UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-Q

 

For the quarterly period ended March 31, 2017

or

For the transition period from _______________ to ________________

Commission File Number 1-32414

 

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)

 

(713) 626-8525

(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 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.

Indicate by check mark whether the registrant is a shell company.    Yes  ☐    No  ☑  

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 or Rule 12b-2 of the Securities Exchange Act of 1934.   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.   ☐

As of May 1, 2017, there were 137,674,372 shares outstanding of the registrant’s common stock, par value $0.00001.

 

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

 

 

 

 

 

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PART I – FINANCIAL INFORMATION

Item 1.  Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

 

See Notes to Condensed Consolidated Financial Statements

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

See Notes to Condensed Consolidated Financial Statements.

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ DEFICIT

 

 

See Notes to Condensed Consolidated Financial Statements.

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

See Notes to Condensed Consolidated Financial Statements.

 

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.  Basis of Presentation

Operations.  W&T Offshore, Inc. (with subsidiaries referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”) is an independent oil and natural gas producer with operations primarily offshore in the Gulf of Mexico.  The Company is active in the exploration, development and acquisition of oil and natural gas properties.  Our interest in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and its 100%-owned subsidiary, W & T Energy VI, LLC (“Energy VI”).  

Interim Financial Statements.  The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim periods and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).  Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by GAAP for complete financial statements for annual periods.  In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included.

Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year.  These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

Use of Estimates.  The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Actual results could differ from those estimates.

Recent Events.  The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital, proved reserves and future rate of growth.  The average prices of these commodities improved during the first quarter of 2017 compared to the average prices in the first quarter and year 2016.  Operating costs were lower than the first quarter of 2017 on a barrel equivalent (“Boe”) basis compared to the first quarter of 2016.  In September 2016, we consummated the Exchange Transaction, as defined and described below in Note 2, which reduced our interest payments in the first quarter of 2017 compared to the first quarter of 2016.  In addition, the Exchange Transaction extended the maturities on a portion of our debt, although for a portion of the New Debt, as defined and described below, the maturities may accelerate if certain events do not transpire.

We continued working to further reduce our operating costs, capital expenditures and costs related to asset retirement obligations (“ARO”).  Our 2017 capital budget is conservative and flexible.  The 2017 capital budget is higher than the capital expenditures incurred during 2016, but it is significantly lower than spending levels incurred during 2015 and 2014.  

 

 

    

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 

During the first quarter of 2017, the Bureau of Ocean Energy Management (“BOEM”) extended the implementation timeline by an additional six months for Notice to Lessees #2016-N01 (“NTL #2016-N01”) as to Outer Continental Shelf (“OCS”) leases, rights-of-way (“ROWs”) or rights of use and easement (“RUEs”) for which there are co-lessees and/or predecessors in interest (non-sole liability properties), with certain exceptions.  Also, in the first quarter of 2017, the BOEM withdrew the orders related to its so called “sole liability” properties it had issued in December 2016 to allow time for the new President’s administration to review the complex financial assurance program.  We continue to have discussions with the BOEM regarding these matters.  See Note 9 for additional information.    

We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices.  We believe we will have adequate liquidity to fund our operations beyond May 2018, the period of assessment to qualify as a going concern.  However, we cannot predict the potential changes in commodity prices or the future bonding requirements, either of which could affect our operations, liquidity levels and compliance with debt covenants.

See our Annual Report on Form 10-K for the year ended December 31, 2016 concerning risks related to our business and events occurring during 2016 and other information and the Notes herein for additional information.  

Prepaid Expenses and Other.  The amounts recorded in Prepaid expenses and other are expected to be realized within one year.  The major categories are presented in the following table (in thousands):

 

Oil and natural gas properties and other, net – at cost:  Oil and natural gas properties and equipment are recorded at cost using the full cost method.  There were no amounts excluded from amortization as of the dates presented in the following table:

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 

Accrued liabilities.  The major categories recorded in Accrued liabilities are presented in the following table (in thousands):

 

Recent Accounting Developments.  In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments That Create Revenue from Contracts and Customers (Subtopic 606).  ASU 2014-09 amends and replaces current revenue recognition requirements, including most industry-specific guidance.  The revised guidance establishes a five step approach to be utilized in determining when, and if, revenue should be recognized.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017.  Upon application, an entity may elect one of two methods, either restatement of prior periods presented or recording a cumulative adjustment in the initial period of application.  Our current intention is to adopt the standard utilizing the modified retrospective approach.  Our evaluation to date is the adoption of ASU 2014-09 is not expected to have a material impact on our consolidated financial statements.  We have not fully completed our analysis and subsequent guidance may change this assessment.  Our disclosures related to revenue will be modified when the new guidance is effective.  ASU 2014-09 will be effective for us in the first quarter of 2018.

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases (Subtopic 842).  Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Consistent with current GAAP, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease.  However, unlike current GAAP, which requires only capital leases to be recognized on the balance sheet, ASU 2016-02 will require both types of leases to be recognized on the balance sheet.  ASU 2016-02 also will require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases.  These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements.  ASU 2016-02 does not apply for leases for oil and gas properties, but does apply to equipment used to explore and develop oil and gas resources.  Our current operating leases that will be impacted by ASU 2016-02 are leases for office space in Houston, Texas and New Orleans, Louisiana, although ASU 2016-02 may impact the accounting for leases related to equipment depending on the term of the lease.  We currently do not have any leases classified as financing leases.  ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective approach.  We have not yet fully determined or quantified the effect ASU 2016-02 will have on our financial statements.

In June 2016, the FASB issued Accounting Standards Update No. 2016-13, (“ASU 2016-13”), Financial Instruments – Credit Losses (Subtopic 326).  The new guidance eliminates the probable recognition threshold and broadens the information to consider past events, current conditions and forecasted information in estimating credit losses.  ASU 2016-13 is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted for fiscal years beginning after December 15, 2018.  We have not yet fully determined or quantified the effect ASU 2016-13 will have on our financial statements.

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

In August 2016, the FASB issued Accounting Standards Update No. 2016-15, (“ASU 2016-15”), Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments.  ASU 2016-15 addresses the classification of several items that previously had diversity in practice.  Items identified in the new standard which were incurred by us in the past are: (a) debt prepayment or extinguishment costs; (b) contingent consideration made after a business acquisition; and (c) proceeds from settlement of insurance claims.  The item described in clause (b) would be the only such item changed under our historical classification in the statement of cash flows (financing vs. investing) and the amount of such change would not have been material; therefore, we do not anticipate the new standard will have a material effect on our reports.  ASU 2016-15 is effective for fiscal years beginning after December 15, 2017 and early adoption is permitted.

In November 2016, the FASB issued Accounting Standards Update No. 2016-18, (“ASU 2016-18”), Statement of Cash Flows (Topic 230) – Restricted Cash.  ASU 2016-18 addresses diversity in practice and requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.  ASU 2016-18 is expected to change some of the presentation in our statement of cash flows, but not materially impact total cash flows from operating, investing or financing activities.  ASU 2016-18 is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years.  Early adoption is permitted, including adoption in an interim period.

