xog_Current_Folio_10Q

Table of Contents

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

 

 

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

 

For the quarterly period ended March 31, 2017

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  ☒    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  ☒    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

 

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  ☒

 

The total number of shares of common stock, par value $0.01 per share, outstanding as of May 5, 2017 was 171,834,605.

 

 

 

 


 

Table of Contents

EXTRACTION OIL & GAS, INC.

TABLE OF CONTENTS

 

 

 

 

 

 

 

 

    

    

   

Page

 

PART I—FINANCIAL INFORMATION 

 

 

 

 

 

 

 

Item 1. 

 

Condensed Consolidated Financial Statements (Unaudited)

 

 

 

 

 

Condensed Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016

 

5

 

 

 

Condensed Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016

 

6

 

 

 

Condensed Consolidated Statements of Changes in Members’ and Stockholders’ Equity for the three months ended March 31, 2017 and 2016

 

7

 

 

 

Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and 2016

 

8

 

 

 

Notes to the Unaudited Condensed Consolidated Financial Statements

 

9

 

Item 2. 

 

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

 

27

 

Item 3. 

 

Quantitative and Qualitative Disclosures about Market Risk

 

49

 

Item 4.

 

Controls and Procedures

 

52

 

 

 

 

 

 

 

PART II—OTHER INFORMATION 

 

 

 

 

 

 

 

Item 1. 

 

Legal Proceedings

 

53

 

Item 1A. 

 

Risk Factors

 

53

 

Item 2. 

 

Unregistered Sales of Equity Securities and Use of Proceeds

 

53

 

Item 3. 

 

Defaults upon Senior Securities

 

53

 

Item 4. 

 

Mine Safety Disclosures

 

53

 

Item 5. 

 

Other Information

 

53

 

Item 6. 

 

Exhibits

 

53

 

 

 

Signatures

 

54

 

 

 

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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. following the completion of our initial public offering on October 17, 2016, as described in our Annual Report on Form 10-K (“Annual Report”). When used in the historical context, the "Company," "Holdings,”  "us," "we," "our" and "ours" or like terms refer to Extraction Oil & Gas Holdings, LLC and its subsidiaries. Holdings is our accounting predecessor, for which we present the consolidated financial statements for the three months ended March 31, 2016 in this Quarterly Report.

 

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 on 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.

 

"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.

 

"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.

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

 

"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.

 

"Net revenue interest" means all of the working interests less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.

 

"NGL" means natural gas liquids.

 

"NYMEX" means New York Mercantile Exchange.

 

“Overriding royalty” means an interest in the gross revenues or production over and above the landowner’s royalty carved out of the working interest and also unencumbered with any expenses of operation, development or maintenance.

 

“Operator” means the individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.

 

“Producing well” means a well that is producing oil or natural gas or that is capable of production.

 

"Proved developed reserves" means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

 

"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.

 

"Proved undeveloped reserves" means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

 

“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.

 

"Recompletion" means the completion for production from an existing wellbore in a formation other than that in which the well has previously been completed.

 

"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.

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"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.

 

“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

 

“Undeveloped acreage” means lease acres 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 or not such acreage contains proved reserves.

 

“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.

 

“Unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

 

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

 

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

 

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

 

 

 

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Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

 

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

 

 

 

 

 

 

 

 

 

    

March 31, 

    

December 31, 

 

 

    

2017

    

2016

 

ASSETS

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

284,551

 

$

588,736

 

Accounts receivable

 

 

 

 

 

 

 

Trade

 

 

21,775

 

 

23,154

 

Oil, natural gas and NGL sales

 

 

31,066

 

 

34,066

 

Inventory and prepaid expenses

 

 

9,715

 

 

7,722

 

Total Current Assets

 

 

347,107

 

 

653,678

 

Property and Equipment (successful efforts method), at cost:

 

 

 

 

 

 

 

Proved oil and gas properties

 

 

2,081,304

 

 

1,851,052

 

Unproved oil and gas properties

 

 

479,710

 

 

452,577

 

Wells in progress

 

 

141,423

 

 

98,747

 

Less: accumulated depletion, depreciation and amortization

 

 

(451,458)

 

 

(402,912)

 

Net oil and gas properties

 

 

2,250,979

 

