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, 2018 

OR

 

 

 

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

 

For the transition period from              to             

Commission file number 001-16317 

 

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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    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 5, 2018 was 25,583,398.

 

 

 


 

Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018

 

TABLE OF CONTENTS

 

 

 

 

 

 

 

 

    

    

   

Page

 

PART I—FINANCIAL INFORMATION 

 

 

 

 

 

 

Item 1. 

 

Consolidated Financial Statements

 

 

 

 

 

Consolidated Balance Sheets (unaudited) as of September 30, 2018 and December 31, 2017

 

3

 

 

 

Consolidated Statements of Operations (unaudited) for the three and nine months ended September 30, 2018 and 2017

 

4

 

 

 

Consolidated Statements of Cash Flows (unaudited) for the nine months ended September 30, 2018 and 2017

 

5

 

 

 

Consolidated Statement of Shareholders’ Equity (unaudited) for the nine months ended September 30, 2018

 

6

 

 

 

Notes to the Consolidated Financial Statements (unaudited)

 

7

 

Item 2. 

 

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

 

25

 

Item 3. 

 

Quantitative and Qualitative Disclosures about Market Risk

 

36

 

Item 4. 

 

Controls and Procedures

 

37

 

 

 

 

 

 

 

PART II—OTHER INFORMATION 

 

 

 

 

 

 

 

Item 1. 

 

Legal Proceedings

 

37

 

Item 1A. 

 

Risk Factors

 

38

 

Item 2. 

 

Unregistered Sales of Equity Securities and Use of Proceeds

 

39

 

Item 3. 

 

Defaults upon Senior Securities

 

39

 

Item 4. 

 

Mine Safety Disclosures

 

39

 

Item 5. 

 

Other Information

 

39

 

Item 6. 

 

Exhibits

 

41

 

 

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, 

 

 

    

2018

    

2017

  

 

 

 

 

 

 

(unaudited)

 

CURRENT ASSETS:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

 —

 

$

 —

 

Accounts receivable, net

 

 

10,957

 

 

13,059

 

Prepaid expenses

 

 

1,191

 

 

1,892

 

Current derivative asset

 

 

43

 

 

822

 

Held for sale (see Note 3)

 

 

1,748

 

 

 —

 

Total current assets

 

 

13,939

 

 

15,773

 

PROPERTY, PLANT AND EQUIPMENT:

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

Proved properties

 

 

1,156,557

 

 

1,239,662

 

Unproved properties

 

 

34,295

 

 

35,243

 

Held for sale (see Note 3)

 

 

8,248

 

 

 —

 

Other property and equipment

 

 

1,272

 

 

1,272

 

Accumulated depreciation, depletion and amortization

 

 

(929,416)

 

 

(930,220)

 

Total property, plant and equipment, net

 

 

270,956

 

 

345,957

 

OTHER NON-CURRENT ASSETS:

 

 

 

 

 

 

 

Investments in affiliates

 

 

18,426

 

 

18,464

 

Long-term derivative asset

 

 

39

 

 

 —

 

Deferred tax asset

 

 

424

 

 

424

 

Other

 

 

477

 

 

835

 

Total other non-current assets

 

 

19,366

 

 

19,723

 

TOTAL ASSETS

 

$

304,261

 

$

381,453

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

52,899

 

$

46,755

 

Current derivative liability

 

 

3,118

 

 

1,765

 

Current asset retirement obligations

 

 

747

 

 

2,017

 

Held for sale (see Note 3)

 

 

1,440

 

 

 —

 

Total current liabilities

 

 

58,204

 

 

50,537

 

NON-CURRENT LIABILITIES:

 

 

 

 

 

 

 

Long-term debt

 

 

81,771

 

 

85,380

 

Long-term derivative liability

 

 

759

 

 

300

 

Asset retirement obligations

 

 

17,837

 

 

20,388

 

Other long term liabilities

 

 

3,298

 

 

248

 

Held for sale (see Note 3)

 

 

2,155

 

 

 —

 

