mcf_Current_Folio_10Qv2

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

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

 

For the quarterly period ended March 31, 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 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 May 1, 2018 was 25,662,238.

 

 

 


 

Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31, 2018 

 

TABLE OF CONTENTS 

 

 

 

 

 

 

 

 

    

    

   

Page

 

PART I—FINANCIAL INFORMATION 

 

 

 

 

 

 

Item 1. 

 

Consolidated Financial Statements

 

 

 

 

 

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

 

3

 

 

 

Consolidated Statements of Operations (unaudited) for the three months ended March 31, 2018 and 2017

 

4

 

 

 

Consolidated Statements of Cash Flows (unaudited) for the three months ended March 31, 2018 and 2017

 

5

 

 

 

Consolidated Statement of Shareholders’ Equity (unaudited) for the three months ended March 31, 2018

 

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

 

30

 

Item 4. 

 

Controls and Procedures

 

32

 

 

 

 

 

 

 

PART II—OTHER INFORMATION 

 

 

 

 

 

 

 

Item 1. 

 

Legal Proceedings

 

32

 

Item 1A. 

 

Risk Factors

 

32

 

Item 2. 

 

Unregistered Sales of Equity Securities and Use of Proceeds

 

33

 

Item 3. 

 

Defaults upon Senior Securities

 

33

 

Item 4. 

 

Mine Safety Disclosures

 

33

 

Item 5. 

 

Other Information

 

33

 

Item 6. 

 

Exhibits

 

33

 

 

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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Item 1. Consolidated Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except shares)

 

 

 

 

 

 

 

 

 

 

 

March 31, 

 

December 31, 

 

 

    

2018

    

2017

  

 

 

 

 

 

 

(unaudited)

 

CURRENT ASSETS:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

 —

 

$

 —

 

Accounts receivable, net

 

 

13,701

 

 

13,059

 

Prepaid expenses

 

 

952

 

 

1,892

 

Current derivative asset

 

 

736

 

 

822

 

Total current assets

 

 

15,389

 

 

15,773

 

PROPERTY, PLANT AND EQUIPMENT:

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

Proved properties

 

 

1,180,083

 

 

1,239,662

 

Unproved properties

 

 

36,150

 

 

35,243

 

Other property and equipment

 

 

1,272

 

 

1,272

 

Accumulated depreciation, depletion and amortization

 

 

(876,972)

 

 

(930,220)

 

Total property, plant and equipment, net

 

 

340,533

 

 

345,957

 

OTHER NON-CURRENT ASSETS:

 

 

 

 

 

 

 

Investments in affiliates

 

 

19,170

 

 

18,464

 

Long-term derivative asset

 

 

328

 

 

 —

 

Deferred tax asset

 

 

424

 

 

424

 

Other

 

 

716

 

 

835

 

Total other non-current assets

 

 

20,638

 

 

19,723

 

TOTAL ASSETS

 

$

376,560

 

$

381,453

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

42,610

 

$

46,755

 

Current derivative liability

 

 

2,047

 

 

1,765

 

Current asset retirement obligations

 

 

1,592

 

 

2,017

 

Total current liabilities

 

 

46,249

 

 

50,537

 

NON-CURRENT LIABILITIES:

 

 

 

 

 

 

 

Long-term debt

 

 

78,660

 

 

85,380

 

Long-term derivative liability

 

 

778

 

 

300

 

Asset retirement obligations

 

 

20,455

 

 

20,388

 

Other long term liabilities

 

 

3,528

 

 

248

 

Total non-current liabilities

 

 

103,421

 

 

106,316

 

Total liabilities

 

 

149,670

 

 

156,853

 

COMMITMENTS AND CONTINGENCIES (NOTE 12)

 

 

 

 

 

 

 

SHAREHOLDERS’ EQUITY:

 

 

 

 

 

 

 

Common stock, $0.04 par value, 50 million shares authorized, 31,079,584 shares issued and 25,695,797 shares outstanding at March 31, 2018, 30,873,470 shares issued and 25,505,715 shares outstanding at December 31, 2017

 

 

1,231

 

 

1,223

 

Additional paid-in capital

 

 

303,943

 

 