 

1,999,464

 

Other property and equipment, net of accumulated depreciation

 

 

32,677

 

 

32,721

 

Net Property and Equipment

 

 

2,283,656

 

 

2,032,185

 

Non-Current Assets:

 

 

 

 

 

 

 

Cash held in escrow

 

 

22,318

 

 

42,200

 

Commodity derivative asset

 

 

5,724

 

 

 —

 

Goodwill and other intangible assets, net of accumulated amortization

 

 

54,526

 

 

54,489

 

Other non-current assets

 

 

1,947

 

 

2,224

 

Total Non-Current Assets

 

 

84,515

 

 

98,913

 

Total Assets

 

$

2,715,278

 

$

2,784,776

 

LIABILITIES AND STOCKHOLDERS' EQUITY

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

88,166

 

$

131,134

 

Revenue payable

 

 

34,499

 

 

35,162

 

Production taxes payable

 

 

27,080

 

 

27,327

 

Commodity derivative liability

 

 

9,002

 

 

56,003

 

Accrued interest payable

 

 

9,148

 

 

19,621

 

Asset retirement obligations

 

 

4,375

 

 

5,300

 

Total Current Liabilities

 

 

172,270

 

 

274,547

 

Non-Current Liabilities:

 

 

 

 

 

 

 

Senior Notes, net of unamortized debt issuance costs

 

 

538,684

 

 

538,141

 

Production taxes payable

 

 

45,342

 

 

35,838

 

Commodity derivative liability

 

 

 —

 

 

6,738

 

Other non-current liabilities

 

 

3,408

 

 

3,466

 

Asset retirement obligations

 

 

53,751

 

 

50,808

 

Deferred tax liability

 

 

111,156

 

 

106,026

 

Total Non-Current Liabilities

 

 

752,341

 

 

741,017

 

Commitments and Contingencies—Note 11

 

 

 

 

 

 

 

Total Liabilities

 

 

924,611

 

 

1,015,564

 

 

 

 

 

 

 

 

 

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

 

 

154,360

 

 

153,139

 

 

 

 

 

 

 

 

 

Stockholders' Equity:

 

 

 

 

 

 

 

Common stock, $0.01 par value; 900,000,000 shares authorized; 171,834,605 issued and outstanding

 

 

1,718

 

 

1,718

 

Additional paid-in capital

 

 

2,079,108

 

 

2,067,590

 

Accumulated deficit

 

 

(444,519)

 

 

(453,235)

 

Total Stockholders' Equity

 

 

1,636,307

 

 

1,616,073

 

Total Liabilities and Stockholders' Equity

 

$

2,715,278

 

$

2,784,776

 

 

 

 

 

 

 

 

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

 

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Table of Contents

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

 

 

March 31, 

 

 

    

2017

    

2016

    

Revenues:

 

 

 

 

 

 

 

Oil sales

 

$

52,128

 

$

34,088

 

Natural gas sales

 

 

19,897

 

 

6,606

 

NGL sales

 

 

17,614

 

 

4,438

 

Total Revenues

 

 

89,639

 

 

45,132

 

Operating Expenses:

 

 

 

 

 

 

 

Lease operating expenses

 

 

22,323

 

 

11,970

 

Production taxes

 

 

6,453

 

 

4,490

 

Exploration expenses

 

 

10,812

 

 

2,831

 

Depletion, depreciation, amortization and accretion

 

 

50,653

 

 

45,308

 

Impairment of long lived assets

 

 

675

 

 

446

 

Other operating expenses

 

 

451

 

 

891

 

Acquisition transaction expenses

 

 

68

 

 

 —

 

General and administrative expenses

 

 

25,688

 

 

7,140

 

Total Operating Expenses

 

 

117,123

 

 

73,076

 

Operating Loss

 

 

(27,484)

 

 

(27,944)

 

Other Income (Expense):

 

 

 

 

 

 

 

Commodity derivatives gain (loss)

 

 

50,422

 

 

(4,036)

 

Interest expense

 

 

(9,660)

 

 

(13,568)

 

Other income

 

 

568

 

 

28

 

Total Other Income (Expense)

 

 

41,330

 

 

(17,576)

 

Net Income (Loss) Before Income Taxes

 