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

2.  Long-Term Debt

The components of our long-term debt are presented in the following table (in thousands):

 

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Exchange Transaction

On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our 8.500% Senior Notes, due June 15, 2019 (the “Unsecured Senior Notes”)for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Senior Second Lien PIK Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); (ii) $142.0 million in aggregate principal amount of 8.50%/10.00% Senior Third Lien PIK Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”); and (iii) 60.4 million shares of our common stock (collectively, the “Debt Exchange”).  At the same time on closing on the Debt Exchange, we closed on a $75.0 million, 11.00% 1.5 Lien Term Loan, due November 15, 2019, (the “1.5 Lien Term Loan”) with the largest holder of our Unsecured Senior Notes (collectively with the Debt Exchange, the “Exchange Transaction”).  We accounted for the Exchange Transaction as a Troubled Debt Restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring (“ASC 470-60”).  Under ASC 470-60, the carrying value of the newly issued Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “New Debt”) is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Condensed Consolidated Statements of Operations during the three months ended March 31, 2017.  Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt.    

The funds received from the 1.5 Lien Term Loan were used to pay transaction costs related to the Exchange Transaction and to pay down borrowings on the revolving bank credit facility.  The balance of the borrowings on the revolving bank credit facility was paid down from available cash.

The primary terms of our long-term debt following the Exchange Transaction are described below.    

Credit Agreement

The Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), provides a revolving bank credit facility.  The primary items of the Credit Agreement are as follows, with certain terms defined under the Credit Agreement:

Availability under our revolving bank credit facility is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  The 2017 spring redetermination reaffirmed the borrowing base amount.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility.  The revolving bank credit facility is secured and is collateralized by a first priority lien on substantially all of our oil and natural gas properties.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

The Credit Agreement contains various customary covenants for certain financial tests, as defined in the Credit Agreement and measured as of the end of each quarter, and for customary events of default.  As of March 31, 2017, we were in compliance with all applicable ratios.  The customary events of default include: (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to the Company or any of its subsidiaries guaranteeing borrowings under the revolving bank credit facility; or (iii) a change of control.  The Credit Agreement contains cross-default clauses with the other long-term debt agreements, and such agreements contain similar cross-default clauses with the Credit Agreement.  We were in compliance with all applicable covenants of the Credit Agreement as of March 31, 2017.

  As of March 31, 2017 and December 31, 2016, we did not have any borrowings outstanding.  As of both March 31, 2017 and December 31, 2016, we had $0.5 million of letters of credit outstanding under the revolving bank credit facility at both dates.  Availability as of March 31, 2017 was $149.5 million.

1.5 Lien Term Loan

As part of the Exchange Transaction, we entered into the 1.5 Lien Term Loan on September 7, 2016 with a maturity date of November 15, 2019.  The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019. Interest accrues at 11.00% per annum and is payable quarterly in cash.  The holder of the 1.5 Lien Term Loan was the largest holder of our Unsecured Senior Notes prior to the Exchange Transaction.  The 1.5 Lien Term Loan is secured by a 1.5 priority lien on all of our assets pledged under the Credit Agreement.  The lien securing the 1.5 Lien Term Loan is subordinate to the liens securing the Credit Agreement and has priority above the liens securing the Second Lien Term Loan (defined below), the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes.  All future undiscounted cash flows have been included in the carrying value under ASC 470-60.  Current maturities of long-term debt represent the cash interest payable for the 1.5 Lien Term Loan payable in the next 12 months.  The 1.5 Lien Term Loan contains various covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) enter into certain liens; and (vii) enter into transactions with affiliates.  We were in compliance with those covenants as of March 31, 2017.

Second Lien Term Loan

In May 2015, we entered into the 9.00% Term Loan (the “Second Lien Term Loan”), which bears an annual interest rate of 9.00%, was issued at a 1.0% discount to par and matures on May 15, 2020 and is recorded at its carrying value consisting of principal, unamortized discount and unamortized debt issuance costs.  Interest on the Second Lien Term Loan is payable in arrears semi-annually on May 15 and November 15.  The estimated annual effective interest rate on the Second Lien Term Loan is 9.6%, which includes amortization of debt issuance costs and discounts.  The Second Lien Term Loan is secured by a second-priority lien on all of our assets that are secured under the Credit Agreement.  The Second Lien Term Loan is effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu with the Second Lien PIK Toggle Notes (discussed below).  The Second Lien Term Loan contains covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with those covenants as of March 31, 2017.

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Second Lien PIK Toggle Notes

As part of the Exchange Transaction, we issued Second Lien PIK Toggle Notes on September 7, 2016, with a maturity date of May 15, 2020.  Cash interest accrues at 9.00% per annum and is payable on May 15 and November 15 of each year.  The Second Lien PIK Toggle Notes contain PIK interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period.  We have the option for the first 18 months to pay all or a portion of interest in kind at a rate of 10.75% per annum.  The Second Lien PIK Toggle Notes are secured by a second-priority lien on all of our assets that are pledged under the Credit Agreement.  The Second Lien PIK Toggle Notes are effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu with the Second Lien Term Loan (discussed above).  For purposes of determining the carrying amount under ASC 470-60, we assumed we will elect full use of the PIK option and these amounts will increase the principal amount.  The Second Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with those covenants as of March 31, 2017.    

Third Lien PIK Toggle Notes

As part of the Exchange Transaction, we issued Third Lien PIK Toggle Notes on September 7, 2016, with a maturity date of June 15, 2021.  The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  Cash interest accrues at 8.50% per annum and is payable on June 15 and December 15 of each year.  The Third Lien PIK Toggle Notes contain PIK interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period.  We have the option for the first 24 months to pay all or a portion of interest in kind at a rate of 10.00% per annum.  The Third Lien PIK Toggle Notes are secured by a third-priority lien on all of our assets that are secured under the Credit Agreement.  The Third Lien PIK Toggle Notes are effectively subordinate to the Second Lien Term Loan and the Second Lien PIK Toggle Notes.  For purposes of determining the carrying value under ASC 470-60, we assumed we will elect full use of the PIK option and these amounts will increase the principal amount.  The Third Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with those covenants as of March 31, 2017.

Unsecured Senior Notes

Our outstanding Unsecured Senior Notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019, were recorded at their carrying value, which includes unamortized debt premium and unamortized debt issuance costs.  Interest on the Unsecured Senior Notes is payable semi-annually in arrears on June 15 and December 15.  The estimated annual effective interest rate on the Unsecured Senior Notes is 8.3%, which includes amortization of premiums and debt issuance costs.  The Unsecured Senior Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.  We were in compliance with those covenants as of March 31, 2017.  

For information about fair value measurements for our long-term debt, refer to Note 3.

 

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

3.  Fair Value Measurements  

We measure the fair value of our open derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy.  The inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads, credit risk and published commodity futures prices.  The fair value of the 1.5 Lien Term Loan was estimated using the carrying value of the principal as no market has developed and the holder of the 1.5 Lien Term Loan was the largest holder of our Unsecured Senior Notes prior to the Exchange Transaction.  The fair values of our Second Lien Term Loan, Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and Unsecured Senior Notes were based on quoted prices, although the market is not an active market; therefore, the fair value is classified within Level 2.  

