UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 





For the quarterly period ended March 31, 2016 

OR





For the transition period from              to             

Commission file number 001-16317 

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)



(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, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):





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 6, 2016 was 19,586,187.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31, 2016 

TABLE OF CONTENTS

 





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)











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) 







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) 







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)

 







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 in order to explore, develop, exploit, produce and acquire crude oil and natural gas properties in the onshore Texas Gulf Coast and Rocky Mountain regions of the United States.

The following table lists the Company’s primary producing areas as of March 31, 2016:

Additionally, the Company has (i) operated properties producing from various conventional formations in various counties along the Texas Gulf Coast; (ii) operated producing properties in the Denver Julesburg Basin (“DJ Basin”) in Weld and Adams counties in Colorado, which the Company believes may also be prospective in the Niobrara Shale oil play; and (iii) operated producing properties in the Haynesville Shale, Mid Bossier and James Lime formations in East Texas. 

Due to the current challenging commodity price environment, the Company intends to focus its 2016 capital program on: (i) the preservation of its healthy financial position, including limiting its overall capital expenditure budget to a minimal amount; (ii) focusing drilling expenditures, if any, on strategic projects; (iii) identification of opportunities for cost efficiencies in all areas of its operations; and (iv) continuing to identify new resource potential opportunities, internally and, where appropriate, through acquisition. The Company will continuously monitor the commodity price environment, stability and forecast, and, if warranted, make adjustments to its drilling strategy as the year progresses.

The following table lists the primary area to which the Company has allocated drilling capital for 2016:



In addition, we have allocated some geological and geophysical and leasehold capital to Madison and Grimes counties, Texas and Weston County, Wyoming.

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, 2015 (the “2015 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2015 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

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should be read in conjunction with the 2015 Form 10-K. The consolidated results of operations for the three months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.

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. Republic Exploration LLC (“REX”), a partially-owned oil and gas exploration and development affiliate which is not controlled by the Company,  was proportionately consolidated prior to its dissolution as of December 31, 2015.  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.

Impairment of Long-Lived Assets

Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. The Company recognized approximately $0.7 million for impairment of proved properties for the quarter ended March 31, 2016. Substantially all of the non-cash impairment charge in the quarter ended March 31, 2016 is directly related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated reserves. The Company recognized a $2.0 million impairment of small marginal proved properties for the quarter ended March 31, 2015.  

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 $1.1 million for the quarter ended March 31, 2016,  related to partial impairment of certain unproved properties due primarily to the sustained low commodity price environment and expiring leases; substantially all  of  which is related to unproved lease cost amortization of the Elm Hill project in Fayette and Gonzales counties Texas. The Company recognized impairment expense of approximately $0.2 million for the quarter ended March 31, 2015, related to partial impairment of certain unproved properties due to expiring leases.

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. Potential dilutive securities, including unexercised stock options and unvested restricted stock, have not been considered when their effect would be antidilutive. For the quarter ended March 31, 2016,  116,461 stock options and 284,528 restricted shares were excluded from dilutive shares due to the loss for the period. For the quarter ended March 31, 2015,  129,852 stock options and 456,528 restricted shares were excluded from dilutive shares due to the loss for the period. 

Subsidiary Guarantees

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



Recent Accounting Pronouncements 

In March 2016, the FASB issued Accounting Standards Update No. 2016-09: Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 is part of an initiative to reduce complexity in accounting standards. The areas of simplification in ASU 2016-09 involve several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. For public entities, ASU 2016-09 is effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years; early application is

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permitted. The Company will continue to assess the impact this may have on its financial position, results of operations, and cash flows.

In February 2016, the FASB issued Accounting Standards Update 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. ASU 2016-02 further defines a lease as a contract that conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. Control over the use of the identified asset means that the customer has both (1) the right to obtain substantially all of the economic benefit from the use of the asset and (2) the right to direct the use of the asset. ASU 2016-02 requires disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. 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.

In January 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update No. 2016-01: Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (ASU 2016-01). The main objective of ASU 2016-01 is enhancing the reporting model for financial instruments to provide users of financial statements with more decision-useful information. The amendments in ASU 2016-01 make targeted improvements to GAAP by: (i) requiring equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) be measured at fair value with changes in fair value recognized in net income; (ii) simplifying the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment; (iii) exempting all non-public business entities from disclosing fair value information for financial instruments measured at amortized cost; (iv) eliminating requirement for public business entities to disclose the methods and significant assumptions used to estimate the fair value for financial instruments measured at amortized cost on the balance sheet: (v) requiring public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes; (vi) requiring separate presentation in other comprehensive income the portion of the total change in fair value of a liability resulting from a change in the instrument- specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments; (vii) requiring separate presentation of financial assets and financial liabilities by measurement category and form of financial asset; and (viii) clarifying that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. For public entities, ASU 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years; early application is permitted. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations.