302,527

 

Treasury shares at cost (5,383,787 shares at March 31, 2018 and 5,367,755 shares at December 31, 2017)

 

 

(128,654)

 

 

(128,583)

 

Retained earnings

 

 

50,370

 

 

49,433

 

Total shareholders’ equity

 

 

226,890

 

 

224,600

 

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

 

$

376,560

 

$

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

 

 

 

March 31, 

 

 

    

2018

    

2017

 

 

 

(unaudited)

 

REVENUES:

 

 

 

 

 

 

 

Oil and condensate sales

 

$

8,811

 

$

5,542

 

Natural gas sales

 

 

8,609

 

 

11,140

 

Natural gas liquids sales

 

 

3,017

 

 

2,742

 

Total revenues

 

 

20,437

 

 

19,424

 

EXPENSES:

 

 

 

 

 

 

 

Operating expenses

 

 

6,927

 

 

6,833

 

Exploration expenses

 

 

469

 

 

91

 

Depreciation, depletion and amortization

 

 

10,485

 

 

11,771

 

Impairment and abandonment of oil and gas properties

 

 

3,327

 

 

30

 

General and administrative expenses

 

 

6,726

 

 

6,596

 

Total expenses

 

 

27,934

 

 

25,321

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

Gain from investment in affiliates, net of income taxes

 

 

707

 

 

1,784

 

Gain from sale of assets

 

 

9,447

 

 

2,940

 

Interest expense

 

 

(1,409)

 

 

(759)

 

Gain (loss) on derivatives, net

 

 

(1,032)

 

 

3,096

 

Other income (expense)

 

 

879

 

 

(88)

 

Total other income

 

 

8,592

 

 

6,973

 

NET INCOME BEFORE INCOME TAXES

 

 

1,095

 

 

1,076

 

Income tax provision

 

 

(158)

 

 

(191)

 

NET INCOME

 

$

937

 

$

885

 

NET INCOME PER SHARE:

 

 

 

 

 

 

 

Basic

 

$

0.04

 

$

0.04

 

Diluted

 

$

0.04

 

$

0.04

 

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:

 

 

 

 

 

 

 

Basic

 

 

24,793

 

 

24,607

 

Diluted

 

 

24,841

 

 

24,641

 

 

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)

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

March 31, 

 

 

    

2018

    

2017

 

 

 

 

 

 

 

 

 

 

 

(unaudited)

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

Net income

 

$

937

 

$

885

 

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

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

10,485

 

 

11,771

 

Impairment of natural gas and oil properties

 

 

3,097

 

 

 —

 

Exploration recovery

 

 

 —

 

 

(232)

 

Gain on sale of assets

 

 

(9,447)

 

 

(2,940)

 

Gain from investment in affiliates

 

 

(707)

 

 

(1,784)

 

Stock-based compensation

 

 

1,424

 

 

1,456

 

Unrealized loss (gain) on derivative instruments

 

 

519

 

 

(3,275)

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Decrease (increase) in accounts receivable & other receivables

 

 

(642)

 

 

4,840

 

Decrease in prepaids

 

 

940

 

 

991

 

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

 

 

(6,053)

 

 

3,869

 

Decrease in other accrued liabilities

 

 

(1,921)

 

 

(973)

 

Increase in income taxes payable, net

 

 

158

 

 

188

 

Other

 

 

3,279

 

 

61

 

Net cash provided by operating activities

 

$

2,069

 

$

14,857

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

Natural gas and oil exploration and development expenditures

 

$

(16,244)

 

$

(20,807)

 

Additions to furniture & equipment

 

 

 —

 

 

(14)

 

Sale of oil & gas properties

 

 

20,965

 

 

670

 

Net cash provided by (used) in investing activities

 

$

4,721

 

$

(20,151)

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

Borrowings under credit facility

 

$

74,832

 

$

54,963

 

Repayments under credit facility

 

 

(81,551)

 

 

(49,595)

 

Purchase of treasury stock

 

 

(71)

 

 

(74)

 

Net cash provided by (used in) financing activities

 

$

(6,790)

 

$

5,294

 

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)

 

Ex

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

(16,032)

 

 