 

13,846

 

 

(45,520)

 

Income Tax Expense

 

 

5,130

 

 

 —

 

Net Income (Loss)

 

$

8,716

 

$

(45,520)

 

Earnings Per Common Share (Note 10)

 

 

 

 

 

 

 

Basic and diluted

 

$

0.03

 

 

 

 

Weighted Average Common Shares Outstanding

 

 

 

 

 

 

 

Basic and diluted

 

 

171,835

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

MEMBERS’ AND STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Members' Units

 

Common Stock

 

 

 

 

 

 

 

 

 

 

 

 

 

Preferred

 

 

 

 

 

 

 

 

 

Additional

 

Retained

 

 

 

 

 

Tranche A

 

Tranche C

 

 

 

 

 

 

 

 

 

Paid in

 

Earnings

 

Total

 

 

 

Units

 

Units

 

Amount

 

Shares

 

 

Amount

 

Capital

 

(Deficit)

 

Equity

 

Balance at January 1, 2016

 

231,101

 

78,444

 

$

751,466

 

 —

 

$

 —

 

$

 —

 

$

2,766

 

$

754,232

 

Restricted stock units issued

 

304

 

 —

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

 —

 

Unit-based compensation

 

 —

 

 —

 

 

1,368

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

1,368

 

Net loss

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

(45,520)

 

 

(45,520)

 

Balance at March 31, 2016

 

231,405

 

78,444

 

$

752,834

 

 —

 

$

 —

 

$

 —

 

$

(42,754)

 

$

710,080

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at January 1, 2017

 

 —

 

 —

 

$

 —

 

171,835

 

$

1,718

 

$

2,067,590

 

$

(453,235)

 

$

1,616,073

 

Common stock issuance costs

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

(210)

 

 

 —

 

 

(210)

 

Stock-based compensation

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

15,745

 

 

 —

 

 

15,745

 

Series A Preferred Stock dividends

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

(2,721)

 

 

 —

 

 

(2,721)

 

Accretion of beneficial conversion feature on Series A Preferred Stock

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

(1,296)

 

 

 —

 

 

(1,296)

 

Net income

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

8,716

 

 

8,716

 

Balance at March 31, 2017

 

 —

 

 —

 

$

 —

 

171,835

 

$

1,718

 

$

2,079,108

 

$

(444,519)

 

$

1,636,307

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

 

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EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

 

 

March 31, 

 

 

    

2017

    

2016

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income (loss)

 

$

8,716

 

$

(45,520)

 

Reconciliation of net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Depletion, depreciation, amortization and accretion

 

 

50,653

 

 

45,308

 

Abandonment and impairment of unproved properties

 

 

2,735

 

 

 —

 

Impairment of long lived assets

 

 

675

 

 

446

 

Loss on sale of property and equipment

 

 

451

 

 

 —

 

Amortization of debt issuance costs and debt discount

 

 

845

 

 

1,198

 

Deferred rent

 

 

101

 

 

242

 

Commodity derivatives (gain) loss

 

 

(50,422)

 

 

4,036

 

Settlements on commodity derivatives

 

 

(9,129)

 

 

29,072

 

Premiums paid on commodity derivatives

 

 

 —

 

 

(30)

 

Deferred income tax expense

 

 

5,130

 

 

 —

 

Unit and stock-based compensation

 

 

15,745

 

 

1,368

 

Changes in current assets and liabilities:

 

 

 

 

 

 

 

Accounts receivable—trade

 

 

1,096

 

 

6,107

 

Accounts receivable—oil, natural gas and NGL sales

 

 

3,000

 

 

(557)

 

Inventory and prepaid expenses

 

 

140

 

 

252

 

Accounts payable and accrued liabilities

 

 

(7,913)

 

 

(17,738)

 

Revenue payable

 

 

(663)

 

 

(3,632)

 

Production taxes payable

 

 

9,248

 

 

5,816

 

Accrued interest payable

 

 

(10,473)

 

 

11,268

 

Asset retirement expenditures

 

 

(602)

 

 

(96)

 

Net cash provided by operating activities

 

 

19,333

 

 

37,540

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Oil and gas property additions

 

 

(334,606)

 

 

(79,086)

 

