mcf_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 September 30, 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 001-16317 

 

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)

 

 

 

 

DELAWARE

 

95-4079863

 

 

 

(State or other jurisdiction of
incorporation or organization)

 

(IRS Employer
Identification No.)

 

 

 

717 TEXAS AVENUE, SUITE 2900

HOUSTON, TEXAS

 

77002

(Address of principal executive offices)

 

(Zip Code)

 

(713) 236-7400

(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 $0.04 per share, outstanding as of November 6, 2017 was 25,509,792.

 

 

 


 

Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017

 

TABLE OF CONTENTS

 

 

 

 

 

 

 

 

    

    

   

Page

 

PART I—FINANCIAL INFORMATION 

 

 

 

 

 

 

Item 1. 

 

Consolidated Financial Statements

 

 

 

 

 

Consolidated Balance Sheets (unaudited) as of September 30, 2017 and December 31, 2016

 

3

 

 

 

Consolidated Statements of Operations (unaudited) for the three and nine months ended September 30, 2017 and 2016

 

4

 

 

 

Consolidated Statements of Cash Flows (unaudited) for the nine months ended September 30, 2017 and 2016

 

5

 

 

 

Consolidated Statement of Shareholders’ Equity (unaudited) for the nine months ended September 30, 2017

 

6

 

 

 

Notes to the Unaudited Consolidated Financial Statements (unaudited)

 

7

 

Item 2. 

 

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

 

23

 

Item 3. 

 

Quantitative and Qualitative Disclosures about Market Risk

 

32

 

Item 4. 

 

Controls and Procedures

 

33

 

 

 

 

 

 

 

PART II—OTHER INFORMATION 

 

 

 

 

 

 

 

Item 1. 

 

Legal Proceedings

 

33

 

Item 1A. 

 

Risk Factors

 

33

 

Item 2. 

 

Unregistered Sales of Equity Securities and Use of Proceeds

 

34

 

Item 3. 

 

Defaults upon Senior Securities

 

34

 

Item 4. 

 

Mine Safety Disclosures

 

34

 

Item 5. 

 

Other Information

 

34

 

Item 6. 

 

Exhibits

 

34

 

 

All references in this Quarterly Report on Form 10-Q to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and its subsidiaries.

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Table of Contents

Item 1. Consolidated Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except shares)

 

 

 

 

 

 

 

 

 

 

 

September 30, 

 

December 31, 

 

 

    

2017

    

2016

  

 

 

 

 

 

 

(unaudited)

 

CURRENT ASSETS:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

 —

 

$

 —

 

Accounts receivable, net

 

 

11,757

 

 

16,727

 

Prepaid expenses

 

 

1,786

 

 

1,787

 

Current derivative asset

 

 

440

 

 

 —

 

Inventory

 

 

 —

 

 

540

 

Total current assets

 

 

13,983

 

 

19,054

 

PROPERTY, PLANT AND EQUIPMENT:

 

 

 

 

 

 

 

Natural gas and oil properties, successful efforts method of accounting:

 

 

 

 

 

 

 

Proved properties

 

 

1,221,391

 

 

1,188,065

 

Unproved properties

 

 

38,720

 

 

38,338

 

Other property and equipment

 

 

1,272

 

 

1,265

 

Accumulated depreciation, depletion and amortization

 

 

(918,768)

 

 

(887,286)

 

Total property, plant and equipment, net

 

 

342,615

 

 

340,382

 

OTHER NON-CURRENT ASSETS:

 

 

 

 

 

 

 

Investments in affiliates

 

 

18,242

 

 

15,767

 

Other

 

 

954

 

 

1,311

 

Total other non-current assets

 

 

19,196

 

 

17,078

 

TOTAL ASSETS

 

$

375,794

 

$

376,514

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

45,401

 

$

55,135

 

Current derivative liability

 

 

90

 

 

3,446

 

Current asset retirement obligations

 

 

4,008

 

 

4,308

 

Total current liabilities

 

 

49,499

 

 

62,889

 

NON-CURRENT LIABILITIES:

 

 

 

 

 

 

 

Long-term debt

 

 

79,226

 

 

54,354

 

Asset retirement obligations

 

 

18,082

 

 

22,618

 

Other long term liabilities

 

 

248

 