 —

 

 

 —

 

 

(71)

 

 

 —

 

 

(71)

 

Restricted shares activity

 

206,114

 

 

 8

 

 

(8)

 

 

 —

 

 

 —

 

 

 —

 

Stock-based compensation

 

 —

 

 

 —

 

 

1,424

 

 

 —

 

 

 —

 

 

1,424

 

Net income

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

937

 

 

937

 

Balance at March 31, 2018

 

25,695,797

 

$

1,231

 

$

303,943

 

$

(128,654)

 

$

50,370

 

$

226,890

 

 

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 the onshore West Texas, the Texas Gulf Coast and the Rocky Mountain regions of the United States.

 

The following table lists the Company’s primary producing areas as of March 31, 2018:

 

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)

Other Texas Gulf Coast

 

Conventional and smaller 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 quarter ended March 31, 2018.

 

The Company’s 2018 capital program has focused, and will continue to focus, on the development of the Company’s 16,500 gross operated acres (6,800 net) 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, through acquisition. Acquisition efforts will typically be focused on areas in which the Company can leverage its geographic and geological expertise to exploit identified drilling opportunities and where the Company can develop an inventory of additional drilling prospects that the Company believes will enable it to grow production and add reserves. 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, 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 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. The consolidated results of operations for the quarter ended March 31, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018.

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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

The Company’s application of the successful efforts method of accounting for the Company’s 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, 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. During the quarter ended March 31, 2018, the Company recognized $2.3 million in non-cash proved impairment charges related to its Vermilion 170 offshore property. No impairment of proved properties was recognized during the quarter ended March 31, 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 $0.8 million for the quarter ended March 31, 2018, related to impairment of certain non-core unproved properties due to expiring leases. The Company recognized no impairment of unproved properties for the quarter ended March 31, 2017.

 

Net Income Per Common Share 

 

Basic net income per common share is computed by dividing the net income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income 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 quarter ended March 31, 2018, the Company excluded 670,210 potentially dilutive securities, as they were antidilutive. For the quarter ended March 31, 2017, the Company excluded 917,737 potentially dilutive securities, 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

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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.

 

 

 

Revenue Recognition

 

Adoption of ASC 606

 

During the quarter ended March 31, 2018 the Company adopted Accounting Standards Codification 606 – Revenue from Contracts with Customers (“ASC 606”). 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 the Company’s 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,

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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 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 the Company’s 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 our operating results for the quarter ended March 31, 2018. Going forward, the Company is modifying 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

 

In January 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-01 – Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. The amendments in this update 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 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. 

 

3. Acquisitions and Dispositions  

 

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 $9.4 million.

 

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.

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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.

 

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 March 31, 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 March 31, 2018 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

Fair Value Measurements Using

 

 

    

Carrying Value

    

Level 1

    

Level 2

    

Level 3

 

Derivatives

 

 

 

 

 

 

 

 

 

Commodity price contracts - assets

 

$

1,064

 

$

 —

 

$

1,064

 

$

 —

 

Commodity price contracts - liabilities

 

$

(2,825)

 

$

 —

 

$

(2,825)

 

$

 —

 

 

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 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 March 31, 2018, 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

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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 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 March 31, 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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The following derivative instruments were in place at March 31, 2018 (fair value in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

    

Period

    

Derivative

    

Volume/Month

    

Price/Unit

    

Fair Value

 

Natural Gas

 

Apr 2018 - July 2018

 

Swap

 

370,000 MMBtus

 

$

3.07 (1)

 

 

462

 

Natural Gas

 

Aug 2018 - Oct 2018

 

Swap

 

70,000 MMBtus

 

$

3.07 (1)

 

 

48

 

Natural Gas

 

Nov 2018 - Dec 2018

 

Swap

 

320,000 MMBtus

 

$

3.07 (1)

 

 

77

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Apr 2018 - June 2018

 

Swap

 

20,000 Bbls

 

$

56.40 (2)

 

 

(653)

 

Oil

 

July 2018 - Oct 2018

 

Collar

 

20,000 Bbls

 

$

52.00 - 56.85 (2)

 

 

(737)

 

Oil

 

Nov 2018 - Dec 2018

 