Acquired oil and gas properties

 

 

(3,830)

 

 

 —

 

Sale of other property and equipment

 

 

2,000

 

 

2,148

 

Other property and equipment additions

 

 

(3,231)

 

 

(1,586)

 

Cash held in escrow

 

 

19,882

 

 

 —

 

Net cash used in investing activities

 

 

(319,785)

 

 

(78,524)

 

Cash flows from financing activities:

 

 

 

 

 

 

 

Borrowings under credit facility

 

 

 —

 

 

10,000

 

Dividends on Series A Preferred Stock

 

 

(2,237)

 

 

 —

 

Debt issuance costs

 

 

(14)

 

 

 —

 

Equity issuance costs

 

 

(1,482)

 

 

(214)

 

Net cash provided by (used in) financing activities

 

 

(3,733)

 

 

9,786

 

Decrease in cash and cash equivalents

 

 

(304,185)

 

 

(31,198)

 

Cash and cash equivalents at beginning of period

 

 

588,736

 

 

97,106

 

Cash and cash equivalents at end of the period

 

$

284,551

 

$

65,908

 

Supplemental cash flow information:

 

 

 

 

 

 

 

Property and equipment included in accounts payable and accrued liabilities

 

$

71,308

 

$

60,020

 

Cash paid for interest

 

$

21,749

 

$

2,064

 

Accretion of beneficial conversion feature of Series A Preferred Stock

 

$

1,296

 

$

 —

 

 

 

 

 

 

 

 

 

 

 

 

 

 

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

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EXTRACTION OIL & GAS, INC.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1—Business and Organization

 

Extraction Oil & Gas, Inc. (the “Company” or “Extraction”) is an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of Colorado. The Company has nine subsidiaries, 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”.

 

The condensed consolidated financial statements for the three months ended March 31, 2016 are based on the financial statements of the Company’s accounting predecessor, Extraction Oil & Gas Holdings, LLC, prior to the corporate reorganization (the “Corporate Reorganization”), pursuant to which, in connection with the initial public offering (“IPO”) of the Company, (i) on October 11, 2016, a former subsidiary of Extraction Oil & Gas Holdings, LLC, Extraction Oil & Gas, LLC, converted into the Company, and (ii) on October 17, 2016, Holdings merged with and into the Company with the Company as the surviving entity. For further information on the Corporate Reorganization please refer to the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (“Annual Report”).

 

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 SEC 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 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 financial statements should be read in conjunction with the Company’s audited 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.

 

Recent Accounting Pronouncements

 

In February 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-05, which provides clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. Early adoption is permitted for fiscal years beginning after December 15, 2016, including the interim reporting periods within that fiscal year. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.

 

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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 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 this new standard to determine the potential impact to its 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 is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in the financial statements that have been issued. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.

 

In December 2016, the FASB issued ASU No. 2016-19, which among other technical corrections and improvements, adds a reference to guidance to use when accounting for internal-use software licensed from third parties that is within the scope of Subtopic 350-40. For public entities, the guidance is effective upon issuance of the ASU. Adoption is permitted either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. The Company elected to adopt this guidance prospectively during the fourth quarter of 2016, which resulted in the capitalization of internal-use software licensed from third parties to goodwill and other intangible assets on the consolidated balance sheets. Costs are amortized over their respective service periods and expensed to depletion, depreciation, and amortization on the consolidated statements of operations.

 

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 will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.

 

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. In addition, in November 2016, the FASB issued ASU 2016-18, which requires that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including an adoption in an interim period, with a required retrospective application to each period presented. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.

 

In March 2016, the FASB issued ASU No. 2016-09, which simplifies the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the consolidated statements of cash flows. ASU 2016-09 was effective for public companies for annual and interim reporting periods beginning after December 15, 2016, including interim periods within those fiscal years. The Company adopted this guidance during the first quarter of 2017. As a result of adoption of this guidance, the Company elected to account for the forfeiture of stock-based compensation forfeitures as they occur. The adoption of this standard did not have a significant impact on the Company’s financial statements and related disclosures.

