEX Henry Hub Low ($/MMBtu)
$
2.66

 
$
2.89

 
$
2.55

 
$
2.56

NYMEX Henry Hub Average ($/MMBtu)
$
2.83

 
$
3.14

 
$
2.84

 
$
3.10

NYMEX Henry Hub Average converted to a $/Mcf basis (factor of 1.1 to 1)
$
3.11

 
$
3.45

 
$
3.12

 
$
3.41

Average Realized Price ($/Mcf)
$
1.74

 
$
2.89

 
$
2.02

 
$
3.01

Average Realized Price, with derivative settlements ($/Mcf)
$
2.19

 
$
2.90

 
$
2.53

 
$
2.94

Average Realized Price as a % of Average NYMEX Henry Hub(1)
55.9
%
 
83.9
%
 
64.7
%
 
88.3
%
Differential ($/Mcf) to Average NYMEX Henry Hub
$
(1.37
)
 
$
(0.56
)
 
$
(1.10
)
 
$
(0.40
)
NGL
 
 
 
 
 
 
 
Average Realized Price ($/Bbl)
$
21.22

 
$
18.61

 
$
21.21