Further, management is closely monitoring the joint standard-setting efforts of the FASB and the International Accounting Standards Board. There are a large number of pending accounting standards that are being targeted for completion in 2016 and beyond. Because these pending standards have not yet been finalized, management is not able to determine the potential future impact that these standards will have, if any, on the Company's financial position, results of operations, or cash flows.

3. 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, 2016.  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

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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, 2016 (in thousands):



Derivatives listed above are recorded in “Current derivative asset” on the Company’s consolidated balance sheet and include swaps 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. As of December 31, 2015, there were no outstanding commodity price contracts. See Note 4 - "Derivative Instruments" for additional discussion of derivatives.

As of March 31, 2016, the Company's derivative contracts were with 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 three months. See Note 8 - "Long-Term Debt" for further information.

Impairments

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

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.

4. 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

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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, 2016, the Company’s natural gas derivative positions consisted of “swaps”.  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.  

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 exposed to potential margin calls, under any of these contracts as they are secured under the RBC Credit Facility. See Note 8 - "Long-Term Debt" for further information regarding the RBC Credit Facility.

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

The following swaps were in place at March 31, 2016 (fair value in thousands):











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



As of December 31, 2015, the Company did not have any outstanding derivative positions.

The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the quarter ended March 31, 2016 (in thousands):





There were no gains or losses related to derivative instruments for the three months ended March 31, 2015.

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In April 2016, the Company entered into the following financial derivative contracts with a member of its bank group:



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.

5. Stock-Based Compensation

During the quarter ended March 31, 2016, the Company had a stock-based compensation program in effect which allows for stock options and/or restricted stock to be awarded to officers, directors, consultants and employees. This program includes (i) the Company's Amended and Restated 2009 Incentive Compensation Plan (the “2009 Plan”); and (ii) the Crimson 2005 Stock Incentive Plan (the “2005 Plan” or "Crimson Plan"), which expired on February 25, 2015.

Effective September 1, 2015, all employees and board members entered into a salary replacement program (the “Salary Replacement Program”) which is expected to continue through December 31, 2016. The Salary Replacement Program reduces all office employees’ base salary by 10% and all board of director retainer and committee chairman fees by 10% and replaces annually the portion of the salary/fees being reduced with common stock in a number of shares commensurate with the salary/fees reduction amount.

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, 2016 and March 31, 2015, 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, 2016 or 2015.

During the quarter ended March 31, 2016,  no stock options were exercised and no stock options were forfeited. During the quarter ended March 31, 2015,  no stock options were exercised and stock options for 82 shares of common stock were forfeited.

Restricted Stock

During the quarter ended March 31, 2016, the Company granted 40,688 shares of restricted common stock under the 2009 Plan. Of these, 38,943 shares were granted to employees, which vested immediately, and 1,745 shares were granted to directors, which vested immediately; all of which were granted pursuant to the Salary Replacement Program. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2016, was $6.40 with a total fair value of approximately $0.3 million after adjustment for an estimated weighted average forfeiture rate of 0.0%.  During the quarter ended March 31, 2016, 40 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the quarter ended March 31, 2016 was approximately $1 thousand. Approximately 0.8 million shares remain available for grant under the 2009 Plan as of March 31, 2016.

During the quarter ended March 31, 2015, the Company granted 241,121 shares of restricted common stock under the 2009 Plan to newly hired and promoted employees as part of their overall compensation package, which vest over four years.  Additionally, the Company issued the final 7,030 shares of restricted stock under the 2005 Plan to employees as part of their compensation package, which vest over four years. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2015, was $31.31 with a total fair value of approximately $7.8 million after adjustment for an estimated weighted average forfeiture rate of 5.2%. During the quarter ended March 31, 2015,  708 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the quarter ended March 31, 2015 was approximately $34 thousand.

The Company recognized approximately $1.7 million and $1.1 million in stock compensation expense during the quarters ended March 31, 2016 and 2015, respectively, for restricted shares granted to its officers, employees and directors. As of March 31, 2016, an additional $6.0 million of compensation expense remained to be recognized over the remaining weighted-average vesting period of 2.1 years.

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Additionally, in April 2016, the Company granted 197,306 stock awards to employees under the 2009 Plan as part of their overall compensation package.

6. 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):





Included in the table below is supplemental information about certain cash and non-cash transactions during the quarters ended March 31, 2016 and 2015 (in thousands):



















7. Investment in Exaro Energy III LLC

In April 2012, the Company entered into a Limited Liability Company Agreement (the “LLC Agreement”) in connection with the formation of Exaro. Pursuant to the LLC Agreement, as amended, the Company committed to invest up to $67.5 million in Exaro for an ownership interest of approximately 37%. The Company did not make any contributions during the quarter ended March 31, 2016. As of March 31, 2016, the Company had invested approximately $46.9 million.

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The following table (in thousands) presents condensed balance sheet data for Exaro as of March 31, 2016 and December 31, 2015. The balance sheet data was derived from Exaro’s balance sheet as of March 31, 2016 and December 31, 2015 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, 2016 was approximately $14.2 million.