 

In March 2016, the FASB issued ASU No. 2016-06, which clarifies the requirements to assess whether an embedded put or call option is clearly and closely related to the debt host, solely in accordance with the four step decision sequence in FASB ASC Topic 815, Derivatives and Hedging, as amended by ASU 2016-06. This standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and should be applied using a modified retrospective approach. Early adoption is permitted. The Company is currently evaluating the

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impact of adopting ASU 2016-06, however the standard is not expected to have a significant effect on its consolidated financial statements.

 

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 flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. The Company is currently evaluating the impact this new standard will have on its financial statements and related disclosures. As part of the Company’s assessment work to-date, the Company formed an implementation work team, completed training of the new ASU's leasing guidance, and is developing a strategy for implementation.

 

In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model 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 is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of reporting periods beginning after December 15, 2016. The FASB subsequent issued ASU 2016-08, ASU 2016-10, ASU 2016-11 and ASU 2016-12, and 2016-20, which provided additional implementation guidance. The Company is currently evaluating the level of effort necessary to implement the standards, evaluating the provisions of each of these standards, and assessing their potential impact on the Company’s financial statements and disclosures, as well as determining whether to use the full retrospective method or the modified retrospective method. The Company is currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on its financial statements and related disclosures. As part of the Company’s assessment work to-date, the Company formed an implementation work team, completed training of the new ASU's revenue recognition model, and is developing a strategy for implementation.

 

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 financial statements and related disclosures that have been issued but not yet adopted by the Company through the date of this filing.

 

Note 3—Acquisitions

 

Proposed July 2017 Acquisition

 

On March 24, 2017, the Company entered into a definitive agreement to acquire an unaffiliated oil and gas company’s interests in approximately 12,500 net acres of leasehold, and related producing and non-producing properties located in the DJ Basin of Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the "Proposed July 2017 Acquisition"). Upon closing the seller will receive total consideration of $84.0 million in cash, subject to customary purchase price adjustments. The effective date for the Proposed July 2017 Acquisition is July 1, 2017, with purchase price adjustments calculated as of the closing date, which is scheduled to occur in July 2017. The acquisition would provide new development opportunities in the DJ Basin. The Company also made an $8.4 million deposit in March 2017 in conjunction with Proposed July 2017 Acquisition, which has been reflected in the March 31, 2017 consolidated balance sheet within the cash held in escrow line item.

 

November 2016 Acquisition

 

On November 22, 2016, the Company acquired an unaffiliated oil and gas company’s interest in approximately 9,200 net acres of leaseholds located in the DJ Basin for approximately $120.0 million, including customary closing adjustments (the “November 2016 Acquisition”). The Company also made a $41.1 million deposit in November 2016 in conjunction with November 2016 Acquisition, which has been reflected in the December 31, 2016 consolidated balance sheets within the cash held in escrow line item. The deposit was made for two additional closings of leaseholds located

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in the DJ Basin. The first closing occurred in January 2017 and added approximately 5,300 net acres. The second closing is expected to occur in July 2017 and will add approximately 800 net acres.

 

October 2016 Acquisition

 

On October 3, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 6,400 net acres of leasehold, and related producing and non‑producing properties located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the “Bayswater Assets” and the acquisition, the “October 2016 Acquisition” or the “Bayswater Acquisition”). The seller received aggregate consideration of approximately $405.3 million in cash. The effective date for the acquisition was July 1, 2016, with purchase price adjustments calculated as of the closing date on October 3, 2016. The acquisition provides new development opportunities in the DJ Basin as well as increases the Company’s existing working interest, as the majority of the locations are located on acreage in which the Company already owns a majority working interest and operates. The Company incurred $2.6 million of transaction costs related to the acquisition. These transaction costs were recorded in the consolidated statements of operations within the acquisition transaction expenses line item in the third and fourth quarter of 2016. No transaction costs related to the acquisition were incurred for the three months ended March 31, 2017 and 2016.  