Collar

 

15,000 Bbls

 

$

52.00 - 56.85 (2)

 

 

(241)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Apr 2018 - Dec 2018

 

Collar

 

2,000 Bbls

 

$

52.00 - 58.76 (3)

 

 

(100)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Apr 2018 - July 2018

 

Collar

 

6,000 Bbls

 

$

58.00 - 68.00 (2)

 

 

(35)

 

Oil

 

Nov 2018 - Dec 2018

 

Collar

 

5,000 Bbls

 

$

58.00 - 68.00 (2)

 

 

(5)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Jan 2019 - Dec 2019

 

Collar

 

4,000 Bbls

 

$

52.00 - 59.45 (3)

 

 

(105)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Jan 2019 - Dec 2019

 

Collar

 

7,000 Bbls

 

$

50.00 - 58.00 (2)

 

 

(472)

 

 

 

 

 

Total net fair value of derivative instruments

 

$

(1,761)

 


(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 March 31, 2018 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

    

Gross

    

Netting (1)

    

Total

 

Assets

 

$

1,064

 

$

 —

 

$

1,064

 

Liabilities

 

$

(2,825)

 

$

 —

 

$

(2,825)

 


(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 quarters ended March 31, 2018 and 2017 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31, 

 

 

    

2018

    

2017

    

Crude oil contracts

 

$

(588)

 

$

170

 

Natural gas contracts

 

 

75

 

 

(349)

 

Realized loss

 

$

(513)

 

$

(179)

 

 

 

 

 

 

 

 

 

Crude oil contracts

 

$

(284)

 

$

524

 

Natural gas contracts

 

 

(235)

 

 

2,751

 

Unrealized gain (loss)

 

$

(519)

 

$

3,275

 

Gain (loss) on derivatives, net

 

$

(1,032)

 

$

3,096

 

 

 

 

6. Stock-Based Compensation

 

The Company recognized approximately $1.4 million and $1.5 million in stock compensation expense during the quarters ended March 31, 2018 and 2017, respectively, for equity awards granted to its officers, employees and directors. As of March 31, 2018, an additional $5.3 million of compensation expense remained to be recognized over the remaining weighted-average vesting period of 1.9 years. This includes expense related to restricted stock, Performance Stock Units (“PSUs”) and stock options.

 

Restricted Stock 

 

During the quarter ended March 31, 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. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2018, was $3.57 with a total fair value of approximately $0.8 million with no adjustment for an estimated weighted average forfeiture rate. During the quarter ended March 31, 2018, 19,668 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the quarter ended March 31, 2018 was approximately $164 thousand. Approximately 1.2 million shares remained available for grant under the Amended and Restated 2009 Incentive Compensation Plan as of March 31, 2018, assuming PSUs are settled at 100% of target.

 

During the quarter ended March 31, 2017, the Company granted 30,000 shares of restricted common stock, which vest over three years, to a newly hired employee as part of his overall compensation package. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2017, was $7.78 with a total fair value of approximately $0.2 million after adjustment for an estimated weighted average forfeiture rate of 5.8%. During the quarter ended March 31, 2017, 24,244 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the quarter ended March 31, 2017 was approximately $256 thousand.

 

Performance Stock Units

 

During the quarter ended March 31, 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 quarter ended March 31, 2017, the Company granted 30,000 PSUs to a new employee, at a weighted average fair value of $8.32 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the quarters ended March 31, 2018 and 2017, 16,900 and 23,800 PSUs were forfeited by former employees, respectively. 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

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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 quarters ended March 31, 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 quarters ended March 31, 2018 or 2017.

 

During the quarter ended March 31, 2018, no stock options were exercised or forfeited. During the quarter ended March 31, 2017, no stock options were exercised and stock options for 14,586 shares of common stock were forfeited by former employees.