 



The following table (in thousands) presents the condensed results of operations for Exaro for the three months ended March 31, 2016 and 2015. The results of operations for the three months ended March 31, 2016 and 2015 were derived from Exaro's financial statements for the respective periods. The income statement data below was not adjusted to represent the Company’s ownership interest but rather reflects the results of Exaro as a company. The Company's share in Exaro's results of operations recognized for the three months ended March 31, 2016 and 2015 was a gain of $40 thousand, with an insignificant tax expense, and a gain of $0.6 million, net of tax expense of $0.3 million, respectively.



Included in Other gain are realized and unrealized gains and losses attributable to derivatives, whose value is likely to change based on future oil and gas prices. Exaro's results of operations do not include income taxes because Exaro is treated as a partnership for tax purposes.

8. Long-Term Debt

RBC Credit Facility

In October 2013, the Company entered into a $500 million four-year revolving credit facility with Royal Bank of Canada and other lenders (the “bank group”) with an initial hydrocarbon supported borrowing base of $275 million. As part of the regular redetermination schedule, the Company’s bank group redetermined the Company’s borrowing base at $190 million effective

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November 13, 2015, primarily to reflect lower commodity prices and the impact of the significant reduction in the Company’s drilling program in 2015 attributable to the low price environment. The borrowing base under the facility is redetermined each November and May.

As of March 31, 2016 and December 31, 2015, the Company had approximately $112.2 million and $115.4 million, respectively, outstanding under the RBC Credit Facility and $1.9 million and $1.9 million, respectively, in outstanding letters of credit. As of March 31, 2016, borrowing availability under the RBC Credit Facility was $75.9 million.

Borrowings under the RBC Credit Facility bear interest at a rate that is dependent upon LIBOR, the U.S. prime rate, or the federal funds rate, plus a 0.5% to 2.5% margin, dependent upon the amount outstanding. Additionally, the Company must pay a commitment fee on the amount of the facility that remains unused, which varies from .375% to .5%, depending on the amount of the credit facility that is unused. Total interest expense under the RBC Credit Facility, including commitment fees, for the three months ended March 31, 2016 was approximately $0.9 million. Total interest expense under the RBC Credit Facility, including commitment fees, for the three months ended March 31, 2015 was approximately $0.7 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, 2016, the Company was in compliance with all covenants under the RBC Credit Facility, and at current commodity prices, does not expect any covenant compliance issues over the next twelve months. 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 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, 2016 and December 31, 2015 was 2.6% and 2.4%, respectively. The RBC Credit Facility matures on October 1, 2017, at which time any outstanding balances will be due.

Effective May 6, 2016, as part of the regular redetermination schedule, the borrowing base under the RBC Credit Facility was redetermined at $140 million, which reflects the impact of a decline in commodity prices from those used in connection with the last redetermination and the Company’s limited drilling program.  Also effective May 6, 2016, the RBC Credit Facility was amended to, among other things, extend the maturity of the facility from October 1, 2017 to October 1, 2019, increase the LIBOR, U.S. prime rate and federal funds rate margins to 2.5% - 4.0% and increase the commitment fee to 0.5%, regardless of the amount of the credit facility that is unused.  The Company paid fees totaling approximately $1.0 million to its lenders in connection with the amendment.

9. Income Taxes

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



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,

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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, 2016, the Company continues to fully value the net deferred tax asset. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.





10. Related Party Transactions

Republic Exploration LLC

Historically, REX, an entity owned 32.3% by Contango, participated with the Company in the drilling and development of certain prospects through participation agreements and joint operating agreements, which specified each participant’s working interest, net revenue interest and described when such interests were earned. The Company proportionately consolidated the results of REX in its consolidated financial statements prior to its dissolution as of December 31, 2015.

Olympic Energy Partners

In December 2012, Mr. Joseph J. Romano was elected President and Chief Executive Officer of the Company and in April 2013 was named Chairman of the Company. Upon the merger with Crimson Exploration Inc. (“Crimson”) on October 1, 2013, Mr. Romano resigned as President and Chief Executive Officer, but remains Chairman. Mr. Romano is also the President and Chief Executive Officer of Olympic Energy Partners LLC ("Olympic"). Olympic last participated with the Company in the drilling of wells in March 2010, and its ownership in Company-operated wells is limited to its Dutch and Mary Rose wells.



During the quarter ended March 31, 2016, Mr. Romano earned $14 thousand for his service as a director of the Company. During the quarter ended March 31, 2015, Mr. Romano earned $27 thousand for his service as a director of the Company.

During the years ended December 31,  2015 and 2014,  Mr. Romano received 4,534 and 2,612 shares of restricted stock, respectively, which both vest 100% on the one-year anniversary of the date of grant, as part of his board of director compensation.  Additionally, in January 2016, Mr. Romano received 261 shares of restricted stock, which vested immediately, pursuant to the Salary Replacement Program. The Company recognized compensation expense of approximately $19 thousand and $27 thousand related to the shares granted to Mr. Romano for the three months ended March 31, 2016 and March 31, 2015, respectively.  