Total non-current liabilities

 

 

105,820

 

 

106,316

 

Total liabilities

 

 

164,024

 

 

156,853

 

COMMITMENTS AND CONTINGENCIES (NOTE 11)

 

 

 

 

 

 

 

SHAREHOLDERS’ EQUITY:

 

 

 

 

 

 

 

Common stock, $0.04 par value, 50 million shares authorized, 31,029,458 shares issued and 25,584,108 shares outstanding at September 30, 2018, 30,873,470 shares issued and 25,505,715 shares outstanding at December 31, 2017

 

 

1,229

 

 

1,223

 

Additional paid-in capital

 

 

306,293

 

 

302,527

 

Treasury shares at cost (5,445,350 shares at September 30, 2018 and 5,367,755 shares at December 31, 2017)

 

 

(128,953)

 

 

(128,583)

 

Retained earnings

 

 

(38,332)

 

 

49,433

 

Total shareholders’ equity

 

 

140,237

 

 

224,600

 

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

 

$

304,261

 

$

381,453

 

 

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, 

 

 

    

2018

    

2017

 

2018

    

2017

 

 

 

(unaudited)

 

(unaudited)

 

REVENUES:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate sales

 

$

8,558

 

$

6,109

 

$

26,976

 

$

18,134

 

Natural gas sales

 

 

7,128

 

 

9,681

 

 

21,585

 

 

31,956

 

Natural gas liquids sales

 

 

3,822

 

 

3,040

 

 

9,832

 

 

8,440

 

Total revenues

 

 

19,508

 

 

18,830

 

 

58,393

 

 

58,530

 

EXPENSES:

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

6,382

 

 

7,041

 

 

19,787

 

 

20,203

 

Exploration expenses

 

 

425

 

 

315

 

 

1,288

 

 

690

 

Depreciation, depletion and amortization

 

 

12,853

 

 

11,193

 

 

32,836

 

 

35,678

 

Impairment and abandonment of oil and gas properties

 

 

72,524

 

 

84

 

 

76,628

 

 

1,515

 

General and administrative expenses

 

 

6,724

 

 

6,219

 

 

18,804

 

 

18,648

 

Total expenses

 

 

98,908

 

 

24,852

 

 

149,343

 

 

76,734

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) from investment in affiliates, net of income taxes

 

 

(270)

 

 

525

 

 

(38)

 

 

2,475

 

Gain (loss) from sale of assets

 

 

498

 

 

(184)

 

 

11,315

 

 

2,336

 

Interest expense

 

 

(1,411)

 

 

(1,138)

 

 

(4,082)

 

 

(2,822)

 

Gain (loss) on derivatives, net

 

 

(1,319)

 

 

(9)

 

 

(4,961)

 

 

4,574

 

Other income (expense)

 

 

357

 

 

 —

 

 

1,239

 

 

(27)

 

Total other income (expense)

 

 

(2,145)

 

 

(806)

 

 

3,473

 

 

6,536

 

NET LOSS BEFORE INCOME TAXES

 

 

(81,545)

 

 

(6,828)

 

 

(87,477)

 

 

(11,668)

 

Income tax benefit (provision)

 

 

21

 

 

(88)

 

 

(288)

 

 

(397)

 

NET LOSS

 

$

(81,524)

 

$

(6,916)

 

$

(87,765)

 

$

(12,065)

 

NET LOSS PER SHARE:

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(3.26)

 

$

(0.28)

 

$

(3.52)

 

$

(0.49)

 

Diluted

 

$

(3.26)

 

$

(0.28)

 

$

(3.52)

 

$

(0.49)

 

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

25,001

 

 

24,708

 

 

24,910

 

 

24,662

 

Diluted

 

 

25,001

 

 

24,708

 

 

24,910

 

 

24,662

 

 

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, 

 

 

    

2018

    

2017

 

 

 

 

 

 

 

 

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

Net loss

 

$

(87,765)

 

$

(12,065)

 

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

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

32,836

 

 

35,678

 