 

248

 

Total non-current liabilities

 

 

97,556

 

 

77,220

 

Total liabilities

 

 

147,055

 

 

140,109

 

COMMITMENTS AND CONTINGENCIES (NOTE 12)

 

 

 

 

 

 

 

SHAREHOLDERS’ EQUITY:

 

 

 

 

 

 

 

Common stock, $0.04 par value, 50 million shares authorized, 30,887,073 shares issued and 25,544,705 shares outstanding at September 30, 2017, 30,557,987 shares issued and 25,238,600 shares outstanding at December 31, 2016

 

 

1,224

 

 

1,211

 

Additional paid-in capital

 

 

300,986

 

 

296,439

 

Treasury shares at cost (5,342,368 shares at September 30, 2017 and 5,319,387 shares at December 31, 2016)

 

 

(128,482)

 

 

(128,321)

 

Retained earnings

 

 

55,011

 

 

67,076

 

Total shareholders’ equity

 

 

228,739

 

 

236,405

 

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

 

$

375,794

 

$

376,514

 

 

The accompanying notes are an integral part of these consolidated financial statements 

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30, 

 

September 30, 

 

 

    

2017

    

2016

 

2017

    

2016

 

 

 

(unaudited)

 

(unaudited)

 

REVENUES:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate sales

 

$

6,109

 

$

4,946

 

$

18,134

 

$

17,164

 

Natural gas sales

 

 

9,681

 

 

12,011

 

 

31,956

 

 

31,283

 

Natural gas liquids sales

 

 

3,040

 

 

2,619

 

 

8,440

 

 

8,073

 

Total revenues

 

 

18,830

 

 

19,576

 

 

58,530

 

 

56,520

 

EXPENSES:

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

7,041

 

 

8,158

 

 

20,203

 

 

22,782

 

Exploration expenses

 

 

315

 

 

444

 

 

690

 

 

1,088

 

Depreciation, depletion and amortization

 

 

11,193

 

 

15,166

 

 

35,678

 

 

49,586

 

Impairment and abandonment of oil and gas properties

 

 

84

 

 

1,165

 

 

1,515

 

 

4,268

 

General and administrative expenses

 

 

6,219

 

 

7,486

 

 

18,648

 

 

18,772

 

Total expenses

 

 

24,852

 

 

32,419

 

 

76,734

 

 

96,496

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

 

 

 

 

 

Gain from investment in affiliates, net of income taxes

 

 

525

 

 

467

 

 

2,475

 

 

1,802

 

Gain (loss) from sale of assets

 

 

(184)

 

 

11

 

 

2,336

 

 

11

 

Interest expense

 

 

(1,138)

 

 

(989)

 

 

(2,822)

 

 

(3,045)

 

Gain (loss) on derivatives, net

 

 

(9)

 

 

913

 

 

4,574

 

 

736

 

Other income (expense)

 

 

 —

 

 

 7

 

 

(27)

 

 

(303)

 

Total other income (expense)

 

 

(806)

 

 

409

 

 

6,536

 

 

(799)

 

NET LOSS  BEFORE INCOME TAXES

 

 

(6,828)

 

 

(12,434)

 

 

(11,668)

 

 

(40,775)

 

Income tax provision

 

 

(88)

 

 

(51)

 

 

(397)

 

 

(410)

 

NET LOSS

 

$

(6,916)

 

$

(12,485)

 

$

(12,065)

 

$

(41,185)

 

NET LOSS PER SHARE:

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.28)

 

$

(0.55)

 

$

(0.49)

 

$

(2.02)

 

Diluted

 

$

(0.28)

 

$

(0.55)

 

$

(0.49)

 

$

(2.02)

 

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

24,708

 

 

22,881

 

 

24,662

 

 

20,370

 

Diluted

 

 

24,708

 

 

22,881

 

 

24,662

 

 

20,370

 

 

The accompanying notes are an integral part of these consolidated financial statements 

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

 

 

September 30, 

 

 

    

2017

    

2016

 

 

 

 

 

 

 

 

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

Net loss

 

$

(12,065)

 

$

(41,185)

 

Adjustments to reconcile net loss to net cash provided by operating activities:

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

35,678

 

 

49,586

 

Impairment of natural gas and oil properties

 