Below is a summary of payments received from (paid to) Olympic and REX in the ordinary course of business in the Company’s capacity as operator of the wells and platforms for the periods indicated. The Company made and received similar types of payments with other well owners (in thousands): 



Below is a summary of payments received from Olympic and REX as a result of specific transactions between the Company, Olympic and REX. While these payments are in the ordinary course of business, the Company did not have similar transactions with other well owners (in thousands):



As of March 31, 2016 and December 31, 2015, the Company's consolidated balance sheets reflected the following balances (in thousands):





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Oaktree Capital Management L.P.

As of March 31, 2016, Oaktree Capital Management L.P. ("Oaktree"), through various funds, owned approximately 6.6% of the Company's stock. On October 1, 2013, Mr. James Ford, then a Managing Director and Portfolio Manager within Oaktree, was elected to the Company's board of directors. Mr. Ford is currently a Senior Advisor to Oaktree.

As part of Mr. Ford's director compensation, all cash and equity awards payable to Mr. Ford are instead granted to an affiliate of Oaktree. During the years ended December 31, 2015 and 2014, an affiliate of Oaktree received  4,534 and 2,612 shares of restricted stock, respectively, which both vest 100% on the one-year anniversary of the date of the grant. Additionally, in January 2016, an affiliate of Oaktree received 313 shares of restricted stock, which vested immediately, pursuant to the Salary Replacement Program.

During the three months ended March 31, 2016, the affiliate of Oaktree earned $17 thousand in cash as a result of Mr. Ford's board participation, and the Company recognized compensation expense of approximately $19 thousand related to the shares of restricted stock granted to an affiliate of Oaktree under the Director Compensation Plan. During the three months ended March 31, 2015, the affiliate of Oaktree earned $17 thousand in cash as a result of Mr. Ford's board participation, and the Company recognized compensation expense of approximately $27 thousand related to the shares of restricted stock granted to an affiliate of Oaktree under the Director Compensation Plan. 

11. 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 July 2010, several parties associated with a limited partnership formed to invest in oil and gas properties that was dissolved in 1995 filed suit against a subsidiary of the Company and several co-defendants in district court for Madison County in Texas.  The plaintiffs claim to own or have rights in certain oil and gas properties situated in Madison County, Texas by virtue of the partnership having interests in addition to those it held of record at the time of its dissolution, which were distributed to the partners in connection with such dissolution.  A predecessor of the subsidiary of the Company involved in this case acquired a portion of the interests now claimed by the plaintiffs from a successor to the general partner of the aforementioned partnership in 2000.  The plaintiffs’ expert has recently provided a range of estimated monetary damages of up to approximately $9.4 million as to our Subsidiary.  The Company is vigorously defending this lawsuit and believes that it has meritorious defenses.

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 us 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 is vigorously defending this lawsuit, believes that it has meritorious defenses and is appealing the trial court’s decision to the applicable state Court of Appeals.  

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 us 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 is appealing the trial court’s decision to the applicable state Court of Appeals. The Company is vigorously defending 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.



Mineral interest owners in South Louisiana filed suit against a subsidiary of the Company and several co-defendants in April 2013 in the 31st Judicial District Court situated in Jefferson Davis Parish, Louisiana alleging failure to act as a reasonably prudent operator, failure to explore, waste, breach of contract, etc. in connection with two wells located in Jefferson Davis Parish. Many of the alleged improprieties occurred prior to the Company’s ownership of an interest in the wells at issue, although the

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Company may have assumed liability otherwise attributable to its predecessors-in-interest through the acquisition documents relating to the acquisition of the Company’s interest in these wells. This case is based on the same actions and allegations as a prior case in which the Company and its co-defendants prevailed. The plaintiffs claim damages of approximately $2.5 million against a subsidiary of the Company and its co-defendants. The Company and its co-defendants are vigorously defending this lawsuit and believe they have a meritorious position.

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.

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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:





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Any of these factors and other factors described in this report could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us or on our behalf. Although we believe our estimates and assumptions to be reasonable when made, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. Our assumptions about future events may prove to be inaccurate. We caution you that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure you that those statements will be realized or the forward-looking events and circumstances will occur. All forward-looking statements speak only as of the date of this report.

We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

You should not unduly rely on these forward-looking statements in this report, as they speak only as of the date of this report. Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and the accompanying notes and other information included elsewhere in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2015 (our “2015 Form 10-K”), previously filed with the Securities and Exchange Commission ("SEC").

Overview

We are a Houston, Texas based, independent oil and natural gas company. Our business is to maximize production and cash flow in order to explore, develop, exploit and acquire crude oil and natural gas properties in the onshore Texas Gulf Coast and Rocky Mountain regions of the United States. 