Impairment of natural gas and oil properties

 

 

76,175

 

 

1,400

 

Exploration recovery

 

 

 —

 

 

(232)

 

Gain on sale of assets

 

 

(11,315)

 

 

(2,336)

 

Loss (gain) from investment in affiliates

 

 

38

 

 

(2,475)

 

Stock-based compensation

 

 

3,772

 

 

4,560

 

Unrealized loss (gain) on derivative instruments

 

 

2,551

 

 

(3,797)

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Decrease in accounts receivable & other receivables

 

 

355

 

 

4,767

 

Decrease in prepaids

 

 

702

 

 

 1

 

Decrease in inventory

 

 

 —

 

 

123

 

Increase (decrease) in accounts payable & advances from joint owners

 

 

3,571

 

 

(1,744)

 

Increase in other accrued liabilities

 

 

964

 

 

2,461

 

Increase (decrease) in income taxes payable, net

 

 

208

 

 

(308)

 

Other

 

 

3,051

 

 

72

 

Net cash provided by operating activities

 

$

25,143

 

$

26,105

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

Natural gas and oil exploration and development expenditures

 

$

(43,223)

 

$

(51,937)

 

Additions to furniture & equipment

 

 

 —

 

 

(42)

 

Sale of furniture & equipment

 

 

 —

 

 

12

 

Sale of oil & gas properties

 

 

21,562

 

 

1,151

 

Sale of energy credits

 

 

497

 

 

 —

 

Net cash used in investing activities

 

$

(21,164)

 

$

(50,816)

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Borrowings under credit facility

 

$

182,319

 

$

172,015

 

Repayments under credit facility

 

 

(185,928)

 

 

(147,143)

 

Purchase of treasury stock

 

 

(370)

 

 

(161)

 

Net cash provided by (used in) financing activities

 

$

(3,979)

 

$

24,711

 

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, 2017

 

25,505,715

 

$

1,223

 

$

302,527

 

$

(128,583)

 

$

49,433

 

$

224,600

 

Treasury shares at cost

 

(77,595)

 

 

 —

 

 

 —

 

 

(370)

 

 

 —

 

 

(370)

 

Restricted shares activity

 

155,988

 

 

 6

 

 

(6)

 

 

 —

 

 

 —

 

 

 —

 

Stock-based compensation

 

 —

 

 

 —

 

 

3,772

 

 

 —

 

 

 —

 

 

3,772

 

Net loss

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

(87,765)

 

 

(87,765)

 

Balance at September 30, 2018

 

25,584,108

 

$

1,229

 

$

306,293

 

$

(128,953)

 

$

(38,332)

 

$

140,237

 

 

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, increase production from and acquire crude oil and natural gas properties in West Texas, the onshore Texas Gulf Coast and the Rocky Mountain regions of the United States.

 

The following table lists the Company’s primary producing areas as of September 30, 2018:

 

Location

    

Formation

Gulf of Mexico

 

Offshore Louisiana - water depths less than 300 feet

Southern Delaware Basin, Pecos County, Texas

 

Wolfcamp

Madison and Grimes counties, Texas

 

Woodbine (Upper Lewisville)

Other Texas Gulf Coast

 

Conventional and smaller unconventional formations

Zavala and Dimmit counties, Texas

 

Buda / Eagle Ford

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 all periods shown in this report.

 