 

1,400

 

 

4,137

 

Exploration recovery

 

 

(232)

 

 

(2)

 

Gain on sale of assets

 

 

(2,336)

 

 

(11)

 

Gain from investment in affiliates

 

 

(2,475)

 

 

(1,802)

 

Stock-based compensation

 

 

4,560

 

 

4,315

 

Unrealized loss (gain) on derivative instruments

 

 

(3,797)

 

 

2,400

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Decrease in accounts receivable & other receivables

 

 

4,767

 

 

7,026

 

Decrease (increase) in prepaids

 

 

 1

 

 

(282)

 

Decrease in inventory

 

 

123

 

 

 —

 

Decrease in accounts payable & advances from joint owners

 

 

(1,744)

 

 

(5,621)

 

Increase in other accrued liabilities

 

 

2,461

 

 

2,384

 

Decrease in income taxes receivable, net

 

 

 —

 

 

2,868

 

Decrease in income taxes payable, net

 

 

(308)

 

 

(200)

 

Other

 

 

72

 

 

(17)

 

Net cash provided by operating activities

 

$

26,105

 

$

23,596

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

Natural gas and oil exploration and development expenditures

 

$

(51,937)

 

$

(19,849)

 

Additions to furniture & equipment

 

 

(42)

 

 

 —

 

Sale of furniture & equipment

 

 

12

 

 

11

 

Sale of oil & gas properties

 

 

1,151

 

 

 —

 

Net cash used in investing activities

 

$

(50,816)

 

$

(19,838)

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Borrowings under credit facility

 

$

172,015

 

$

118,310

 

Repayments under credit facility

 

 

(147,143)

 

 

(171,293)

 

Net proceeds from equity offering

 

 

 —

 

 

50,451

 

Purchase of treasury stock

 

 

(161)

 

 

(230)

 

Debt issuance costs

 

 

 —

 

 

(996)

 

Net cash provided by (used in) financing activities

 

$

24,711

 

$

(3,758)

 

NET CHANGE IN CASH AND CASH EQUIVALENTS

 

$

 —

 

$

 —

 

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

 

 

 —

 

 

 —

 

CASH AND CASH EQUIVALENTS, END OF PERIOD

 

$

 —

 

$

 —

 

 

The accompanying notes are an integral part of these consolidated financial statements 

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(in thousands, except number of shares)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Additional

 

 

 

 

 

 

 

Total

 

 

 

Common Stock

 

Paid-in

 

Treasury

 

Retained

 

Shareholders’

 

 

    

Shares

    

Amount

    

Capital

    

Stock

    

Earnings

    

Equity

 

 

 

(unaudited)

 

Balance at December 31, 2016

 

25,238,600

 

$

1,211

 

$

296,439

 

$

(128,321)

 

$

67,076

 

$

236,405

 

Treasury shares at cost

 

(22,981)

 

 

 —

 

 

 —

 

 

(161)

 

 

 —

 

 

(161)

 

Restricted shares activity

 

329,086

 

 

13

 

 

(13)

 

 

 —

 

 

 —

 

 

 —

 

Stock-based compensation

 

 —

 

 

 —

 

 

4,560

 

 

 —

 

 

 —

 

 

4,560

 

Net income

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

(12,065)

 

 

(12,065)

 

Balance at September 30, 2017

 

25,544,705

 

$

1,224

 

$

300,986

 

$

(128,482)

 

$

55,011

 

$

228,739

 

 

The accompanying notes are an integral part of these consolidated financial statements 

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1. Organization and Business

 

Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Houston, Texas based, independent oil and natural gas company. The Company’s business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties in Texas and Wyoming and to use that cash flow to explore, develop, exploit, produce and acquire crude oil and natural gas properties in the Texas and Rocky Mountain regions of the United States.

 

The following table lists the Company’s primary producing areas as of September 30, 2017:

 

Location

    

Formation

Gulf of Mexico

 

Offshore Louisiana - water depths less than 300 feet

Madison and Grimes counties, Texas

 

Woodbine (Upper Lewisville)

Pecos County, Texas

 

Southern Delaware Basin (Wolfcamp)

Texas Gulf Coast

 

Conventional and unconventional formations

Zavala and Dimmit counties, Texas

 

Buda / Austin Chalk

Weston County, Wyoming

 

Muddy Sandstone

Sublette County, Wyoming

 

Jonah Field (1)


(1)

Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production associated with this investment is not included in the Company’s reported production results for the three and nine months ended September 30, 2017.