The following table lists our primary producing areas as of March 31, 2016:

Additionally, we have (i) operated properties producing from various conventional formations in various counties along the Texas Gulf Coast; (ii) operated producing properties in the Denver Julesburg Basin (“DJ Basin”) in Weld and Adams counties in Colorado, which we believe may also be prospective in the Niobrara Shale oil play; and (iii) operated producing properties in the Haynesville Shale, Mid Bossier and James Lime formations in East Texas. 

Due to the current challenging commodity price environment, we intend to focus our 2016 capital program on: (i) the preservation of our healthy financial position, including limiting our overall capital expenditure budget to a minimal amount; (ii) focusing drilling expenditures, if any, on strategic projects; (iii) identification of opportunities for cost efficiencies in all areas of our operations; and (iv) continuing to identify new resource potential opportunities, internally and, where appropriate, through acquisition. We will continuously monitor the commodity price environment, stability and forecast, and, if warranted, make adjustments to our drilling strategy as the year progresses.

The following table lists the primary area to which we have allocated drilling capital for 2016:



In addition, we have allocated some geological and geophysical and leasehold capital to Madison and Grimes counties, Texas and Weston County, Wyoming.

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Capital Expenditures

As previously disclosed, due to the low and uncertain commodity price environment, we are focusing our drilling program for 2016 on strategic projects only.

Weston County, Wyoming

In June 2015, we announced the discovery and successful completion of the Elliot #1H well (80% WI) in the Muddy Sandstone formation in Weston County, Wyoming (referred to as our North Cheyenne Project).  In January 2016, we announced the discovery and successful completion of the Popham #1H well (80% WI) also in the Muddy Sandstone formation.  In March 2016, we began production from the Christensen #1H (80% WI), our third well in this area. 

We have not budgeted to drill any additional wells during 2016, but any future drilling plans in this area will be developed based on the results of these three wells and the commodity price environment. Approximately 200 to 300 Muddy Sandstone horizontal well locations may be prospective on our 49,000 gross acres (39,000 net) based on a drilling density of three to four wells per 640 acres. Additional prospective horizons in this area will be evaluated during the delineation phase with additional log and core data and could also add significantly to the total number of potential horizontal well locations.    

Impairment of Long-Lived Assets 



We recognized approximately $0.7 million in non-cash impairment charges in the current quarter primarily related to the reduction in the estimated value of future net cash flows of the Company’s risk adjusted proved, probable and possible reserves (3P reserves) due to the recent dramatic decline in commodity prices for crude oil and natural gas. Under Financial Accounting Standards Board Accounting Codifications, an impairment charge is required when the unamortized capital cost of any individual property within the company’s producing property base exceeds the risked estimated future net cash flows from the proved, probable and possible reserves for that property. Substantially all of the impairment charge in this quarter is directly related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated reserves. Also included in the impairment charge for the quarter is approximately $1.1 million related to unproved lease cost amortization on our Elm Hill project in Fayette and Gonzales counties Texas.



If oil and/or natural gas prices continue to decline, we may be required to record additional non-cash impairment in the future, thereby impacting our financial results for that period.

Summary Production Information

Our production for the three months ended March 31, 2016 was approximately 67% offshore and 33% onshore, and 68% natural gas, 15% oil and 17% natural gas liquids. Our production for the three months ended March 31, 2015 was 67% offshore and 33% onshore, and approximately 68% natural gas, 17% oil and 15% natural gas liquids.

The table below sets forth our average net daily production data in Mmcfe/d for each of our fields for each of the periods indicated:







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Other Investments

Kaybob Duvernay - Alberta, Canada

On August 1, 2013, our wholly-owned subsidiary, Alta Resources Investments, LLC (“Alta”) sold its interest in the liquids-rich Kaybob Duvernay Play in Alberta, Canada for approximately $30.5 million net to us. Of this amount, we have received $28.5 million, and expect to receive the remaining $2.0 million once approved by Canadian regulatory officials. 

Jonah Field - Sublette County, Wyoming 

Our wholly-owned subsidiary, Contaro Company (“Contaro”) currently has a 37% ownership interest in Exaro and has committed to invest up to $67.5 million in cash in Exaro. As of March 31, 2016, Contaro had invested approximately $46.9 million in Exaro.

As of March 31, 2016,  Exaro had 645 wells on production over its 5,760 gross acres (1,040 net), with a working interest between 14.6% and 32.5%. These wells were producing at a rate of approximately 33 Mmcfed, net to Exaro. Due to the persistent decline in natural gas prices, the operator does not expect to have any drilling rigs running on this project during 2016. For the quarter ended March 31, 2016, we recognized a net investment gain of approximately $40 thousand,  with an insignificant tax expense, as a result of our investment in Exaro. For the quarter ended March 31, 2015, we recognized a net investment gain of approximately $0.6 million, net of tax expense of $0.3 million. We do not anticipate making any additional equity contributions during 2016 as Exaro estimates drilling capital will be funded through internally generated cash flow and borrowings under its revolving credit facility. See Note 7 to our Financial Statements - “Investment in Exaro Energy III LLC” for additional details related to this investment.