 

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):

 

 

 

 

 

 

 

 

 

 

    

March 31, 2018

    

December 31, 2017

 

Accounts receivable:

 

 

 

 

 

 

 

Trade receivables

 

$

7,407

 

$

6,565

 

Receivable for Alta Resources Distribution

 

 

1,993

 

 

1,993

 

Joint interest billings

 

 

3,896

 

 

4,030

 

Income taxes receivable

 

 

424

 

 

424

 

Other receivables

 

 

762

 

 

828

 

Allowance for doubtful accounts

 

 

(781)

 

 

(781)

 

Total accounts receivable

 

$

13,701

 

$

13,059

 

 

 

 

 

 

 

 

 

Prepaid expenses and other:

 

 

 

 

 

 

 

Prepaid insurance

 

$

429

 

$

1,177

 

Other

 

 

523

 

 

715

 

Total prepaid expenses and other

 

$

952

 

$

1,892

 

 

 

 

 

 

 

 

 

Accounts payable and accrued liabilities:

 

 

 

 

 

 

 

Royalties and revenue payable

 

$

14,762

 

$

18,181

 

Advances from partners

 

 

2,816

 

 

2,243

 

Accrued exploration and development

 

 

12,069

 

 

8,400

 

Trade payables

 

 

6,011

 

 

9,559

 

Accrued general and administrative expenses

 

 

2,562

 

 

2,960

 

Accrued operating expenses

 

 

1,350

 

 

1,654

 

Other accounts payable and accrued liabilities

 

 

3,040

 

 

3,758

 

Total accounts payable and accrued liabilities

 

$

42,610

 

$

46,755

 

 

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Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the quarters ended March 31, 2018 and 2017 (in thousands):

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31, 

 

 

 

2018

    

 

2017

 

Cash payments:

 

 

 

 

 

 

Interest payments

$

1,448

 

$

760

 

Income tax payments

$

 —

 

$

 3

 

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

 

 

 

 

 

 

Increase (decrease) in accrued capital expenditures

$

3,669

 

$

(5,261)

 

 

 

8. Investment in Exaro Energy III LLC

 

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

 

The following table (in thousands) presents condensed balance sheet data for Exaro as of March 31, 2018 and December 31, 2017. The balance sheet data was derived from Exaro’s balance sheet as of March 31, 2018 and December 31, 2017 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 March 31, 2018 was approximately $19.1 million.

 

 

 

 

 

 

 

 

 

 

    

March 31, 2018

    

December 31, 2017

 

Current assets (1)

 

$

14,993

 

$

17,063

 

Non-current assets:

 

 

 

 

 

 

 

Net property and equipment

 

 

80,323

 

 

82,450

 

Gas processing deposit

 

 

1,150

 

 

1,150

 

Other non-current assets

 

 

1,124

 

 

390

 

Total non-current assets

 

 

82,597

 

 

83,990

 

Total assets

 

$

97,590

 

$

101,053

 

 

 

 

 

 

 

 

 

Current liabilities

 

$

5,017

 

$

6,199

 

Non-current liabilities:

 

 

 

 

 

 

 

Long-term debt

 

 

35,893

 

 

40,375

 

Other non-current liabilities

 

 

3,909

 

 

3,858

 

Total non-current liabilities

 

 

39,802

 

 

44,233

 

Members' equity

 

 

52,771

 

 

50,621

 

Total liabilities & members' equity

 

$

97,590

 

$

101,053

 


(1)

Approximately $10.5 million and $12.8 million of current assets as of March 31, 2018 and December 31, 2017, respectively, is cash.

 

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The following table (in thousands) presents the condensed results of operations for Exaro for the quarters ended March 31, 2018 and 2017. The results of operations for the quarters ended March 31, 2018 and 2017 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 quarters ended March 31, 2018 and 2017 was a gain of $0.7 million, net of no tax expense, and a gain of $1.8 million, net of no tax expense, respectively.

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31, 

 

 

    

2018

    

2017

    

Production:

 

 

 

 

 

 

 

Oil (thousand barrels)

 

 

22

 

 

25

 

Gas (million cubic feet)

 

 

1,933

 

 

2,308

 

Total (million cubic feet equivalent)

 

 

2,065

 

 

2,460

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

 

$

6,883

 

$

9,171

 

Gain (loss) on derivatives

 

 

1,626

 

 

2,562

 

Other gain

 

 

 —

 

 

 —

 

Less:

 

 

 

 

 

 

 

Lease operating expenses

 

 

3,390

 

 

3,219

 

Depreciation, depletion, amortization & accretion

 

 

2,407

 

 

2,343

 

General & administrative expense

 

 

354

 

 

733

 

Income from continuing operations

 

 

2,358

 

 

5,438

 

Net interest expense

 

 

(444)

 

 

(624)

 

Net income

 

$

1,914

 

$

4,814

 

 

Exaro's results of operations do not include income taxes because Exaro is treated as a partnership for tax purposes.