 

In July 2016, the Company purchased approximately 12,100 gross operated undeveloped acres (5,000 net acres) in the Southern Delaware Basin in Pecos County, Texas, which it began drilling during the fourth quarter of 2016, and as of September 30, 2017, had increased its acreage to approximately 13,600 gross operated acres (6,800 net).

 

The Company’s 2017 capital program has focused, and will continue to focus, on the development of the Company’s Southern Delaware Basin acreage. Additionally, the Company will continue to identify opportunities for cost efficiencies in all areas of its operations, maintain core leases and identify new resource potential opportunities internally and, where appropriate, through acquisition. The Company will continuously monitor the commodity price environment, including its stability and forecast, and, if warranted, make adjustments to its strategy as the year progresses.

 

2. Summary of Significant Accounting Policies

 

The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2016 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material items included in those notes have changed except as a result of normal transactions in the interim or as disclosed within this report.

 

Basis of Presentation

 

The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the 2016 Form 10-K. The consolidated results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017.

 

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The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The investment in Exaro by our wholly owned subsidiary, Contaro Company (“Contaro”) is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results, reserves or production in those reported for the Company’s consolidated results.

Oil and Gas Properties - Successful Efforts

Our application of the successful efforts method of accounting for our natural gas and oil exploration and production activities requires judgments as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

 

Impairment of Long-Lived Assets

 

Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. The Company recognized no impairment of proved properties for the three and nine months ended September 30, 2017. No impairment of proved properties was recognized for the three months ended September 30, 2016, and the Company recognized approximately $0.7 million impairment of proved properties for the nine months ended September 30, 2016, substantially all of which was directly related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated reserves.

 

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The Company recognized no impairment of unproved properties for the three months ended September 30, 2017 and $1.4 million in impairment expense related to the partial impairment of two unused offshore platforms for the nine months ended September 30, 2017. The Company recognized impairment expense of approximately $1.1 million and approximately $3.4 million for the three and nine months ended September 30, 2016, respectively, related to partial impairment of certain unproved properties due primarily to the sustained low commodity price environment and expiring leases, substantially all of which was related to unproved lease cost amortization of marginal, non-core properties in Fayette and Gonzales counties, Texas.

 

Net Loss Per Common Share 

 

Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, Performance Stock Units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the three months ended September 30, 2017, the Company excluded 971,813 potentially dilutive securities, as they were antidilutive, and excluded 813,151 potentially dilutive securities for the nine months ended September 30, 2017, as they were antidilutive.

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For the three months ended September 30, 2016, the Company excluded 439,017 potentially dilutive securities, as they were antidilutive, and 382,867 potentially dilutive securities were excluded for the nine months ended September 30, 2016, as they were antidilutive.

 

Subsidiary Guarantees

 

Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a full and unconditional basis by each of the Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the Subsidiary Guarantors is wholly owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly owned subsidiary that is inactive and not a Subsidiary Guarantor. Finally, the Parent Company’s wholly owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party.

 

 

 

Recent Accounting Pronouncements   

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-01: Business Combinations (Topic 805) Clarifying the Definition of a Business (ASU 2017-01). The amendments in this update are intended to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation.  Public business entities should apply the amendments in this update to annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments in this update should be applied prospectively on or after the effective date. No disclosures are required at transition. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations.

In August 2016, the FASB issued ASU No. 2016-15: Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. The main objective of this update is to reduce the diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. This update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The eight cash flow updates relate to the following issues: 1) debt prepayment or debt extinguishment costs; 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; 3) contingent consideration payments made after a business combination; 4) proceeds from the settlement of insurance claims; 5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; 6) distributions received from equity method investees; 7) beneficial interest in securitization transactions; and 8) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The provisions of this accounting update are not expected to have a material impact on the Company’s presentation of cash flows.

In February 2016, the FASB issued ASU No. 2016-02: Leases (Topic 842) (ASU 2016-02). The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company will continue to assess the impact this may have on its financial position, results of operations, and cash flows.