The following table presents the fair value of our open derivatives and long-term debt, all of which are classified as Level 2 within the valuation hierarchy (in thousands):

 

4.  Asset Retirement Obligations

Our ARO primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives.  

A summary of the changes to our ARO is as follows (in thousands):  

 

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

5.  Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and, from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our oil and natural gas.  All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility.  We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations.  Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders, and we do not require collateral from our derivative counterparties.

We have elected not to designate our commodity derivative contracts as hedging instruments; therefore, all changes in the fair value of derivative contracts were recognized currently in earnings during the periods presented.  The cash flows of all of our commodity derivative contracts are included in Net cash provided by operating activities on the Condensed Consolidated Statements of Cash Flows.

For information about fair value measurements, refer to Note 3.

Commodity Derivatives

As of March 31, 2017, we had open crude oil and natural gas derivative contracts for a portion of our anticipated future production for the remainder of 2017.  These contracts were entered into during the first quarter of 2017.  For crude oil, we entered into two types of contracts.  The first type is a swap contract, where we either receive or pay depending on whether the crude oil price is below or above the contract price.   The second type is known as “two-way collar” consisting of a purchased put option and a sold call option.  These two-way collars provide price risk protection if commodity prices fall below certain levels, but may limit incremental income from favorable price movements above certain limits.  The crude oil contracts are based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”).  For natural gas, we entered into “two-way collar” contracts.  The natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX.  The strike prices of both the oil and natural gas two-way collar contracts were set so that the contracts were premium neutral (“costless”), which means no net premium was paid to or received from a counterparty.  Settlement occurs monthly using the per day notional quantity.  As of December 31, 2016, we did not have any open derivative contracts.    

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

As of March 31, 2017, our open commodity derivative contracts were as follows:

 

Our open and closed (not settled) commodity derivative contracts were recorded within the line Prepaid and other assets on the Condensed Consolidated Balance Sheets summarized in the following table (in thousands):

 

Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands):

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 

Cash receipts, net, on commodity derivative contract settlements are included within Net cash provided by operating activities on the Condensed Consolidated Statements of Cash Flows and were as follows (in thousands):

 

Offsetting Commodity Derivatives

All our commodity derivative contracts permit netting of derivative gains and losses upon settlement.  In general, the terms of the contracts provide for offsetting of amounts payable or receivable between us and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same commodity.  If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility, that event may also trigger an acceleration of settlement of our derivative instruments.  If we were required to settle all of our open derivative contracts, we would be able to net payments and receipts per counterparty pursuant to the derivative contracts.  Although our derivative contracts allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we have historically accounted for our derivative contracts on a gross basis per contract as either an asset or liability.  

6.  Share-Based Compensation and Cash-Based Incentive Compensation

Awards to Employees.  In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholders, and amendments to the Plan were approved by our shareholders in May 2013 and in May 2016.  The May 2016 amendment increased the number of shares available in the Plan by 3,300,000 shares.  As allowed by the Plan, during the three months ended March 31, 2017 and the years 2016 and 2015, the Company granted restricted stock units (“RSUs”) to certain of its employees.  RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period based on the results of certain predetermined criteria.  In addition to share-based compensation, the Company may grant to its employees cash-based incentive awards, which are a short-term component of the Plan and are typically based on the Company and the employee achieving certain pre-defined performance criteria.

As of March 31, 2017, there were 6,933,337 shares of common stock available for issuance in satisfaction of awards under the Plan.   The shares available for issuance are reduced when RSUs are settled in shares of common stock, net of withholding tax.  Although the Company has the option at vesting to settle RSUs in stock or cash, or a combination of stock and cash, only common stock has been used to settle vested RSUs to date.

RSUs currently outstanding related to the 2016 and 2015 grants have been adjusted for performance achieved against predetermined criteria for the applicable performance year.  These RSUs continue to be subject to employment-based criteria and vesting occurs in December of the second year after the grant.  The RSUs related to the 2017 grants are subject to performance-based criteria and employment-based criteria.  See the second table below for potential vesting by year.

We recognize compensation cost for share-based payments to employees over the period during which the recipient is required to provide service in exchange for the award.  Compensation cost is based on the fair value of the equity instrument on the date of grant.  The fair values for the RSUs granted during 2017, 2016 and 2015 were determined using the Company’s closing price on the grant date.  We are also required to estimate forfeitures, resulting in the recognition of compensation cost only for those awards that are expected to actually vest.

All RSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period.  

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

A summary of activity in 2017 related to RSUs is as follows:

 

 

For the outstanding RSUs issued to the eligible employees as of March 31, 2017, vesting is expected to occur as follows:  

 

The fair value of Restricted Stock Units granted during the three months ended March 31, 2017 was $5.8 million based on the Company’s closing price on the date of grant.

Awards to Non-Employee Directors.  Under the Director Compensation Plan, shares of restricted stock (“Restricted Shares”) have been granted to the Company’s non-employee directors.  Grants to non-employee directors were made during 2016, 2015 and 2014.  As of March 31, 2017, there were 317,896 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan.  The shares available are reduced when Restricted Shares are granted.  

We recognize compensation cost for share-based payments to non-employee directors over the period during which the recipient is required to provide service in exchange for the award.  Compensation cost is based on the fair value of the equity instrument on the date of grant.  The fair values for the Restricted Shares granted were determined using the Company’s closing price on the grant date.   No forfeitures were estimated for the non-employee directors’ awards.

The Restricted Shares are subject to service conditions and vesting occurs at the end of specified service periods unless approved by the Board of Directors.  Restricted Shares cannot be sold, transferred or disposed of during the restricted period.  The holders of Restricted Shares generally have the same rights as a shareholder of the Company with respect to such Restricted Shares, including the right to vote and receive dividends or other distributions paid with respect to the Restricted Shares.  

For the outstanding Restricted Shares issued to the non-employee directors as of March 31, 2017, vesting is expected to occur as follows:

 

There were no grants, forfeitures or vesting of Restricted Shares during the three months ended March 31, 2017.

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

  Share-Based Compensation.  Share-based compensation expense is recorded in the line General and administrative expenses in the Condensed Consolidated Statements of Operations.  A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands):

 

 

Unrecognized Share-Based Compensation.  As of March 31, 2017, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $12.6 million and $0.3 million, respectively.  Unrecognized share-based compensation expense will be recognized through November 2019 for RSUs and April 2019 for Restricted Shares.

Cash-Based Incentive Compensation. As defined by the Plan, annual incentive awards may be granted to eligible employees and are typically payable in cash.  These awards are performance-based awards consisting of one or more business or individual performance criteria and a targeted level or levels of performance with respect to each such criterion.  Generally, the performance period is the calendar year and determination and payment is made in cash in the first quarter of the following year.  

During 2017, 2016 and 2015, the Company issued cash-based incentive awards that, in addition to being performance-based awards related to respective 2017, 2016 and 2015 criteria, the payment of such awards is contingent on the Company achieving the following financial condition on or before December 31, 2019, December 31, 2018 and December 31, 2017, respectively:  Adjusted EBITDA less Interest Expense, as reported by the Company in its announced Earnings Release with respect to the end of any fiscal quarter plus three preceding quarters, exceeds $200.0 million for the 2017 awards and exceeds $300.0 million for the 2016 and 2015 awards.  As the Company did not achieve either financial condition up through March 31, 2017, no amounts have been recognized to date related to the 2017, 2016 and 2015 cash-based incentive awards.         