 

9. Long-Term Debt

 

RBC Credit Facility 

 

In October 2013, the Company entered into a $500 million revolving credit facility with Royal Bank of Canada and other lenders (the “RBC Credit Facility”), the maturity of which has been extended by subsequent amendment to October 1, 2019. The borrowing base under the facility is redetermined each November and May. As of March 31, 2018, the borrowing base under the RBC Credit Facility was $115 million. The Company is currently going through the redetermination process, but does not expect any material change that would adversely affect its liquidity.

 

As of March 31, 2018, the Company had approximately $78.7 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of December 31, 2017, the Company had approximately $85.4 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of March 31, 2018, borrowing availability under the RBC Credit Facility was $34.4 million.

 

The RBC Credit Facility is collateralized by a lien on substantially all the producing assets of the Company and its subsidiaries, including a security interest in the stock of Contango’s subsidiaries and a lien on the Company’s oil and gas properties.

 

Total interest expense under the RBC Credit Facility, including commitment fees, for the quarter ended March 31, 2018 was approximately $1.4 million. Total interest expense under the RBC Credit Facility, including commitment fees, for the quarter ended March 31, 2017 was approximately $0.8 million.

 

The RBC Credit Facility contains restrictive covenants which, among other things, restrict the declaration or payment of dividends by Contango and require a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of less than or equal to 3.50, both as defined in the RBC Credit Facility Agreement. As of March 31, 2018, the Company was in compliance with all financial covenants under the RBC Credit Facility. The RBC Credit Facility also contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default

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include, but are not limited to, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events.

 

The weighted average interest rate in effect at March 31, 2018 and December 31, 2017 was 5.4% and 5.2%, respectively. The RBC Credit Facility matures on October 1, 2019, at which time any outstanding balances will be due.

 

10. Income Taxes

 

The Company’s income tax provision for continuing operations consists of the following (in thousands):

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31, 

 

 

    

2018

    

2017

 

Current tax provision:

 

 

 

 

 

Federal

 

$

 —

 

$

 —

 

State

 

 

158

 

 

191

 

Total

 

$

158

 

$

191

 

Total tax provision:

 

 

 

 

 

 

 

Federal

 

$

 —

 

$

 —

 

State

 

 

158

 

 

191

 

Total income tax provision

 

$

158

 

$

191

 

 

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and, therefore, established a full valuation allowance at September 30, 2015. For the quarter ended March 31, 2018, the Company continues to take a full valuation allowance against its deferred tax asset except for the portion attributable to the estimated refundable Alternative Minimum Tax (“AMT”) credit. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

 

On December 22, 2017, the United States enacted tax reform legislation known as the H.R.1, commonly referred to as the “Tax Cuts and Jobs Act” (the “Act”), resulting in significant modifications to existing law. The Company completed the accounting for the effects of the Act during 2017. The Company’s financial statements for the quarter ended March 31, 2018 reflect certain effects of the Act which includes the reduced corporate tax of 21%, elimination of the corporate AMT, limitations on the use of interest expense and net operating losses, accelerated expensing of tangible property, as well as other changes.

 

 

11. Related Party Transactions

 

 Oaktree Capital Management L.P.

 

In November 2017, Oaktree Capital Management L.P. ("Oaktree") sold all of its shares of the Company’s stock. Mr. James Ford, previously a Managing Director and Portfolio Manager within Oaktree, and a Senior Advisor to Oaktree at the time of sale, has served on the Company’s board of directors since October 1, 2013. Mr. Ford was previously a member of Crimson’s board of directors from February 2005 until the closing of the Merger.

 

During the quarters ended March 31, 2018 and 2017, Mr. Ford earned $20 thousand and $14 thousand in cash as a result of his board participation, respectively.