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In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. Several additional standards related to revenue recognition have been issued that amend the original standard, with most providing additional clarification.

In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. The Company has completed its initial review of all revenue contracts. The Company’s revenue contracts are normal purchase/sale contracts and as such, the Company does not expect that the new revenue recognition standard will have a material impact on the Company’s financial statements upon adoption.  The Company expects to use the modified retrospective method to adopt the standard, meaning the cumulative effect of initially applying the standard will be recognized at the date of the adoption of the standard.

3. Acquisitions and Dispositions

 

In July 2016, the Company purchased one-half of the seller’s interest in approximately 12,100 gross undeveloped acres (approximately 5,000 net acres) in the Southern Delaware Basin of Texas for up to $25 million (the “Acquisition”). The purchase price was comprised of $10 million in cash paid on July 26, 2016, plus $10 million to be paid in the form of carried well costs expected to be paid over the period of drilling and completion of the first six wells. Additionally, contingent upon success, $5 million in spud bonuses is to be paid by the Company ratably over the following 14 wells drilled, which would increase the total consideration paid by the Company to $25 million. As of September 30, 2017, the Company had paid all $10 million of the carried well costs and $0.7 million in spud bonuses. As of September 30, 2017, the Company had increased its acreage to approximately 13,600 gross operated acres (6,800 net).

 

On December 30, 2016, all of the Company’s non-core Colorado assets were sold to an independent oil and gas company for an aggregate purchase price of $5.0 million, subject to normal post-closing adjustments. The properties consisted of the Company’s approximately 16,000 gross (11,200 net) acres primarily in Adams and Weld counties, Colorado and associated producing vertical wells.

 

Effective February 1, 2017, the Company sold to a third party all of its assets in the North Bob West area and its operated assets in the Escobas area, both located in Southeast Texas, for a cash purchase price of $650,000. The Company recorded a net gain of $2.9 million after removal of the asset retirement obligations associated with the sold properties.

 

4. Fair Value Measurements

 

Pursuant to Accounting Standards Codification 820, Fair Value Measurements and Disclosures (ASC 820), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

 

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The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of September 30, 2017. As required by ASC 820, a financial instrument's level within the fair value hierarchy is 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 fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3.

 

Fair value information for financial assets and liabilities was as follows as of September 30, 2017 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

Fair Value Measurements Using

 

 

    

Carrying Value

    

Level 1

    

Level 2

    

Level 3

 

Derivatives

 

 

 

 

 

 

 

 

 

Commodity price contracts - assets

 

$

440

 

$

 —

 

$

440

 

$

 —

 

Commodity price contracts - liabilities

 

$

(90)

 

$

 —

 

$

(90)

 

$

 —

 

 

Derivatives listed above are recorded in “Current derivative asset or liability” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The Company records the net change in the fair value of these positions in "Gain (loss) on derivatives, net" in the Company's consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted markets prices and implied volatility factors related to changes in the forward curves. See Note 5 - "Derivative Instruments" for additional discussion of derivatives.

 

As of September 30, 2017, the Company's derivative contracts were with certain members of its credit facility lenders which are major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance.

 

Estimates of the fair value of financial instruments are made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's credit facility with the Royal Bank of Canada and other lenders (the “RBC Credit Facility”) approximates carrying value because the facility interest rate approximates current market rates and is reset at least every six months. See Note 9 - "Long-Term Debt" for further information.

 

Impairments

 

Contango tests proved oil and natural gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gas properties on a field by field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure.

 

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period.

 

Asset Retirement Obligations

 

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. The factors

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used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3.

 

5. Derivative Instruments

 

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are typically utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions and commodity price forecasts.

 

As of September 30, 2017, the Company’s natural gas and oil derivative positions consisted of “swaps” and “costless collars”.  Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a purchased put option and a sold call option, which establishes a minimum and maximum price, respectively, that the Company will receive for the volumes under the contract.

 

It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company does not post collateral, nor is it exposed to potential margin calls, under any of these contracts as they are secured under the RBC Credit Facility. See Note 9 - "Long-Term Debt" for further information regarding the RBC Credit Facility.

 

The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in "Gain (loss) on derivatives, net" on the consolidated statements of operations.