Other

We intend to continue to evaluate potential acquisition opportunities to expand our presence in resource plays, to exploit our oil and liquids-rich positions and to continue to develop exploration and exploitation opportunities where commodity price-justified. Acquisition efforts will typically be focused on areas in which we can leverage our geographic and geological expertise to exploit identified drilling opportunities and where we can develop an inventory of additional drilling prospects that we believe will enable us to grow production and add reserves.

Results of Operations for the Three Months Ended March 31, 2016 and 2015

The table below sets forth revenue, production data, average sales prices and average production costs associated with our sales of natural gas, oil and natural gas liquids ("NGLs") from continuing operations for the three months ended March 31, 2016 and 2015. Oil, condensate and NGLs are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil, condensate or NGL is the energy equivalent of six thousand cubic feet (“Mcf”) of natural gas. Reported lease operating expenses include production taxes, such as ad valorem and severance taxes.







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Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015

Natural Gas, Oil and NGL Sales and Production

All of our revenues are from the sale of our natural gas, oil and NGL production. Our revenues may vary significantly from year to year depending on production volumes and changes in commodity prices, each of which may fluctuate widely. Our production volumes are subject to wide swings as a result of new discoveries, weather events, transportation and processing constraints, and mechanical problems. In addition, our production naturally declines over time as we produce our reserves.

We reported revenues of $17.6 million for the quarter ended March 31, 2016, compared to revenues of $30.6 million for the quarter ended March 31, 2015. The decrease in revenues was primarily attributable to: (i) a significant decline in commodity prices, which contributed approximately $7.4 million of the decrease in revenues and (ii) approximately $5.6 million due to lower production volumes resulting from a commodity price related reduction in drilling.

Total equivalent production was 79.4 Mmcfed for the quarter ended March 31, 2016, compared to 96.3 Mmcfed in the prior year quarter, a decrease attributable primarily to an 7.4 Mmcfed decline in production from the Dutch and Mary Rose Field due to normal field decline and a 5.7 Mmcfed decline in onshore production due to field declines related to the strategic decrease in our capital program during 2016 due to the low, and uncertain, commodity price environment.

Average Sales Prices

The average equivalent sales price realized for the quarter ended March 31, 2016 was $2.43 per Mcfe compared to $3.54 per Mcfe for the quarter ended March 31, 2015. This decrease was attributable primarily to the decrease in the realized price of oil to $28.39 per barrel, compared to $44.10 per barrel for the quarter ended March 31, 2015, and to the decrease in the realized price of natural gas to $2.02 per Mcf, compared to $2.87 per Mcf for the quarter ended March 31, 2015. 

Operating Expenses

Operating expenses for the quarter ended March 31, 2016 were approximately $7.6 million, or $1.05 per Mcfe, compared to $9.9 million, or $1.14 per Mcfe, for the quarter ended March 31, 2015.  The table below provides additional detail of operating expenses for the quarters ended March 31, 2016 and 2015:



Lease operating expenses decreased by 24% for the quarter ended March 31, 2016, compared to the quarter ended March 31, 2015, as a direct result of our efforts to reduce costs during this challenging commodity price environment.  

Exploration Expenses

Exploration expenses for the quarter ended March 31, 2016 were approximately $0.3 million. Exploration expenses for the quarter ended March 31, 2015 included a fee of  $3.2 million related to early termination of a drilling rig contract. 

Impairment Expenses

Impairment expenses for the quarter ended March 31, 2016 included a $0.7 million impairment of proved properties. Substantially all of the non-cash impairment charge in the quarter ended March 31, 2016 is directly related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated reserves. Impairment expenses for

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the quarter ended March 31, 2016 also included a $1.1 million impairment and partial impairment of certain unproved properties and onshore prospects due primarily to the sustained low commodity price environment and expiring leases, substantially all of which is related to unproved lease cost amortization of the Elm Hill project in Fayette and Gonzales counties Texas.

Impairment expenses for the quarter ended March 31, 2015 included producing property impairments of $2.0 million for small marginal natural gas properties as a result of commodity price declines. Impairment expense for the quarter ended March 31, 2015 also included a $0.2 million partial impairment of certain unproved prospects due to expiring leases.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for the quarter ended March 31, 2016 was approximately $16.5 million, or $2.29 per Mcfe. This compares to approximately $35.1 million, or $4.05 per Mcfe, for the quarter ended March 31, 2015.  The decrease in the depletion rate for 2016 is primarily attributable to the impairment recorded during the six months ended December 31, 2015.

General and Administrative Expenses

General and administrative expenses for the quarter ended March 31, 2016 were approximately $5.9 million, compared to $7.8 million for the quarter ended March 31, 2015. This reduction is a result of our ongoing cost cutting efforts necessitated by the current challenging commodity price environment. General and administrative expenses for the current quarter included approximately $1.7 million in non-cash stock based compensation, while the prior year quarter included $1.1 million in non-cash stock based compensation.  