The Company’s 2018 capital program has focused on the development of its 15,500 gross (6,600 net) acres in the Southern Delaware Basin. Additionally, the Company will continue to identify opportunities for cost efficiencies in all areas of its operations, maintain core leases and continue to identify new resource potential opportunities internally and, where appropriate and assuming the Company has adequate capital to do so, through acquisition. Due to the increasing uncertainty surrounding the availability of takeaway capacity in the Permian Basin (the “Basin”), the resulting increase in negative oil and natural gas price differentials in the Basin, and pending the Company’s review of liquidity-enhancing options, the Company has decided to temporarily reduce its emphasis on developmental drilling and will instead concentrate on preserving its leased acreage position by addressing lease expirations through lease extensions and/or drilling, where necessary, and reducing outstanding debt through a reduction in general and administrative costs and non-core asset rationalization. The Company continuously monitors the commodity price environment, including its stability, forecast and geographic price differentials, and, if warranted, will make adjustments to its capital program as the year progresses. The Company also continues to evaluate new organic opportunities for growth and will continue to evaluate pursuing stressed or distressed acquisition opportunities that may arise in the current commodity price environment. Acquisition efforts will be focused on areas in which the Company can leverage its geological and operational experience and expertise to exploit identified drilling opportunities and where it can develop an inventory of additional drilling prospects that the Company believes will enable it to economically grow production and add reserves.

 

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, 2017 (the “2017 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2017 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

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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 2017 Form 10-K. These unaudited interim consolidated results of operations for the nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018.

 

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 the Company’s wholly owned subsidiary, Contaro Company, is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results or production in those reported for the Company’s consolidated results of operations.

 

Liquidity and Going Concern

 

Over the past few months, the Company has been in discussions with its current lenders and other sources of capital regarding a possible refinancing and/or replacement of its existing RBC Credit Facility, which matures on October 1, 2019. The refinancing or replacement of the RBC Credit Facility could be made in conjunction with an issuance of unsecured or non-priority secured debt or preferred or common equity, non-core property monetization, potential monetization of certain midstream and/or water handling facilities, etc. or a combination of the foregoing. These discussions have included a possible new, replacement or extended credit facility that would be expected to provide additional borrowing capacity for future capital expenditures. There is no assurance, however, that such discussions will result in a refinancing of the RBC Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures. Without any further extension of the RBC Credit Facility, it will be reflected as a current liability on the Company’s December 31, 2018 balance sheet, which may further limit its access to capital. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. However, the accompanying financial statements have been prepared assuming the Company will continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The accompanying financial statements do not include adjustments that might result from the outcome of the uncertainty, including any adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts or amounts and classifications of liabilities that might be necessary should the Company be unable to continue as a going concern. Management has concluded that their plans alleviate the substantial doubt about the Company’s ability to continue as a going concern.

 

Oil and Gas Properties - Successful Efforts

The Company’s application of the successful efforts method of accounting for its natural gas and oil exploration and production activities requires judgment 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

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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, probable and possible 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 $72.2 million and $74.9 million in non-cash proved property impairment charges for the three and nine months ended September 30, 2018, respectively. Included in proved property impairment expense for the three and nine months ended September 30, 2018 was a $59.4 million and a $61.7 million impairment, respectively, of the carrying costs of its Gulf of Mexico properties primarily due to revised proved reserve estimates made during the quarter ended September 30, 2018 as a result of new bottom hole pressure data gathered during the planned installation of a second stage compression in the Company’s Eugene Island 11 field. The revised reserve estimates, prepared by the Company’s third party engineers, resulted in the present value, discounted at a 10% rate (“PV-10”), of its offshore reserves being reduced to a total PV-10 of $97.2 million, a decrease of $9.8 million, thereby necessitating the requirement to reduce the carrying costs of the Gulf of Mexico properties. The three and nine months ended September 30, 2018 also included an onshore proved property impairment expense of $12.8 million and $13.2 million, respectively, of which $12.8 million impairment was related to the impairment of certain of its non-core properties in Southeast Texas that were reduced to their fair value as a result of a planned sale. See Note 3 – “Acquisitions and Dispositions” for further information regarding the sale of certain non-core properties in Southeast Texas. No impairment of proved properties was recognized during the three and nine months ended September 30, 2017.

 

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 impairment expense of approximately $0.1 million and approximately $1.3 million for the three and nine months ended September 30, 2018, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases. The Company recognized no impairment of unproved properties for the three months ended September 30, 2017 and $1.4 million in impairment expense for the nine months ended September 30, 2017 related to the partial impairment of two unused offshore platforms that were subsequently sold.