 

The following derivative instruments were in place at September 30, 2017 (fair value in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

    

Period

    

Derivative

    

Volume/Month

    

Price/Unit (1)

    

Fair Value

 

Natural Gas

 

Oct 2017

 

Collar

 

200,000 MMBtu

 

$

2.65 - 3.00

 

 

0

 

Natural Gas

 

Nov 2017 - Dec 2017

 

Collar

 

400,000 MMBtu

 

$

2.65 - 3.00

 

 

(90)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

Oct 2017

 

Swap

 

70,000 MMBtu

 

$

3.51

 

 

37

 

Natural Gas

 

Nov 2017 - Dec 2017

 

Swap

 

300,000 MMBtu

 

$

3.51

 

 

246

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Oct 2017

 

Swap

 

6,000 Bbls

 

$

53.95

 

 

13

 

Oil

 

Nov 2017 - Dec 2017

 

Swap

 

8,000 Bbls

 

$

53.95

 

 

30

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Oct 2017 - Dec 2017

 

Swap

 

9,000 Bbls

 

$

56.20

 

 

114

 

 

 

 

 

Total net fair value of derivative instruments

 

$

350

 


(1)   Commodity price derivatives are based on Henry Hub NYMEX natural gas prices and West Texas Intermediate oil prices, as applicable.

 

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The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of September 30, 2017 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

    

Gross

    

Netting (1)

    

Total

 

Assets

 

$

440

 

$

 —

 

$

440

 

Liabilities

 

$

(90)

 

$

 —

 

$

(90)

 


(1)   Represents counterparty netting under agreements governing such derivatives.

 

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2016 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

    

Gross

    

Netting (1)

    

Total

 

Assets

 

$

 —

 

$

 —

 

$

 —

 

Liabilities

 

$

(3,446)

 

$

 —

 

$

(3,446)

 


(1)   Represents counterparty netting under agreements governing such derivatives.

 

 

The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30, 

 

Nine Months Ended September 30, 

 

 

    

2017

    

2016

    

2017

    

2016

 

Crude oil contracts

 

$

342

 

$

 —

 

$

879

 

$

 —

 

Natural gas contracts

 

 

179

 

 

(619)

 

 

(102)

 

 

3,136

 

Realized gain (loss)

 

$

521

 

$

(619)

 

$

777

 

$

3,136

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil contracts

 

$

(661)

 

$

 —

 

$

156

 

$

 —

 

Natural gas contracts

 

 

131

 

 

1,532

 

 

3,641

 

 

(2,400)

 

Unrealized gain (loss)

 

$

(530)

 

$

1,532

 

$

3,797

 

$

(2,400)

 

Gain (loss) on derivatives, net

 

$

(9)

 

$

913

 

$

4,574

 

$

736

 

 

 

 

 

 

In October 2017, the Company entered into the following additional financial derivative contracts with a member of its credit facility lenders:

 

 

 

 

 

 

 

 

 

 

 

Commodity

    

Period

    

Derivative

    

Volume/Month

    

Price/Unit (1)

Natural Gas

 

Jan 2018 - July 2018

 

Swap

 

370,000 MMBtu

 

$

3.07

Natural Gas

 

Aug 2018 - Oct 2018

 

Swap

 

70,000 MMBtu

 

$

3.07

Natural Gas

 

Nov 2018 - Dec 2018

 

Swap

 

320,000 MMBtu

 

$

3.07

 

 

 

 

 

 

 

 

 

 

Oil

 

Jan 2018 - June 2018

 

Swap

 

20,000 Bbls

 

$

56.40

Oil

 

July 2018 - Oct 2018

 

Collar

 

20,000 Bbls

 

$

52.00 - 56.85

Oil

 

Nov 2018 - Dec 2018

 

Collar

 

15,000 Bbls

 

$

52.00 - 56.85

 

 

 

 

 

 

 

 

 

 

Oil

 

Jan 2019 - Dec 2019

 

Collar

 

7,000 Bbls

 

$

50.00 - 58.00


(1)   Commodity price derivatives are based on Henry Hub NYMEX natural gas prices and Argus Louisiana Light Sweet oil prices, as applicable.  