7.  Income Taxes

Our income tax benefit for the three months ended March 31, 2017 and 2016 was $7.6 million and $4.9 million, respectively.  Our annualized effective tax rate for both periods was not meaningful.  The income tax benefit for both periods relates to net operating loss (“NOL”) carryback claims made pursuant to Internal Revenue Code (“IRC”) Section 172(f) (related to rules for “specified liability losses”), which permit certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.

During the three months ended March 31, 2017 and 2016, we did not pay any income tax or receive any income tax refunds of significance.         

 As of March 31, 2017 and December 31, 2016, our valuation allowance was $276.5 million and $290.2 million, respectively, related to Federal, Louisiana and Alabama NOL’s and other deferred taxes.  Net deferred tax assets were recorded related to NOL’s and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods.  The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or NOL’s are deductible.  In addition, the realization depends on the ability to carryback certain items to prior years for refunds of taxes previously paid.  In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.  

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

As of March 31, 2017 and December 31, 2016, we recorded current income tax receivables of $11.9 million and non-current income tax receivables of $59.8 million and $52.1 million, respectively.  The current income tax receivables primarily relates to our NOL claim for 2016 carried back to 2006.  The non-current income tax receivables relates to our NOL claims for the years 2012, 2013 and 2014 that were carried back to prior years filed on Form 1120X, U.S. Corporation Income Tax Return and to an estimated NOL claim for 2017 that is expected to be filed subsequent to December 31, 2017.  These carryback claims are made pursuant to IRC Section 172(f) described above.  The refund claims filed on Form 1120X will require a review by the Congressional Joint Committee on Taxation and are accordingly classified as non-current.

We recognize interest and penalties related to unrecognized tax benefits in income tax expense.  During the three months ended March 31, 2017 and 2016, we recorded immaterial amounts of accrued interest expense related to our unrecognized tax benefit.

The tax years 2013 through 2016 remain open to examination by the tax jurisdictions to which we are subject.   

8.  Earnings/ (Loss) Per Share

The following table presents the calculation of basic and diluted earnings (loss) per common share (in thousands, except per share amounts):

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

9.  Contingencies  

Supplemental Bonding Requirements by the BOEM.  The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS.  In July 2016, the BOEM issued NTL #2016-N01 to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs or RUEs.  This NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07.

As suggested by the BOEM in its January and February 2017 notices, we intend to use the six month extension granted by the BOEM as an opportunity to propose and negotiate acceptable plans dealing with both sole and non-sole liability properties.

Surety Bond Collateral.  The issuers of surety bonds in some cases have requested and received additional collateral related to surety bonds for plugging and abandonment activities.  We may be required to post collateral at any time pursuant to the terms of our agreement with various sureties under our existing bonds, if they so demand at their discretion.  We did not receive any additional collateral demands from surety bond providers during the three months ended March 31, 2017.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Notification by ONRR of Fine for Non-compliance.  In December 2013 and January 2014, we were notified by the Office of Natural Resources Revenue (“ONRR”) of an underpayment of royalties on certain Federal offshore oil and gas leases that cumulatively approximated $30,000 over several years, which represents 0.0045% of royalty payments paid by us during the same period of the underpayment.  In March 2014, we received notice from the ONRR of a statutory fine of $2.3 million (subsequently reduced to approximately $1.1 million) relative to such underpayment.  We believe the fine is excessive considering the circumstances and in relation to the amount of underpayment.  A hearing on this matter was held with an Administrative Law Judge in August 2016.  A decision on this case has been deferred and we are unable to estimate when a decision will be rendered.  The ultimate resolution may result in a waiver of the fine, a reduction of the fine, or payment of the full amount plus interest covering several years.  As no amount has been determined as more likely than any other within the range of possible resolutions, no amount was accrued as of March 31, 2017 or December 31, 2016.

Apache Lawsuit.   On December 15, 2014, Apache Corporation (“Apache”) filed a lawsuit against W&T Offshore, Inc., alleging that W&T breached the joint operating agreement related to, among other things, the abandonment of deepwater wells in the Mississippi Canyon (“MC”) area of the Gulf of Mexico.  On October 28, 2016, the jury made the following findings:

In November 2016 we filed a motion with the trial court requesting a judgment consistent with the jury’s finding that Apache acted in bad faith thereby causing W&T not to comply with the contract, which W&T asserted bars Apache from recovery for damages under applicable law, and if damages are not barred in their entirety, that any judgment for monetary damages should be offset by $17.0 million as determined by the jury. After Apache filed its opposing motion, a hearing was held by the trial court in December 2016.  As of the filing date of this Quarterly Report on Form 10-Q (“Form 10-Q”), no judgment has been entered by the court.  

Appeal with ONRR.   In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems.  In 2010, the ONRR audited our calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken.  We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR.  We filed an appeal with the ONRR, which was denied in May 2014.  On June 17, 2014, we filed an appeal with the IBLA under the Department of the Interior.  On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties.  We are reviewing the decision with counsel to determine an appropriate course of action.

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Royalties – “Unbundling” Initiative.  The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases.  The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant for which we had gas processed.  In the second quarter of 2015, pursuant to the initiative, we received requests from the ONRR for additional data regarding our transportation and processing allowances on natural gas production related to a specific processing plant.  We also received a preliminary determination notice from the ONRR asserting that our allocation of certain processing costs and plant fuel use at another processing plant were not allowed as deductions in the determination of royalties owed under Federal oil and gas leases.  We have submitted revised calculations covering certain plants and time periods to the ONRR.  As of the filing date of this Form 10-Q, we have not received a response from the ONRR related to our submissions.  These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under our Federal oil and gas leases for current and prior periods.  To date, our revised calculations for one plant covering part of the 84 month period did not result in a material payment.  We are not able to determine the range of any additional royalties or, if and when assessed, whether such amounts would be material.

Notices of Proposed Civil Penalty Assessment.  As of March 31, 2017, we had five open civil penalties issued by the Bureau of Safety and Environmental Enforcement (“BSEE”) arising from Incidents of Noncompliance (“INCs”), which have not been settled as of the filing of this Form 10-Q.  The INC’s underlying the civil penalties relate to separate offshore locations with occurrence dates ranging from July 2012 to March 2016.  The proposed civil penalties for these INCs total $8.3 million.  During the three months ended March 31, 2017, we did not make any payments related to civil penalties.  We have accrued approximately $2.0 million, which is our best estimate of the final settlement once all appeals have been exhausted.  Our position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these INCs.    

Iberville School Board Lawsuit.  In August 2013, a citation was issued on behalf of plaintiffs, the State of Louisiana and the Iberville Parish School Board, in their suit against us (among others) in the 18^th Judicial District Court for the Parish of Iberville, State of Louisiana.  This case involves claims by the Iberville Parish School Board that certain property in Louisiana had allegedly been contaminated or otherwise damaged by certain defendants’ oil and gas exploration and production activities.  The plaintiff’s claims include assessment costs, restoration costs, diminution of property value, punitive damages, and attorney fees and expenses, of which were not quantified in the claim.  The case was set for trial on August 15, 2016, but the trial date has been deferred.  Our assessment is our potential exposure related to this lawsuit is not material, although our assessment may ultimately prove to be inaccurate.  We intend to vigorously defend ourselves in this litigation.