 

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 and nine months ended September 30, 2018, the Company excluded 561,502 and 777,725 shares or units of potentially dilutive securities, respectively, as they were antidilutive. For the three and nine months ended September 30, 2017, the Company excluded 931,666 and 908,394 shares or units of potentially dilutive securities, respectively, 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. 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.

 

 

 

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Revenue Recognition

 

Adoption of ASC 606

As of January 1, 2018 the Company adopted Accounting Standards Codification Topic 606 – Revenue from Contracts with Customers (“ASC 606”), which supersedes the revenue recognition requirements and industry-specific guidance under Accounting Standards Codification Top 605 – Revenue Recognition (“ASC 605”). The Company adopted ASC 606 using the modified retrospective method which allows the Company to apply the new standard to all new contracts entered into after December 31, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance prior to December 31, 2017. The Company identified no material impact on its historical revenues upon initial application of ASC 606, and as such has not recognized any cumulative catch-up effect to the opening balance of the Company’s shareholders’ equity as of January 1, 2018. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.

 

Revenue from Contracts with Customers

 

Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Based upon the Company’s current purchasers’ past experience and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the gas at the inlet of the plant and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. 

 

When sales volumes exceed the Company’s entitled share, a production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. Production imbalances have not had and currently do not have a material impact on the financial statements, and this did not change with the adoption of ASC 606.

 

Transaction Price Allocated to Remaining Performance Obligations

 

Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company has used the practical expedient in ASC 606 which states that the Company is not required to disclose that transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligation is not required.

 

Contract Balances

 

The Company receives purchaser statements from the majority of its customers but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. The majority of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and supply and demand conditions. The price of these commodities fluctuates to remain competitive with supply.

 

Prior Period Performance Obligations

 

The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates

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and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process.

 

Impact of Adoption of ASC 606

 

The Company has reviewed all of its natural gas, NGLs, residue gas, condensate and crude oil sales contracts to assess the impact of the provisions of ASC 606. Based upon the Company’s review, there were no required changes to the recording of residue gas or condensate and crude oil contracts. Certain NGL and natural gas contracts would require insignificant changes to the recording of transportation, gathering and processing fees as net to revenue or as an expense. The Company concluded that these minor changes were not material to its operating results on a quantitative or qualitative basis. Therefore, there was no impact to its results of operations for the nine months ended September 30, 2018. The Company has modified procedures to its existing internal controls relating to revenue by reviewing for any significant increase in sales level, primarily on gas processing or gas purchasing contracts, on a quarterly basis to monitor the significance of gross revenue versus net revenue and expenses under ASC 606. As under previous revenue guidance, the Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment.

 

Recent Accounting Pronouncements

 

Leases: In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 treatment of leases and that proposed in ASU 2016-02 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 has commenced analyzing its leases for evaluation and will continue to assess the impact this may have on its financial position, results of operations and cash flows.

 

In January 2018, the FASB issued ASU 2018-01 – Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. The amendments in ASU 2018-01 permit an entity to elect an optional transition practical expedient to not evaluate under Topic 842 land easements (right of way payments) that exist or expired before the entity’s adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. Right of way payments do not have a material impact on the Company’s results of operations and the Company plans to elect the practical expedient to evaluate right of way payments prospectively on adoption of Topic 842. 

 

In July 2018, the FASB issued ASU 2018-10 – Codification Improvements to Topic 842, Leases. The amendments in ASU 2018-10 affect narrow aspects of the guidance issued in the amendments in ASU 2016-02 – Leases (Topic 842). For public entities, ASU 2018-10 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 is currently evaluating the provisions of this update and assessing the impact, if any, it may have on its financial position and results of operations.

 

In July 2018, the FASB issued ASU 2018-11 – Leases (Topic 842) Targeted Improvements. The FASB has been assisting stakeholders with implementation questions and issues as organizations prepare to adopt ASU 2016-02. Many stakeholders inquired about the following two requirements: Comparative reporting requirements for initial adoption and, for lessors only, separating lease and non-lease components in a contract and allocating the consideration in the contract to the separate components. The amendments in ASU 2018-11 provide another transition method in addition to the existing transition method by allowing entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The amendments in ASU 2018-11 provide lessors with a practical expedient, by class of underlying asset, to not separate non-lease components from the associated lease component. The Company is currently evaluating the provisions of this update and assessing the impact, if any, it may have on its financial position and results of operations.