 

 

6. Stock-Based Compensation

 

The Company recognized approximately $4.6 million and $4.3 million in stock compensation expense during the nine months ended September 30, 2017 and 2016, respectively, for equity awards granted to its officers, employees and directors. As of September 30, 2017, an additional $6.2 million of compensation expense remained to be recognized over the remaining weighted-average vesting period of 2.1 years. This includes expense related to restricted stock, Performance Stock Units (“PSUs”) and stock options.

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Restricted Stock 

 

During the nine months ended September 30, 2017, the Company granted 383,376 shares of restricted common stock, which vest over three years, to new and existing employees as part of their overall compensation package, and 74,325 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average intrinsic value of the restricted shares granted during the nine months ended September 30, 2017, was $7.55 with a total fair value of approximately $3.5 million after adjustment for an estimated weighted average forfeiture rate of 5.7%. During the nine months ended September 30, 2017, 128,615 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2017 was approximately $1.3 million. Approximately 1.6 million shares remained available for grant under the Amended and Restated 2009 Incentive Compensation Plan as of September 30, 2017, assuming PSUs are settled at 100% of target.

 

During the nine months ended September 30, 2016, the Company granted 40,876 immediately vested shares of restricted common stock. Of these, 38,943 shares were granted to employees and 1,933 shares were granted to directors, all of which were issued pursuant to the Company’s salary replacement program (the “Salary Replacement Program”) which temporarily deferred 10% of 2015 employee salaries and director fees. Additionally, the Company granted 197,306 shares of restricted common stock to employees as part of their overall compensation package, which vest over four years, and 49,460 shares of restricted common stock to directors pursuant to the Company’s Director Compensation Plan, which vest over one year. The weighted average fair value of the restricted shares granted during the nine months ended September 30, 2016, was $11.60 with a total fair value of approximately $3.3 million after adjustment for an estimated weighted average forfeiture rate of 3.5%. During the nine months ended September 30, 2016, 4,160 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2016 was approximately $130 thousand.

 

Performance Stock Units

 

During the nine months ended September 30, 2017, the Company granted  30,000 PSUs to a new employee, at a weighted average fair value of $8.32 per unit and 160,908 PSUs to executive officers, as part of their overall compensation package, at a value of $13.91 per unit. All prices were determined using the Monte Carlo simulation model. During the nine months ended September 30, 2017, 94,063 PSUs were forfeited by former employees. No PSUs were issued or forfeited during the nine months ended September 30, 2016. PSUs represent the opportunity to receive shares of the Company's common stock at the time of settlement. The number of shares to be awarded upon settlement of these PSUs may range from 0% to 300% of the number of PSUs awarded contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PSUs vest and settlement is determined after a three year period.

 

Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determined using the Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As it is contemplated that the PSUs will be settled with shares of the Company's common stock after three years, the PSU awards are accounted for as equity awards and the fair value is calculated on the grant date. The simulation model calculates the payout percentage based on the stock price performance over the performance period. The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair value expense is amortized over the life of the PSU award.

 

Stock Options

 

Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the nine months ended September 30, 2017 and 2016, there was no excess tax benefit recognized.

 

Compensation expense related to stock option grants are recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. No stock options were granted during the nine months ended September 30, 2017 or 2016.

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During the nine months ended September 30, 2017, no stock options were exercised, while 17,072 stock options were forfeited by former employees. During the nine months ended September 30, 2016, no stock options were exercised and stock options for 1,657 shares of common stock were forfeited.

 

7. Other Financial Information

 

The following table provides additional detail for accounts receivable, prepaid expenses and other, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands):

 

 

 

 

 

 

 

 

 

 

    

September 30, 2017

    

December 31, 2016

 

Accounts receivable:

 

 

 

 

 

 

 

Trade receivables

 

$

7,262

 

$

8,424

 

Receivable for Alta Resources Distribution

 

 

1,993

 

 

1,993

 

Joint interest billings

 

 

2,972

 

 

3,519

 

Income taxes receivable

 

 

92

 

 

91

 

Other receivables

 

 

335

 

 

3,395

 

Allowance for doubtful accounts

 

 

(897)

 

 

(695)

 

Total accounts receivable

 

$

11,757

 

$

16,727

 

 

 

 

 

 

 

 

 

Prepaid expenses and other:

 

 

 

 

 

 

 

Prepaid insurance

 

$

1,088

 

$

1,086

 