Other Claims.  We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business.  In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties.  In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold.  We are also subject to federal and state administrative proceedings conducted in the ordinary course of business including matters related to alleged royalty underpayments on certain federal-owned properties.  Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

 

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

10.  Supplemental Guarantor Information

Our payment obligations under the Credit Agreement, the 1.5 Lien Term Loan, the Second Lien Term Loan, the Second Lien PIK Toggle Notes, the Third Lien PIK Toggle Notes and the Unsecured Senior Notes (see Note 2) are fully and unconditionally guaranteed by certain of our 100%-owned subsidiaries, including Energy VI and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”).  W & T Energy VII, LLC does not currently have any active operations or contain any assets.  Guarantees will be released under certain circumstances, including:  

The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis.  As to the ceiling test write-down recorded in 2016, the computation is performed for each subsidiary on a stand-alone basis and also for the consolidated Company.  Due to this methodology, consolidating adjustments are required to present the consolidated results appropriately.  

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Condensed Consolidating Balance Sheet as of March 31, 2017

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 

Condensed Consolidating Balance Sheet as of December 31, 2016

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 

Condensed Consolidating Statement of Operations for the Three Months Ended March 31, 2017

 

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 

 

Condensed Consolidating Statement of Operations for the Three Months Ended March 31, 2016

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

Condensed Consolidating Statement of Cash Flows for the Three Months Ended March 31, 2017

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 

Condensed Consolidating Statement of Cash Flows for the Three Months Ended March 31, 2016

 

 

 

 

 

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

Forward-Looking Statements

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q.  The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (“the “Exchange Act”). These forward-looking statements involve risks, uncertainties and assumptions.  If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions.  All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future.  These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances.  Known material risks that may affect our financial condition and results of operations are discussed in Item 1A, Risk Factors, and market risks are discussed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of our Annual Report on Form 10-K for the year ended December 31, 2016 and may be discussed or updated from time to time in subsequent reports filed with the SEC.  Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We assume no obligation, nor do we intend to update these forward-looking statements.  Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries and references to “Parent Company” are solely to W&T Offshore, Inc.

Overview

We are an independent oil and natural gas producer, active in the exploration, development and acquisitions of oil and natural gas properties in the Gulf of Mexico.  We have grown through acquisitions, exploration and development and currently hold working interests in approximately 52 offshore fields in federal and state waters (50 producing and two fields capable of producing).  We currently have under lease approximately 750,000 gross acres, with approximately 490,000 gross acres on the shelf and approximately 260,000 gross acres in the deepwater.  A majority of our daily production is derived from wells we operate.  Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. and our wholly-owned subsidiary, W & T Energy VI, LLC.  

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production.  Our production volumes for the three months ended March 31, 2017 were comprised of 47.0% oil and condensate, 9.7% NGLs and 43.3% natural gas, determined using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs.  The conversion ratio does not assume price equivalency, and the price per one barrel oil equivalent (“Boe”) for oil, NGLs and natural gas has differed significantly from time to time.  For the three months ended March 31, 2017, revenues from the sale of oil and NGLs made up 75.3% of our total revenues compared to 72.0% for the same period in 2016.  For the three months ended March 31, 2017, our combined total production was 2.5% lower than the same period in 2016, with oil having the largest decline.  For the three months ended March 31, 2017, our total revenues were 60.1% higher than the same period in 2016 due primarily to significantly higher realized prices for all three of our commodities - oil, NGLs and natural gas.  See Results of Operations – Three Months Ended March 31, 2017 Compared to the Three Months Ended March 31, 2016 in this Item for additional information on our revenues and production.

On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our Unsecured Senior Notes due 2019 for new secured notes and common stock.  At the same time, we closed on a new $75.0 million, 1.5 Lien Term Loan and in conjunction, two amendments were made effective under our Credit Agreement.  See Financial Statements - Note 2 – Long-Term Debt under Part I, Item 1 of this Form 10-Q and Liquidity and Capital Resources in this Item for additional information.

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Our operating results are strongly influenced by the price of the commodities that we produce and sell.  The price of those commodities is affected by both domestic and international factors, including domestic production.  During the three months ended March 31, 2017, our average realized oil price was $47.06 per barrel.  This is an increase over our average realized oil price of $26.73 for the three months ended March 31, 2016 and an increase over our average realized oil price of $37.35 per barrel for the year 2016.  In addition, average realized prices of NGLs and natural gas for the first quarter of 2017 were higher than average realized prices for the three months ended March 31, 2016 and the year 2016.  

The overall crude oil and other petroleum liquids market remains in an oversupply position.  This is important as excess supplies necessarily limit price increases and could cause future prices to fall until such time as the market becomes more balanced.  

Selected issues and data points related to crude oil, NGLs and natural gas markets are described below.

The U.S. Energy Information Administration (“EIA”) estimates the worldwide crude oil and petroleum liquids supply will exceed demand in 2017, resulting in crude oil and other petroleum liquids inventories increasing by 0.2 million barrels per day.  EIA expects worldwide production to increase by 1.1 million barrels per day in 2017 over 2016 and increase by 1.9 million barrels per day in 2018 over 2017.  The expected increases are primarily in the U.S. and Brazil, with OPEC production expected to be fairly flat in 2017 and increasing in 2018.  EIA reports the market’s perception is that the voluntary production cuts by OPEC and Russia are expected to be extended and that EIA assumes production volumes will approach pre-agreement levels in the second half of 2017.  Consumption is forecast to increase in 2017 by 1.5 million barrels per day in 2017 over 2016, and further increase by 1.6 million barrels per day in 2018 over 2017.   As in the January forecast, the first future quarter where consumption exceeds supply is the third quarter of 2017, but then reverting to inventory builds in the following three quarters.  

According to data provided by EIA, U.S. production of crude oil (excluding other petroleum liquids) increased in the first quarter of 2017 by 2% compared to the fourth quarter of 2016.  EIA’s estimate for 2017 of U.S. crude oil production is an increase of 4% from 2016.  As noted below, the number of rigs drilling for oil increased at the end of the first quarter of 2017 compared to year-end 2016.

In addition, it is important to note that geopolitical events could greatly affect the prices for oil, natural gas and other petroleum products.  While these events are difficult to predict, we note the deteriorating political environment in Venezuela that could affect approximately 0.7 million barrels per day of crude oil exports to the U.S.  In addition, the political environments in other international areas, such as the Middle East and North Korea, could also affect prices for oil, natural gas and other petroleum products.  

During the first quarter of 2017, our average realized oil sales price was $47.06, up from $26.73 per barrel (76.1% higher) for the same period in 2016.  The two primary benchmarks are the prices for WTI and Brent crude oil.  As reported by the EIA, WTI crude oil prices averaged $51.62 per barrel for the first quarter of 2017, up from $33.35 per barrel (54.8% higher) for the same period in 2016.  Brent crude oil prices averaged $53.59 per barrel for the first quarter of 2017, up from $33.84 per barrel (58.4% higher) for the same period in 2016.  The reductions in international crude oil supply and rising U.S. crude oil production put upward price pressure on the premium of Brent to WTI, as the premium increased in the first quarter of 2017 compared to the fourth quarter of 2016.  