 

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Other: In August 2018, the FASB issued ASU 2018-13 – Fair Value Measurement (Topic 820). The amendments in ASU 2018-13 modify the disclosure requirements on fair value measurements in Topic 820. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

 

3. Acquisitions and Dispositions  

 

On September 11, 2018, the Company entered into a definitive agreement to divest certain of its non-core assets in Liberty and Hardin Counties in Southeast Texas. These assets held for sale are recorded at the lower of their carrying value or fair value less cost to sell. As a result of this planned sale, the Company reduced the value of the assets to their fair value and recorded an impairment of approximately $12.8 million during the three months ended September 30, 2018 in “Impairment and abandonment of oil and gas properties” in the Company’s consolidated statement of operations. The sale was completed on November 2, 2018 for cash proceeds of $6.0 million. This planned disposition did not qualify as a discontinued operation.

 

The major categories of assets and liabilities for these assets held for sale were:

 

 

 

 

 

    

September 30, 2018

 

 

 

(in thousands)

Assets classified as held for sale:

 

 

 

Accounts receivable

 

$

1,748

Property and equipment, at cost:

 

 

 

Oil and natural gas properties; successful efforts method

 

 

46,855

Accumulated depreciation, depletion and impairment

 

 

(38,607)

Property and equipment, net

 

 

8,248

Total assets classified as held for sale

 

$

9,996

 

 

 

 

Liabilities associated with assets held for sale:

 

 

 

Current liabilities:

 

 

 

Revenue payable

 

$

(784)

Accrued liabilities

 

 

(580)

Current asset retirement obligations

 

 

(76)

Total current liabilities

 

 

(1,440)

Asset retirement obligations

 

 

(2,155)

Total liabilities associated with assets held for sale

 

$

(3,595)

 

On May 25, 2018, the Company sold its non-operated assets located in Starr County, Texas for a cash purchase price of $0.6 million. The Company recorded a net gain of $1.3 million after removal of the asset retirement obligations associated with the sold properties and final closing adjustments.

 

On March 28, 2018, the Company sold its operated Eagle Ford Shale assets located in Karnes County, Texas for a cash purchase price of $21.0 million. The Company recorded a net gain of $9.5 million, after final closing adjustments.

 

Effective February 1, 2017, the Company sold to a third party all of its assets in the Bob West North 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 Topic 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

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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.

 

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, 2018. 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, 2018 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

Fair Value Measurements Using

 

 

    

Carrying Value

    

Level 1

    

Level 2

    

Level 3

 

Derivatives

 

 

 

 

 

 

 

 

 

Commodity price contracts - assets

 

$

82

 

$

 —

 

$

82

 

$

 —

 

Commodity price contracts - liabilities

 

$

(3,877)

 

$

 —

 

$

(3,877)

 

$

 —

 

 

Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term 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 its 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 reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market 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, 2018, the Company's derivative contracts were all with certain members of its credit facility lending group, 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 Accounting Standards Codification Topic 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 nine months. See Note 9 - "Long-Term Debt" for further information.

 

Impairments

 

The Company 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, probable and possible 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

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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 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, 2018, 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.