 

The acquisition is 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 October 3, 2016. In February 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

    

October 3, 2016

 

Consideration given

 

 

 

 

Cash

 

$

405,335

 

Total consideration given

 

$

405,335

 

Allocation of Purchase Price

 

 

 

 

Proved oil and gas properties

 

$

252,522

 

Unproved oil and gas properties

 

 

109,800

 

Total fair value of oil and gas properties acquired

 

$

362,322

 

Goodwill (1)

 

$

54,220

 

Working capital

 

 

(7,185)

 

Asset retirement obligations

 

 

(4,022)

 

Fair value of net assets acquired

 

$

405,335

 

Working capital acquired was estimated as follows:

 

 

 

 

Accounts receivable

 

$

955

 

Revenue payable

 

 

(3,012)

 

Production taxes payable

 

 

(4,244)

 

Accrued liabilities

 

 

(884)

 

Total working capital

 

$

(7,185)

 

 

(1)

Goodwill is primarily attributable to a decrease in commodity prices from the time the acquisition was negotiated to commodity prices on October 3, 2016 and the operational and financial synergies expected to be realized from the acquisition. Goodwill recognized as a result of the Bayswater Acquisition is not deductible for income tax purposes.

 

August 2016 Acquisition

 

On August 23, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 1,400 net acres of leasehold located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way and other assets (the “August 2016 Acquisition”). The seller received aggregate consideration of approximately $17.5 million in cash. The effective date for the acquisition was August 31, 2016, with purchase price adjustments calculated as of the closing date of August 23, 2016. The acquisition provided new

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development opportunities in the DJ Basin as well as additions adjacent to the Company’s core project area. The Company incurred $0.1 million of transaction costs related to the acquisition. These transaction costs were recorded in the consolidated statements of operations within the acquisition transaction expenses line item in the third quarter of 2016. No transaction costs related to the acquisition were incurred for the three months ended March 31, 2017 and 2016.

 

The 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 August 23, 2016. In March 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

    

August 23, 2016

 

Consideration given

 

 

 

 

Cash

 

$

17,504

 

Total consideration given

 

$

17,504

 

Allocation of Purchase Price

 

 

 

 

Proved oil and gas properties

 

$

12,362

 

Unproved oil and gas properties

 

 

8,566

 

Total fair value of oil and gas properties acquired

 

$

20,928

 

Working capital

 

$

(9)

 

Asset retirement obligations

 

 

(3,415)

 

Fair value of net assets acquired

 

$

17,504

 

Working capital acquired was estimated as follows:

 

 

 

 

Production taxes payable

 

 

(9)

 

Total working capital

 

$

(9)

 

 

Pro Forma Financial Information (Unaudited)

 

For the three months ended March 31, 2016, the following pro forma financial information represents the combined results for the Company and the properties acquired in October 2016 as if the acquisition and related financing had occurred on January 1, 2016. The October 2016 Acquisition was included in the historical results of the Company for the three months ended March 31, 2017, therefore no pro forma financial information is presented for this period. For purposes of the pro forma financial information, it was assumed that the October 2016 Acquisition was funded through the issuance of $260.3 million in convertible preferred securities and borrowings under the revolving credit facility. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $5.4 million for the three months ended March 31, 2016. The pro forma information includes the effects of adjustments for the incremental interest expense on acquisition financing of $1.1 million for the three months ended March 31, 2016. No pro forma adjustments were made for the effect of income taxes for the three months ended March 31, 2016 as the acquisitions occurred before the Corporate Reorganization. Additionally, the pro forma financial information excludes the effects the August 2016 Acquisition as these pro forma adjustments were de minimis.

 

The following pro forma results (in thousands) 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. 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. Net loss per share is not applicable for the period prior to the Corporate Reorganization.

 

 

 

 

 

 

 

 

For the Three Months Ended

 

 

 

March 31, 2016

 

Revenues

 

$

55,658

 

Operating expenses

 

$

80,905

 

Net loss

 

$

(43,952)

 

 

 

 

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Note 4—Long‑Term Debt

 

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

 

 

 

 

 

 

 

 

 

 

 

March 31, 

 

December 31, 

 

 

    

2017

    

2016

 

Credit facility due November 29, 2018

 

$

 —

 

$

 —

 

Senior Notes due July 15, 2021

 

 

550,000

 

 

550,000

 

Unamortized debt issuance costs on Senior Notes

 

 

(11,316)

 

 

(11,859)

 

Total long-term debt

 

 

538,684

 

 

538,141

 

Less: current portion of long-term debt

 

 

 —

 

 

 —

 

Total long-term debt, net of current portion

 

$

538,684

 

$

538,141

 

 