Our average realized oil sales price ($47.06 per barrel compared to a WTI benchmark price of $51.62 per barrel) for the first quarter of 2017 differs from the benchmark crude prices due to premiums or discounts (referred to as differentials), crude quality adjustments, volume weighting and other factors.  All of our oil was produced offshore in the Gulf of Mexico and is characterized as Poseidon, Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and others.  WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors.  Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past.  The monthly average differentials of WTI versus Poseidon, LLS and HLS for the first quarter of 2017 were a negative $3.04, a positive $1.58 and a positive $1.02 per barrel, respectively, compared to a negative $3.71, a positive $1.60 and a positive $0.80 per barrel, respectively, for the same period in 2016.  The majority of our crude oil is priced similar to Poseidon and therefore, is experiencing negative differentials.  In addition, a few of our crude oil fields have a negative quality bank adjustment.

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EIA projects average crude oil prices for WTI and Brent to increase by approximately $9.00 per barrel and $10.00 per barrel, respectively, for the year 2017 compared to 2016 and to increase in 2018 over 2017 by approximately $3.00 per barrel for each.  Their estimate notes that production in the U.S. is expected to increase while being mostly offset by production decreases by OPEC and Russia bringing levels closer to agreed-upon production cuts.  EIA notes the recent U.S. onshore activity has created the expectation of increased U.S. production in 2017causing EIA to increase the premium of the 2017 Brent price over WTI.  In addition, the strength in the U.S. dollar relative to other currencies also has an impact on crude pricing.  Because all barrels are traded in U.S. dollars, as the U.S. dollar gains strength, crude prices are lower in U.S. dollars but are more expensive in other currencies.

During the three months ended March 31, 2017, our average realized NGLs sales price increased 67.2% compared to the same period in 2016.  Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel.  During the three months ended March 31, 2017, average prices for domestic ethane increased 40% and average domestic propane prices increased 85% from the same period in 2016.  Average price changes for other domestic NGLs were an increase of 44% to 86% between the two periods.  Per EIA, production of ethane increased by 9% in the three months ended March 31, 2017 over the same period in 2016 and propane production decreased by 2% in the three months ended March 31, 2017 over the same period in 2016.  Ethane inventories are higher than the same period in 2016, increasing 53%, but have decreased 4% from the fourth quarter of 2016.  Ethane usage is not impacted by weather. On the other hand, propane usage is affected by weather as it is used for house heating fuel in certain areas and for crop drying, along with other uses.  Propane inventory levels are lower coming out of the winter season and are 32% lower than the comparable period in 2016 even with the winter of 2016-2017 being unseasonably warm.  Many natural gas processing facilities have been and, from time to time, will likely continue re-injecting ethane back into the natural gas stream after processing due to insufficient ethane demand, which negatively impacts production and natural gas prices.  Ethane demand is expected to increase in 2017 over 2016 as petrochemical plants and expansion projects that consume ethane come online.  

During the three months ended March 31, 2017, our average realized natural gas sales price increased 48.3% compared to the same period in 2016.  According to the EIA, spot prices for natural gas at Henry Hub (the primary U.S. price benchmark) were 51.5% higher in the three months ended March 31, 2017 from the same period in 2016.  Natural gas prices are more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues, other fuel competition (coal) and domestic economic conditions, and they have historically been subject to substantial fluctuation.  Average spot prices in the first quarter of 2017 were similar to levels in the fourth quarter of 2016.  During the 2016-2017 winter, inventory drawdowns were higher than the prior year period due to lower production and higher exports, partially offset by lower consumption.  Inventories at the end of the first quarter of 2017 were 17% lower than the prior year period, which are expected to move inventories closer to the five-year average by the time the heating season begins in 2017.  The narrowing of inventory levels is reflected in EIA’s forecast of rising natural gas prices discussed below.  U.S. consumption was lower in the first quarter of 2017 compared to the same period in 2016, with decreases in all categories and electric power generation being the primary category of the decrease in consumption.  

The average price of natural gas continues to be weak from an overall economic standpoint, and we expect continued weakness in natural gas prices for a number of reasons, including (i) producers continuing to drill in order to secure and to hold large lease positions before expiration, particularly in shale and similar resource plays, (ii) natural gas continuing to be produced as a by-product of oil drilling,  (iii) production efficiency gains being achieved in the shale gas areas resulting from better hydraulic fracturing, horizontal drilling, pad drilling and production techniques (iv) higher inventory levels and (v) re-injecting ethane into the natural gas stream as indicated above, which increases the natural gas supply.

EIA projects natural gas prices to increase in 2017 compared to 2016 by 23% and further increase by 12% in 2018 over 2017.  U.S. supply is projected to be approximately equal to consumption in 2017 and 2018.  During 2016, natural gas overtook coal as being the largest fuel source for power generation, supplying 34% of the megawatts generated compared to 30% from coal.  EIA’s forecast of fuel used for power generation has natural gas continuing to be the largest in 2017 and 2018, but it’s percentage to fall to 32% for both years while the percentage from coal is forecast to increase to 31% for both years.  This is due to the expected higher natural gas prices compared to coal.  

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During the three months ended March 31, 2017, the number of working rigs drilling for oil and natural gas in the U.S. was significantly above year ago levels for land based rigs, but was lower for offshore rigs.  According to Baker Hughes, the oil rig count at March 2016, December 2016 and March 2017 was 362, 525 and 662, respectively.  The U.S. natural gas rig count at March 2016, December 2016 and March 2017 was 88, 132 and 160 respectively. In the Gulf of Mexico, the number of working rigs was 24 rigs (19 oil and 5 natural gas) at March 2016; 22 rigs (22 oil and no natural gas) at December 2016; and 22 rigs (21 oil and one natural gas) at March 2017.  The majority of working rigs in the Gulf of Mexico are currently “floaters” with very few jack-up rigs working.

As required by the full cost accounting rules, we perform our ceiling test calculation each quarter using the SEC pricing guidelines, which require using the 12-month average commodity price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price adjusted for price differentials.  The average price using the SEC required methodology at March 31, 2017 was $44.10 per barrel for WTI crude oil and $2.73 per MMBtu for Henry Hub natural gas before adjustments.  For the three months ended March 31, 2017, we did not have a ceiling test write-down.  For the three months ended March 31, 2016, we recorded a ceiling test write-down of the carrying value of our oil and natural gas properties of $116.6 million due primarily to lower prices of crude oil and natural gas.  Incurrence of write downs is dependent primarily on the price of crude oil and natural gas, but also is affected by quantities of proved reserves, future development costs and future lease operating costs.