Other

 

 

698

 

 

701

 

Total prepaid expenses and other

 

$

1,786

 

$

1,787

 

 

 

 

 

 

 

 

 

Accounts payable and accrued liabilities:

 

 

 

 

 

 

 

Royalties and revenue payable

 

$

19,343

 

$

16,920

 

Advances from partners

 

 

3,230

 

 

5,792

 

Accrued exploration and development

 

 

8,189

 

 

11,176

 

Accrued carried well costs

 

 

 —

 

 

7,155

 

Trade payables

 

 

5,433

 

 

5,406

 

Accrued LOE & workover expense

 

 

2,228

 

 

1,867

 

Accrued G&A and legal expense

 

 

3,997

 

 

5,016

 

Other accounts payable and accrued liabilities

 

 

2,981

 

 

1,803

 

Total accounts payable and accrued liabilities

 

$

45,401

 

$

55,135

 

 

Included in the table below is supplemental information about certain cash and non-cash transactions during the nine months ended September 30, 2017 and 2016 (in thousands):

 

 

 

 

 

 

 

 

 

 

Nine Months Ended September 30, 

 

 

 

2017

    

 

2016

 

Cash payments:

 

 

 

 

 

 

Interest payments

$

2,501

 

$

2,935

 

Income tax payments (refunds)

$

708

 

$

(2,337)

 

Non-cash investing activities in the consolidated statements of cash flows:

 

 

 

 

 

 

Increase (decrease) in accrued capital expenditures

$

(10,142)

 

$

7,248

 

 

 

8. Investment in Exaro Energy III LLC

 

The Company maintains an ownership interest in Exaro of approximately 37%.  

 

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The following table (in thousands) presents condensed balance sheet data for Exaro as of September 30, 2017 and December 31, 2016. The balance sheet data was derived from Exaro’s balance sheet as of September 30, 2017 and December 31, 2016 and was not adjusted to represent the Company’s percentage of ownership interest in Exaro. The Company’s share in the equity of Exaro at September 30, 2017 was approximately $18.1 million.

 

 

 

 

 

 

 

 

 

 

    

September 30, 2017

    

December 31, 2016

 

Current assets (1)

 

$

15,897

 

$

25,296

 

Non-current assets:

 

 

 

 

 

 

 

Net property and equipment

 

 

84,766

 

 

90,621

 

Gas processing deposit

 

 

1,150

 

 

1,150

 

Other non-current assets

 

 

57

 

 

 8

 

Total non-current assets

 

 

85,973

 

 

91,779

 

Total assets

 

$

101,870

 

$

117,075

 

 

 

 

 

 

 

 

 

Current liabilities (2)

 

$

3,950

 

$

65,694

 

Non-current liabilities:

 

 

 

 

 

 

 

Long-term debt

 

 

44,356

 

 

 —

 

Other non-current liabilities

 

 

3,466

 

 

8,106

 

Total non-current liabilities

 

 

47,822

 

 

8,106

 

Members' equity

 

 

50,098

 

 

43,275

 

Total liabilities & members' equity

 

$

101,870

 

$

117,075

 


(1)

Approximately $13.6 million and $19.6 million of current assets as of September 30, 2017 and December 31, 2016, respectively, is cash.

(2)

Approximately $59.3 million of current liabilities as of December 31, 2016, was attributable to Exaro’s senior loan facility maturing in 2017, which has since been refinanced.

 

 

The following table (in thousands) presents the condensed results of operations for Exaro for the three and nine months ended September 30, 2017 and 2016. The results of operations for the three and nine months ended September 30, 2017 and 2016 were derived from Exaro's financial statements for the respective periods. The income statement data below was not adjusted to represent the Company’s ownership interest but rather reflects the results of Exaro as a company. The Company’s share in Exaro’s results of operations recognized for the three months ended September 30, 2017 and 2016 was a gain of $0.5 million, net of no tax expense.  The Company’s share in Exaro’s results of operations recognized for the nine months ended September 30, 2017 and 2016 was a gain of $2.5 million, net of no tax expense, and a gain of $1.8 million, net of no tax expense, respectively.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30, 

 

Nine Months Ended September 30, 

 

 

    

2017

    

2016

    

2017

    

2016

 

Production:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (thousand barrels)