Gain from Affiliates

For the quarter ended March 31, 2016, the Company recorded a gain from affiliates of approximately $40 thousand,  with an insignificant tax expense, related to our investment in Exaro, compared to a gain of $0.6 million, net of tax expense of $0.3 million, for the quarter ended March 31, 2015.  The decrease in 2016 was primarily attributable to the current challenging commodity price environment.



Capital Resources and Liquidity

During the quarter ended March 31, 2016, we incurred $3.4 million on capital projects, including $2.9 million for the completion of our third delineation well on our North Cheyenne Project in Weston County, Wyoming and $0.5 million for the acquisition of leases and other rights in new areas.

Our capital expenditure budget for 2016 is currently forecasted to be less than $10 million, including the amounts spent during the quarter ended March 31, 2016, and is expected to be funded from internally generated cash flow. 

Additionally, the Company often reviews acquisitions and prospects presented to us by third parties, and we may decide to invest in one or more of these opportunities. There can be no assurance that we will invest or that any investment we enter into will be successful. These potential investments are not part of our current capital budget and could require us to invest additional capital. Natural gas and oil prices continue to be volatile and our resources may not be sufficient to fund these opportunities.

Cash From Operating Activities

Cash flows from operating activities provided approximately $8.3 million in cash for the three months ended March 31, 2016  compared to $5.8 million used in operating activities for the same period in 2015. The table below provides additional detail of cash flows from operating activities for the three months ended March 31, 2016 and 2015:



Production from our wells, the price of oil and natural gas and operating costs represent the main drivers behind our cash flow from operations. Changes in working capital impact cash flows, and during the three months ended March 31, 2016, the working capital deficit normally associated with an active drilling program was reduced as we strategically lowered our drilling activity to preserve our healthy balance sheet.

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Cash From Investing Activities

Cash flows used in investing activities for the three months ended March 31, 2016 were approximately $4.8 million, all of which was used for capital expenditures related to drilling and/or completing wells and acquiring unproved leases in our areas of focus. Cash flows used in investing activities for the three months ended March 31, 2015 were approximately $35.3 million, all of which was used for capital expenditures related to drilling and/or completing wells and acquiring unproved leases in our areas of focus. Amounts presented include cash payments for accrued amounts at the beginning of each period.

Cash From Financing Activities

Cash flows used in financing activities for the three months ended March 31, 2016 were approximately $3.5 million, primarily related to the repayment of net borrowings under our credit facility with the Royal Bank of Canada and other lenders (the “RBC Credit Facility”). Cash flows provided by financing activities for the three months ended March 31, 2015 were approximately $41.1 million, primarily related to net borrowings under our RBC Credit Facility.

RBC Credit Facility 

In October 2013, the Company entered into a $500 million four-year revolving credit facility with Royal Bank of Canada and other lenders with an initial hydrocarbon supported borrowing base of $275 million, which is redetermined each November and May.  Effective November 13, 2015, as part of the regular redetermination schedule, the borrowing base was redetermined at $190 million, which reflected a decline in commodity prices from those used in connection with the previous redetermination.

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, 2016,  we were in compliance with all covenants under the RBC Credit Facility, and at current commodity prices, do not expect any covenant compliance issues over the next twelve months. 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 include, but are not limited to, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events.

Effective May 6, 2016, as part of the regular redetermination schedule, the borrowing base under the RBC Credit Facility was redetermined at $140 million, which reflects the impact of a decline in commodity prices from those used in connection with the last redetermination and our limited capital drilling program. Also effective May 6, 2016, the RBC Credit Facility was amended to, among other things, extend the maturity of the facility from October 1, 2017 to October 1, 2019, increase the LIBOR, U.S. prime rate and federal funds rate margins to 2.5% - 4.0% and increase the commitment fee to 0.5%, regardless of the amount of the credit facility that is unused. The Company paid fees totaling approximately $1.0 million to its lenders in connection with the amendment.

Sustained low prices and any further decline in prices will likely negatively impact the price decks utilized by banks in their calculation of the Company’s borrowing base at November 1, 2016. If our next borrowing base redetermination results in a lower borrowing base, we may be unable to obtain financing otherwise currently available under the RBC Credit Facility. See Note 8 to our Financial Statements – “Long-Term Debt” for further information regarding the RBC Credit Facility.

Application of Critical Accounting Policies and Management’s Estimates

Significant accounting policies that we employ and information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate are presented in Note 2 to our Financial Statements – “Summary of Significant Accounting Policies” of this report and in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – “Application of Critical Accounting Policies and Management’s Estimates” in our 2015 Form 10-K.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements, see Note 2 to our Financial Statements – “Summary of Significant Policies.”