We performed a pro-forma calculation to determine if a ceiling test impairment write-down would be likely in the second quarter of 2017 based only on changes to prices using the assumptions that projected prices are the same as most recently published first-day-of-the month prices to compute a pro-forma 12-month average.  In this pro-forma calculation, no changes were assumed for proved reserves from the March 31, 2017 levels other than price and no changes were assumed for other factors.  The pro-forma calculation indicated that there would not have been a ceiling-test write down for the first quarter of 2017 using these pro-forma prices.  This pro-forma calculation may not be predictive of the second quarter of 2017, as other factors besides price will impact the ceiling test calculation.  

During the first quarter of 2017, the BOEM issued notices that provide for a six-month extension for both “sole-liability” and “non-sole liability” properties related to the implementation of NTL #2016-01, which includes financial assurances related to asset retirement obligations for leases, ROWs and RUEs.  We continue to have discussions with the BOEM regarding these matters.  These matters are more fully discussed in the Liquidity and Capital Resources section of this Item II of this Form 10-Q. 

We have set our initial 2017 capital expenditure budget at $125.0 million, which is above the capital expenditures incurred in 2016 of $48.6 million, but reduced from investment levels in 2015 and 2014 of $231.4 million and $630.0 million, respectively.  Because of the level of commodity prices and the outlook for the remainder of the 2017, we believe this capital expenditure level should enable us to maintain or increase production in 2017 over 2016, while at the same time, allow cash balances to build and leave our revolving bank credit facility undrawn (assuming current commodity price and cost levels). While the 2017 capital projects are expected to impact 2017 production to a degree, the bulk of the impact on production is expected to be in 2018 and beyond.  We strive to maintain flexibility in our capital expenditure projects and if prices improve, we may increase our investments.  

With respect to our costs, we have realized significant reductions in our lease operating expenses and general and administrative expenses as a result of our cost reduction programs, which included headcount and contractor usage reductions, combined with reduced rates from vendors for supplies, equipment and contract labor.  These cost reduction programs and reduced supplier rates have also lowered capital expenditures, ARO settlements and ARO estimates.  

Our short term focus is on liquidity, cost reductions, fulfilling our obligations and making investments with short payback time frames.  In light of our somewhat limited access to capital and liquidity, we are continually assessing our plans.  We continue to closely monitor current and forecasted prices to assess if changes are needed to our plans.  See our Annual Report on Form 10-K for the year ended December 31, 2016, Item 1A, Risk Factors, for additional information.  

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Results of Operations

The following tables set forth selected financial and operating data for the periods indicated (all values are net to our interest unless indicated otherwise):

 

NM – not meaningful

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Completed Wells

During the three months ended March 31, 2017, we completed two offshore wells and during the three months ended March 31, 2016, we completed one offshore well.  All three wells were productive.  

Three Months Ended March 31, 2017 Compared to the Three Months Ended March 31, 2016

Revenues.  Total revenues increased $46.7 million, or 60.1%, to $124.4 million for the first quarter of 2017 as compared to the first quarter of 2016.  Oil revenues increased $34.0 million, or 66.8%, NGLs revenues increased $3.7 million, or 75.0%, natural gas revenues increased $9.5 million, or 46.8% and other revenues decreased $0.6 million.  The increase in oil revenues was attributable to a 76.1% increase in the average realized sales price to $47.06 per barrel for the first quarter of 2017 from $26.73 per barrel for the first quarter of 2016, partially offset by a decrease of sales volumes of 5.3%.  The increase in NGLs revenues was attributable to a 67.2% increase in the average realized sales price to $23.34 per barrel for the first quarter of 2017 from $13.96 per barrel for the first quarter of 2016 and sales volumes increased 4.5%.  The increase in natural gas revenues resulted from a 48.3% increase in the average realized natural gas sales price to $2.98 per Mcf for the first quarter of 2017 from $2.01 per Mcf for the first quarter of 2016, partially offset by a decrease of 0.9% in sales volumes.  Overall, production declined 0.1 MMBoe (2.5%).  The largest production increases for the first quarter of 2017 compared to the first quarter of 2016 were at the Ewing Bank 910, Viosco Knoll 823 (“Virgo”), East Cameron 321, Garden Banks 302 (“Powerplay”) and Main Pass 108 fields.  Offsetting were production decreases primarily due to natural production declines.  

Revenues from oil and liquids as a percent of our total revenues were 75.3% for the first quarter of 2017 compared to 72.0% for the first quarter of 2016.  Our average realized NGLs sales price as a percent of our average realized oil sales price decreased to 49.6% for the first quarter of 2017 compared to 52.2% for the first quarter of 2016.   

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, insurance, workovers, and facilities maintenance, decreased $4.3 million, or 9.7%, to $40.2 million in the first quarter 2017 compared to the first quarter of 2016.  On a per Boe basis, lease operating expenses decreased to $10.45 per Boe during the first quarter of 2017 compared to $11.28 per Boe during the first quarter of 2016.  On a component basis, base lease operating expenses decreased $4.7 million and insurance premiums decreased $2.3 million, partially offset by increases in workover expenses of $2.6 million and facilities maintenance expense increases of $0.1 million.  Base lease operating expenses decreased primarily due to lower costs from service providers.  Insurance premium reductions are primarily due to revisions in our insurance policies related to named windstorms, which became effective in June 2016.    The increase in workover costs was primarily due to increases at the Ship Shoal 349 (“Mahogany”) field.

Production taxes.  Production taxes were basically flat for the first quarter of 2017 compared to the first quarter of 2016.  Most of our production is from federal waters where no production taxes are imposed.  Our Fairway field, which is in state waters, is subject to production taxes.  

Gathering and transportation.  Gathering and transportation increased $1.1 million to $6.2 million for the first quarter of 2017 compared to the first quarter of 2016 primarily due to increases at the Virgo and Atwater Valley 575 fields.  

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, which includes accretion for ARO, decreased to $10.40 per Boe for the first quarter of 2017 from $16.17 per Boe for the first quarter of 2016.  On a nominal basis, DD&A decreased to $40.0 million, (37.3%), for the first quarter of 2017 from $63.7 million for the first quarter of 2016.  DD&A on a per Boe and nominal basis decreased primarily due to the ceiling test write-downs recorded during 2016 and lower capital expenditures in relation to DD&A expense during 2016, which lowers the full-cost pool subject to DD&A.  Other factors affecting the DD&A rate are changes in future development costs on remaining reserves and changes in proved reserves volumes.    

Ceiling test write-down of oil and natural gas properties. For the first quarter of 2016, we recorded a non-cash ceiling test write-down of $116.6 million as the book value of our oil and natural gas properties exceeded the ceiling test limitation.  The write-down was primarily the result of lower prices on all commodities for our proved reserves.  See our Annual Report on Form 10-K for the year ended December 31, 2016, Item 8, Financial Statements and Supplementary Data for additional information on the ceiling test.

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General and administrative expenses (“G&A”).  G&A decreased to $13.3 million, (19.3%), for the first quarter of 2017 from $16.4 million for the first quarter of 2016 primarily due to reductions in legal expense, salaries expenses, professional fees and benefits costs, partially offset by increases in surety bond costs.  G&A on a per BOE basis was $3.45 per Boe for the first quarter of 2017 compared to $4.17 per Boe for the first quarter of 2016.