Credit Facility

 

The Company has commitments of $1.0 billion on its credit facility with a syndicate of banks, which is subject to a borrowing base. As of March 31, 2017, the credit facility was subject to a borrowing base of $475.0 million. The credit facility matures on November 29, 2018. As of each of March 31, 2017 and December 31, 2016, the Company had no outstanding borrowings. As of each of March 31, 2017 and December 31, 2016, the Company had standby letters of credit of $0.6 million. At March 31, 2017, the undrawn balance under the credit facility was $475.0 million. As of March 31, 2017 and the date of this filing, the Company has no balance outstanding under the credit facility. In May 2017, the Company amended its credit facility and issued a $20.0 million letter of credit, with the Company’s oil marketer named as the beneficiary thereof.

 

Redetermination of the borrowing base occurs semiannually on May 1 and November 1. Additionally, the Company and the administrative agent under the credit facility may each elect a redetermination of the borrowing base between any two scheduled redeterminations. In addition, the Company has exercised its right for a redetermination of the borrowing base on August 1, 2017.

 

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

 

 

 

 

 

 

 

 

 

 

 

 

    

 

    

LIBOR

 

Base Rate

 

Commitment

 

Borrowing Base Utilization Percentage

    

Utilization

 

Margin

 

Margin

 

Fee

 

Level 1

 

< 25

%  

2.00

%  

1.00

%  

0.375

%

Level 2

 

≥ 25% < 50

%  

2.25

%  

1.25

%  

0.375

%

Level 3

 

≥ 50% < 75

%  

2.50

%  

1.50

%  

0.500

%

Level 4

 

≥ 75% < 90

%  

2.75

%  

1.75

%  

0.500

%

Level 5

 

≥ 90

%  

3.00

%  

2.00

%  

0.500

%

 

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

 

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The credit facility also contains financial covenants requiring the Company to comply with a current ratio of our consolidated current assets (includes availability under our revolving credit facility and unrestricted cash and excludes derivative assets) to our consolidated current liabilities (excludes obligations under our 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 in excess of certain thresholds to our consolidated EBITDAX (EBITDAX is defined as net income adjusted for certain cash and non-cash items including depletion, depreciation, amortization and accretion, 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. For the quarters ending between and including December 31, 2016 through December 31, 2017, annualized EBITDAX will be based on the last six months’ consolidated EBITDAX multiplied by 2, and for the quarter ending March 31, 2018, annualized EBITDAX will be based on the last nine months’ consolidated EBITDAX multiplied by 4/3. For the quarters ending on or after June 30, 2018, annualized EBITDAX will be based on the last twelve months’ consolidated EBITDAX. The Company was in compliance with all financial covenants under the credit facility as of March 31, 2017, 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 its subsidiaries, including oil and gas properties, personal property and the equity interests of the subsidiaries of the Company. 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.

 

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 “Senior Notes” and the offering, the “Senior Notes Offering”). The Senior Notes bear an annual interest rate of 7.875%. The interest on the Senior Notes is 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.

 

Our Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. Our Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our current and future restricted subsidiaries (other than Extraction Finance Corp., the co-issuer of our Senior Notes) that guarantees our indebtedness under a credit facility (the “Guarantors”). The notes are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our 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 future subsidiaries that do not guarantee the notes.

 

The 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 Senior Notes (the “Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 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 Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under the Indenture as of March 31, 2017, and through the filing of this report.

 

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Debt Issuance Costs

 

As of March 31, 2017, the Company had debt issuance costs, net of accumulated amortization, of $1.9 million related to its credit facility which has been reflected on the Company’s balance sheet within the line item other non‑current assets. As of March 31, 2017, the Company had debt issuance costs, net of accumulated amortization, of $11.3 million related to its Senior Notes which has been reflected on the Company's balance sheet within the line item Senior Notes, net of unamortized debt issuance costs. Debt issuance costs include origination, legal, engineering and other fees incurred in connection with the Company’s credit facility and Senior Notes. For the three months ended March 31, 2017 and 2016, the Company recorded amortization expense related to debt issuance costs of $0.9 million and $0.9 million, respectively.