Off Balance Sheet Arrangements

We may enter into off-balance sheet arrangements that can give rise to off-balance sheet obligations. As of March 31, 2016, the primary off-balance sheet arrangements that we have entered into are operating lease agreements, which are customary in the oil and gas industry. Other than the off-balance sheet arrangements shown under operating leases in the commitments and contingencies table included in our 2015 Form 10-K, we have no other off-balance sheet arrangements that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk

We are exposed to various risks including energy commodity price risk for our natural gas and oil production. When oil, natural gas and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. Our major commodity price risk exposure is to the prices received. Realized commodity prices received for our production are tied to the spot prices applicable to natural gas and crude oil at the applicable delivery points. Prices received for natural gas and oil are volatile and unpredictable. For the quarter ended March 31, 2016, a 10% fluctuation in the prices received for natural gas and oil production would have had an approximate $1.8 million impact on our revenues.

Derivative Instruments and Hedging Activity

We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management strategy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our cash flows. The types of derivative instruments that we typically utilize include swaps and costless collars. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge approximately 40% to 50% of forecasted production from proved developed producing reserves (excluding forecasted offshore production during hurricane season), at the time of hedging, for the following twelve to eighteen months. Our hedge strategy and objectives may change significantly as our operational profile changes and/or commodity prices change.

We are exposed to market risk on our open derivative contracts related to potential nonperformance by our counterparties. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The counterparties to the Company's current derivative contracts are large financial institutions and also lenders or affiliates of lenders in its RBC Credit Facility. We are not required to post collateral, or pay margin calls, under any of these contracts as they are secured under our RBC Credit Facility.

We have also been exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Currently, we do not have any derivative contracts to reduce the exposure to market rate fluctuations. At March 31, 2016, we did not have any open positions that converted our variable interest rate debt to fixed interest rates. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.

We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. The estimated fair values for financial instruments under ASC 825, Financial Instruments (“ASC 825”) 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, cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Note 4 to our Financial Statements - "Derivative Instruments" for more details. As of March 31, 2016, we have 8,550,000  MMBtu of natural gas production hedged between April 1, 2016 and December 31, 2016 at an average Henry Hub price of $2.53/MMBtu.  In April 2016, we entered into financial derivative contracts with a member of our bank group resulting in 400,000 MMBtus of natural gas per month being hedged from January 2017 through July 2017 and from November 2017 through December 2017, and 200,000 MMBtus of natural gas per month being hedged from August 2017 through October 2017 through collars at a floor price of $2.65/MMBtu.

Interest Rate Sensitivity

We are exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and US Prime based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

As of March 31, 2016, our total long-term debt was $112.2 million, which bears interest at a floating or market interest rate that is tied to the prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. During the quarter ended March 31, 2016, our effective rates fluctuated between 2.3 percent and 4.5 percent, depending on the term of the specific debt drawdowns. At March 31, 2016, we did not have any outstanding interest rate swap agreements. As of March 31, 2016, the weighted average interest rate on our variable rate debt was 2.57% per year. Assuming our current level of borrowings, a 100 basis point increase in the interest rates we pay under our RBC Credit Facility would result in an increase of our interest expense by $0.3 million for the three month period.

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Other Financial Instruments

As of March 31, 2016, we had no cash or cash equivalents based on our cash management policy. Investments in fixed-rate, interest-earning instruments carry a degree of interest rate and credit rating risk. Fixed-rate securities may have their fair market value adversely impacted because of changes in interest rates and credit ratings. Additionally, the value of our investments may be impaired temporarily or permanently. Due in part to these factors, our investment income may decline and we may suffer losses in principal. Currently, we do not use any derivative or other financial instruments or derivative commodity instruments to hedge any market risks, including changes in interest rates or credit ratings, and we do not plan to employ these instruments in the future. Because of the nature of the issuers of the securities that we invest in, we do not believe that we have any cash flow exposure arising from changes in credit ratings. Based on a sensitivity analysis performed on the financial instruments held as of March 31, 2016, an immediate 10% change in interest rates would result in a $0.3 million change on our near-term financial condition or results of operations.

Item 4. Controls and Procedures

Our President and Chief Executive Officer, together with our Chief Financial Officer and Chief Accounting Officer, carried out an evaluation of the effectiveness of the Company’s “disclosure controls and procedures” as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of March 31, 2016. Based upon that evaluation, the Company’s management concluded that, as of March 31, 2016, the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and to ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our President and Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in the Company’s internal control over financial reporting that occurred during the three months ended March 31, 2016 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of legal proceedings, see Note 11 to our Financial Statements – “Commitments and Contingencies.”

Item 1A. Risk Factors

For discussion regarding our risk factors, see Item 1A of Part 1 of our Annual Report on Form 10-K for the year ended December 31, 2015. Those risk and uncertainties are not the only ones facing us, and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The Company repurchased the following shares from employees for the payment of withholding taxes due on shares of restricted stock that vested and was issued under its stock-based compensation plans:



Item 3. Defaults upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

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Item 5. Other Information

None.

Item 6. Exhibits

(a) Exhibits:

The exhibits listed on the accompanying Exhibit Index are filed, furnished or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereto duly authorized.

 







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