 

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As of September 30, 2018, the following derivative instruments were in place (fair value in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

    

Period

    

Derivative

    

Volume/Month

    

Price/Unit

    

Fair Value

 

Natural Gas

 

Oct 2018

 

Swap

 

70,000 MMBtus

 

$

3.07 (1)

 

 

3

 

Natural Gas

 

Nov 2018 - Dec 2018

 

Swap

 

320,000 MMBtus

 

$

3.07 (1)

 

 

14

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Oct 2018

 

Collar

 

20,000 Bbls

 

$

52.00 - 56.85 (2)

 

 

(479)

 

Oil

 

Nov 2018 - Dec 2018

 

Collar

 

15,000 Bbls

 

$

52.00 - 56.85 (2)

 

 

(680)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Oct 2018 - Dec 2018

 

Collar

 

2,000 Bbls

 

$

52.00 - 58.76 (3)

 

 

(86)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Nov 2018 - Dec 2018

 

Collar

 

5,000 Bbls

 

$

58.00 - 68.00 (2)

 

 

(118)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Oct 2018

 

Swap

 

3,000 Bbls

 

$

70.11 (3)

 

 

(9)

 

Oil

 

Nov 2018 - Dec 2018

 

Swap

 

6,000 Bbls

 

$

70.11 (3)

 

 

(33)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Jan 2019 - Dec 2019

 

Collar

 

4,000 Bbls

 

$

52.00 - 59.45 (3)

 

 

(601)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Jan 2019 - Dec 2019

 

Collar

 

7,000 Bbls

 

$

50.00 - 58.00 (2)

 

 

(1,565)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Jan 2019 - July 2019

 

Swap

 

6,000 Bbls

 

$

66.10 (3)

 

 

(241)

 

 

 

 

 

Total net fair value of derivative instruments

 

$

(3,795)

 


(1)

Based on Henry Hub NYMEX natural gas prices.

(2)

Based on Argus Louisiana Light Sweet crude oil prices.

(3)

Based on West Texas Intermediate crude oil prices.

 

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of September 30, 2018 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

    

Gross

    

Netting (1)

    

Total

 

Assets

 

$

82

 

$

 —

 

$

82

 

Liabilities

 

$

(3,877)

 

$

 —

 

$

(3,877)

 


(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, 2017 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

    

Gross

    

Netting (1)

    

Total

 

Assets

 

$

1,188

 

$

(1,188)

 

$

 —

 

Liabilities

 

$

(2,431)

 

$

1,188

 

$

(1,243)

 


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

 

 

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The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the three and nine months ended September 30, 2018 and 2017 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30, 

 

Nine Months Ended September 30, 

 

 

    

2018

    

2017

    

2018

    

2017

 

Crude oil contracts

 

$

(1,136)

 

$

342

 

$

(2,846)

 

$

879

 

Natural gas contracts

 

 

57

 

 

179

 

 

436

 

 

(102)

 

Realized gain (loss)

 

$

(1,079)

 

$

521

 

$

(2,410)

 

$

777

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil contracts

 

$

(152)

 

$

(661)

 

$

(1,747)

 

$

156

 

Natural gas contracts

 

 

(88)

 

 

131

 

 

(804)

 

 

3,641

 

Unrealized gain (loss)

 

$

(240)

 

$

(530)

 

$

(2,551)

 

$

3,797

 

Gain (loss) on derivatives, net

 

$

(1,319)

 

$

(9)

 

$

(4,961)

 

$

4,574

 

 

In October 2018, the Company entered into the following additional derivative contracts with certain members of its credit facility lenders:

 

 

 

 

 

 

 

 

 

 

Commodity

    

Period

    

Derivative

    

Volume/Month

    

Price/Unit

Natural Gas

 

Nov 2018 - Dec 2018

 

Swap

 

200,000 MMBtus

 

$

3.35 (1)

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

Nov 2018 - Dec 2018

 

Swap

 

100,000 MMBtus

 

$

3.21 (1)

Natural Gas

 

Jan 2019 - Mar 2019

 

Swap

 

600,000 MMBtus

 

$

3.21 (1)

Natural Gas

 

Apr 2019 - July 2019

 

Swap

 

600,000 MMBtus

 

$

2.75 (1)

Natural Gas

 

Aug 2019 - Oct 2019

 

Swap

 

100,000 MMBtus

 

$

2.75 (1)

Natural Gas

 

Nov 2019 - Dec 2019

 

Swap

 

500,000 MMBtus

 

$

2.75 (1)

 

 