 

No restricted stock was issued to Mr. Ford during the quarters ended March 31, 2018 and 2017.

 

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12. Commitments and Contingencies 

 

Legal Proceedings 

 

From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below.

 

In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decade-old poorly documented transactions. Based on prior summary judgments, the trial court has entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company appealed the trial court’s decision to the applicable state Court of Appeals. In the fourth quarter of 2017 the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. The Company continues to vigorously defend this lawsuit and has filed a motion for rehearing with the Court of Appeals, and if denied, will petition the Texas Supreme Court.   

 

In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for Harris County in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operated by the Company in the Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred to the district court for Liberty County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral interest on which it has been paid). The Company has made royalty payments with respect to the disputed interest in reliance, in part, upon leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million although the plaintiff’s claim increases as additional hydrocarbons are produced from the subject wells. The trial court has entered judgment in favor of the Company’s subsidiary and the successors to the grantors under the aforementioned deeds. The plaintiff appealed the trial court’s decision to the applicable state Court of Appeals. On December 14, 2017, the Court of Appeals affirmed the judgement in the Company’s favor. The plaintiff has filed a motion for rehearing. The Company continues to vigorously defend this lawsuit and believes that it has meritorious defenses. The Company believes if this matter were to be determined adversely, amounts owed to the plaintiff could be partially offset by recoupment rights the Company may have against other working interest and/or royalty interest owners in the unit.

 

While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various insurance policies that may provide coverage when certain types of legal proceedings are determined adversely.

 

Throughput Contract Commitment

 

The Company signed a throughput agreement with a third party pipeline owner/operator that constructed a natural gas gathering pipeline in the Company’s Southeast Texas area that allows the Company to defray the cost of building the pipeline itself. The Company currently forecasts that monthly gas volume deliveries through this line in its Southeast Texas area will not meet minimum throughput requirements under the agreement. Without further development in that area, the volume deficiency will continue through the expiration of the throughput commitment in March 2020. The throughput deficiency fee is paid in April of each calendar year. As of March 31, 2018, the Company estimates that the net deficiency fee will be approximately $1.0 million annually for the remaining contract period, based upon forecasted production volumes from existing proved producing reserves only, assuming no future development during this commitment period. As of March 31, 2018, based upon the current commodity price market and the Company’s short term strategic drilling plans, the Company has recorded a $1.8 million loss contingency through

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December 31, 2018. The Company will continue to assess this commitment in light of its development plans for this area.

 

 

 

 

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Available Information

 

General information about us can be found on our website at www.contango.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission (“SEC”). We are not including the information on our website as a part of, or incorporating it by reference into, this Report.

 

Cautionary Statement about Forward-Looking Statements

 

Certain statements contained in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should be”, “will be”, “believe”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements are made subject to certain risks and uncertainties that could cause actual results to differ materially from those stated. Risks and uncertainties that could cause or contribute to such differences include, without limitation, those discussed in the section entitled “Risk Factors” included in our Annual Report on Form 10-K and those factors summarized below:

 

·

our ability to successfully develop our undeveloped acreage in the Southern Delaware Basin and realize the benefits associated therewith;

·

our financial position;

·

our business strategy, including outsourcing;

·

meeting our forecasts and budgets;

·

expectations regarding natural gas and oil markets in the United States;

·

volatility in natural gas, natural gas liquids and oil prices;

·

operational constraints, start-up delays and production shut-ins at both operated and non-operated production platforms, pipelines and natural gas processing facilities;

·

the risks associated with acting as operator of deep high pressure and high temperature wells, including well blowouts and explosions;

·

the risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes, especially in prospects in which we have made a large capital commitment relative to the size of our capitalization structure;

·

the timing and successful drilling and completion of natural gas and oil wells;

·

our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations, and fund our drilling program;

·

the cost and availability of rigs and other materials, services and operating equipment;

·

timely and full receipt of sale proceeds from the sale of our production;

·

the ability to find, acquire, market, develop and produce new natural gas and oil properties;

·

interest rate volatility;

·

uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures;

·

the need to take impairments on our properties due to lower commodity prices;