 

Debt Discount Costs on Second Lien Notes

 

For the three months ended March 31, 2016, the Company recorded amortization expense related to the debt discount on its Second Lien Notes of $0.3 million. The Company recorded no amortization expense related to the debt discount on its Second Lien Notes for the three months ended March 31, 2017. For additional information regarding debt discount costs on Second Lien Notes, see the Company’s Annual Report.

 

Interest Incurred on Long‑Term Debt

 

For the three months ended March 31, 2017 and 2016, the Company incurred interest expense on long‑term debt of $11.3 million and $13.3 million, respectively. For the three months ended March 31, 2017 and 2016, the Company capitalized interest expense on long term debt of $2.5 million and $0.9 million, respectively, which has been reflected in the Company’s financial statements.

 

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.

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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 six 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.

 

The Company’s commodity derivative contracts as of March 31, 2017 are summarized below:

 

 

 

 

 

 

 

 

 

 

    

2017

    

2018

 

NYMEX WTI(1) Crude Swaps:

 

 

 

 

 

 

 

Notional volume (Bbl)

 

 

450,000

 

 

 —

 

Weighted average fixed price ($/Bbl)

 

$

45.56

 

$

 —

 

NYMEX WTI(1) Crude Sold Calls:

 

 

 

 

 

 

 

Notional volume (Bbl)

 

 

5,800,000

 

 

3,700,000

 

Weighted average sold call price ($/Bbl)

 

$

55.93

 

$

62.36

 

NYMEX WTI(1) Crude Sold Puts:

 

 

 

 

 

 

 

Notional volume (Bbl)

 

 

5,425,000

 

 

3,300,000

 

Weighted average sold put price ($/Bbl)

 

$

38.02

 

$

40.18

 

NYMEX WTI(1) Crude Purchased Puts:

 

 

 

 

 

 

 

Notional volume (Bbl)

 

 

5,800,000

 

 

3,600,000

 

Weighted average purchased put price ($/Bbl)

 

$

47.61

 

$

50.33

 

NYMEX HH(2) Natural Gas Swaps:

 

 

 

 

 

 

 

Notional volume (MMBtu)

 

 

20,430,000

 

 

14,400,000

 

Weighted average fixed price ($/MMBtu)

 

$

3.06

 

$

3.11

 

NYMEX HH(2) Natural Gas Purchased Puts:

 

 

 

 

 

 

 

Notional volume (MMBtu)

 

 

 —

 

 

2,400,000

 

Weighted average purchased put price ($/MMBtu)

 

 

 

 

$

3.00

 

NYMEX HH(2) Natural Gas Sold Calls:

 

 

 

 

 

 

 

Notional volume (MMBtu)

 

 

 —

 

 

2,400,000

 

Weighted average sold call price ($/MMBtu)

 

 

 

 

$

3.15

 

CIG(3) Basis Gas Swaps:

 

 

 

 

 

 

 

Notional volume (MMBtu)

 

 

10,090,000

 

 

2,250,000

 

Weighted average fixed basis price ($/MMBtu)

 

$

(0.35)

 

$

(0.29)

 


(1)

NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange

(2)

NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange

(3)

CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) Inside FERC settlement price.

 

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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 consolidated balance sheets (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of March 31, 2017

 

 

    

 

 

    

 

 

    

Net Amounts of

    

 

 

    

 

 

 

 

 

Gross Amounts

 

 

 

 

Assets and

 

 

 

 

 

 

 

 

of Recognized

 

Gross Amounts

 

Liabilities

 

Gross Amounts

 

 

 

 

 

 

Assets and

 

Offset in the

 

Presented in the

 

not Offset in the

 

Net

 

Location on Balance Sheet

    

Liabilities

    

Balance Sheet(1)

    

Balance Sheet

    

Balance Sheet(2)

    

Amounts(3)

 

Current assets

 

$

17,776

 

$

(17,776)

 

$

 —

 

$

(4,951)

 

$

774

 

Non-current assets

 

$

16,205

 

$

(10,481)

 

$

5,724

 

$

 —

 

$

 —

 

Current liabilities

 

$

(26,778)

 

$

17,776

 

$

(9,002)

 

$

4,951

 

$

(4,052)

 

Non-current liabilities

 

$

(10,481)

 

$

10,481

 

$

 —

 

$

 —

 

$

 —