 

 

 

 

 

 

 

 

Oil

 

Nov 2018 - Dec 2018

 

Collar

 

7,000 Bbls

 

$

70.00 - 77.65 (2)

 

 

 

 

 

 

 

 

 

 

Oil

 

Jan 2019 - June 2019

 

Collar

 

12,000 Bbls

 

$

70.00 - 76.25 (2)

 

 

 

 

 

 

 

 

 

 

Oil

 

July 2019

 

Swap

 

12,000 Bbls

 

$

72.10 (2)

Oil

 

Aug 2019 - Oct 2019

 

Swap

 

9,000 Bbls

 

$

72.10 (2)

Oil

 

Nov 2019 - Dec 2019

 

Swap

 

12,000 Bbls

 

$

72.10 (2)


(1)

Based on Henry Hub NYMEX natural gas prices.

(2)

Based on West Texas Intermediate crude oil prices. 

 

 

 

6. Stock-Based Compensation

 

The Company recognized approximately $3.8 million and $4.6 million in stock compensation expense during the nine months ended September 30, 2018 and 2017, respectively, for equity awards granted to its officers, employees and directors. As of September 30, 2018, an additional $2.6 million of compensation expense remained to be recognized over the remaining weighted-average vesting period of 1.4 years. This includes expense related to restricted stock, Performance Stock Units (“PSUs”) and stock options.

 

Restricted Stock 

 

During the nine months ended September 30, 2018, the Company granted 225,782 shares of restricted common stock, which vest over three years, to executive officers as part of their overall compensation package. Additionally, the Company granted 82,500 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the nine months ended September 30, 2018, was $3.76 per share with a total fair value of approximately $1.2 million with no adjustment for an estimated weighted average forfeiture rate. During the nine months ended September 30, 2018, 152,294 restricted shares were forfeited by former employees, of which 105,800 were related to the resignation of the Company’s former President and CEO in September 2018. The aggregate intrinsic value of restricted shares forfeited

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during the nine months ended September 30, 2018 was approximately $1.0 million.  Approximately 1.5 million shares remained available for grant under the Amended and Restated 2009 Incentive Compensation Plan as of September 30, 2018, assuming PSUs are settled at 100% of target.

 

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 fair value of the restricted shares granted during the nine months ended September 30, 2017, was $7.55 per share 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.  

 

Performance Stock Units

 

During the nine months ended September 30, 2018, the Company granted 190,782 PSUs to executive officers as part of their overall compensation package, at a weighted average fair value of $7.69 per unit. 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. An additional 160,908 PSUs were granted to executive officers, as part of their overall compensation package, at a value of $13.91 per unit during the nine months ended September 30, 2017. All fair value prices were determined using the Monte Carlo simulation model. During the nine months ended September 30, 2018 and 2017, 182,227 and 94,063 PSUs were forfeited by former employees, respectively. 153,127 of the PSU forfeitures in 2018 were related to the resignation of the Company’s former President and CEO in September 2018. 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, 2018 and 2017, 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, 2018 or 2017.

 

During the nine months ended September 30, 2018,  no stock options were exercised and 4,500 were forfeited by former employees. During the nine months ended September 30, 2017, no stock options were exercised and stock options for 17,072 shares of common stock were forfeited by former employees.

 

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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, 2018

    

December 31, 2017

 

Accounts receivable:

 

 

 

 

 

 

 

Trade receivables

 

$

4,908

 

$

6,565

 

Receivable for Alta Resources distribution

 

 

1,993

 

 

1,993

 

Joint interest billings

 

 

3,649

 

 

4,030

 

Income taxes receivable

 

 

424

 

 

424

 

Other receivables

 

 

764

 

 

828

 

Allowance for doubtful accounts

 

 

(781)

 

 

(781)

 

Total accounts receivable

 

$

10,957

 

$

13,059

 

 

 

 

 

 

 

 

 

Prepaid expenses and other:

 

 

 

 

 

 

 

Prepaid insurance

 

$

874

 

$

1,177