Derivative gain. For the first quarter of 2017, there was a $4.0 million derivative gain recorded for both crude oil and natural gas derivative contracts, which includes settled contracts and open contracts recorded at fair value as of March 31, 2017.  We entered into derivative contracts for crude oil and natural gas during the first quarter of 2017, relating to a portion of our 2017 estimated production.  For the first quarter of 2016, there was a $2.5 million derivative gain recorded for derivative contracts for crude oil and natural gas.  

Interest expense.  Interest expense incurred was $11.3 million in the first quarter of 2017, compared to $27.8 million in the first quarter of 2016.  The decrease was primarily attributable to the Exchange Transaction that was completed on September 7, 2016, when we exchanged $710.2 million of our Unsecured Senior Notes for $301.8 million of new secured notes and 60.4 million shares of common stock, and at the same time, closed on a new $75.0 million secured loan.  The Exchange Transaction and the related accounting are more fully described in the Liquidity and Capital Resource section below.  In addition, interest expense was lower as we had no borrowings on the revolving bank credit facility during the first quarter of 2017 compared to borrowings averaging over $100 million during the first quarter of 2016.

Other expense, net.  During the first quarter of 2017 and 2016, other expense, net, was $0.2 million and $1.3 million, respectively.  For the first quarter of 2016, the amount was primarily due to write-down of debt issuance costs related to a reduction in the borrowing base of the revolving bank credit facility.  

Income tax benefit. Our income tax benefit for the first quarter of 2017 and 2016 was $7.6 million and $4.9 million, respectively.  Our annualized effective tax rate using book pre-tax income was not meaningful for either period.  The income tax benefit for both periods relates to NOL carryback claims made pursuant to IRC Section 172(f) (related to rules for “specified liability losses”), which permit certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.  For both periods, adjustments in the valuation allowance offset changes in net deferred tax assets.  See Financial Statements – Note 7 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

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Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas reserves, repay outstanding borrowings, make related interest payments and satisfy our asset retirement obligations.  We have funded such activities with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank borrowings.  

If commodity prices were to return to the weak levels seen in the early part of 2016, especially relative to our cost of finding and producing new reserves, this could significantly affect our liquidity.  In addition, other events outside of our control could significantly affect our liquidity such as demands for additional financial assurances from the BOEM or a final judgment for monetary damages in our lawsuit with Apache.  If such events were to occur in the future, we may seek relief under the U.S. Bankruptcy Code, which relief may include (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of our assets and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks.

Additionally, a prolonged period of weak commodity prices could have other potential negative impacts including:

During 2016, we engaged legal and financial advisors to assist the Board of Directors and our management team to evaluate the various alternatives available to us and executed the transaction described below:

Exchange Transaction.  On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our Unsecured Senior Notes, due June 15, 2019 for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Second Lien PIK Toggle Notes, due May 15, 2020; (ii) $142.0 million in aggregate principal of 8.50%/10.00% Third Lien PIK Toggle Notes, due June 15, 2021; and (iii) 60.4 million shares of our common stock.  

At the same time on closing on the Debt Exchange described above, we closed on a $75.0 million, 11.00% 1.5 Lien Term Loan, due November 2019, with the largest holder of our Unsecured Senior Notes.  We accounted for the Exchange Transaction as a Troubled Debt Restructuring under ASC 470-60.  Under ASC 470-60, the carrying value of the newly issued Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Condensed Consolidated Statements of Operations during the three months ended March 31, 2017.  Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt.  Under ASC 470-60, payments related to the New Debt are reported in the financing section of the Condensed Consolidated Statements of Cash Flows.

The funds received from the 1.5 Lien Term Loan were used to pay transaction costs related to the Exchange Transaction and to pay down borrowings on the revolving bank credit facility. The balance of the borrowings on the revolving bank credit facility was paid down from available cash.

For the Third Lien PIK Toggle Notes and the 1.5 Lien Term Loan, the maturity of both will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes are not extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.  A total of $247.7 million would become due on February 28, 2019 if acceleration were to occur.    

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Credit Agreement.  Availability on our revolving bank credit facility as of March 31, 2017 was $149.5 million.  At March 31, 2017 and December 31, 2016, no amounts were outstanding and letters of credit were $0.5 million.  During the three months ended March 31, 2017, no borrowings were made on the revolving bank credit facility.

Availability under our revolving bank credit facility is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.  The 2017 spring redetermination reaffirmed the borrowing base amount at $150.0 million.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility.    The revolving bank credit facility is secured and is collateralized by substantially all of our oil and natural gas properties.  

The Credit Agreement contains financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the Credit Agreement.  We were in compliance with all applicable covenants of the Credit Agreement and the other debt instruments as of March 31, 2017.

Long-Term Debt.  The recorded amounts of our long-term debt and the primary terms are disclosed in Financial Statements - Note 2 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.  

BOEM Matters.  During the first quarter of 2017, the BOEM extended the implementation timeline by an additional six months for NTL #2016-N01 as to OCS leases, ROWs or RUEs for which there are co-lessees and/or predecessors in interest (non-sole liability properties), with certain exceptions.  Also, in the first quarter of 2017, the BOEM withdrew the sole liability orders it had issued in December 2016 to allow time for the new President’s administration to review the complex financial assurance program.  We are in final stages of resolving a matter with the BOEM that began over a year ago with its demand that we secure financial assurances (such as supplemental bonding) in the aggregate of $260.8 million.  We recently received a letter from the BOEM that indicated that in order for the BOEM to rescind the orders, we must first satisfy our financial assurance requirement related to sole liability properties.  We believe that we can satisfy our obligation under the most recent BOEM request for financial assurance of sole liability properties and we will request that the previous orders pertaining to the $260.8 million of financial assurances be rescinded.

Surety Bond Collateral.  Some of the sureties under our existing supplemental surety bonds have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and could impact our liquidity.  In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion.

The issuance of any additional surety bonds or other security to satisfy the BOEM orders, any future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third-parties may require the posting of cash collateral, which may be significant, and the creation of escrow accounts.  

Cash Flow and Working Capital.  Net cash provided by operating activities for the three months ended March 31, 2017 and 2016 was $81.2 million and $29.7 million, respectively.  Cash flows from operating activities, before changes in working capital, insurance reimbursements and ARO, were $63.4 million for the three months ended March 31, 2017, compared to a negative $9.6 million in the comparable period.  The increase in cash flows was primarily due to higher realized prices for all our commodities - oil, NGLs and natural gas, lower operating costs and lower interest payments, partially offset by lower production volumes.  Our combined average realized sales price per Boe increased 66.2%, which increased revenues $49.9 million.  Lease operating expenses decreased $4.3 million and G&A expenses decreased $3.2 million.  Partially offsetting were volume decreases of 2.5% on a per Boe basis, which lowered revenues by $2.6 million.  

Other items affecting operating cash flows for the three months ended March 31, 2017 were insurance reimbursements of $30.1 million and changes in receivables, accounts payable and accrued liabilities of $2.2 million, partially offset by ARO settlements of $14.5 million.  

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Net cash used in investing activities during the three months ended March 31, 2017 and 2016 was $23.0 million and $32.6 million, respectively, which represents our investments in oil and gas properties and equipment.  There were no acquisitions of properties during either period.  Investments in oil and natural gas properties on an accrual basis in the three months ended March 31, 2017 were $23.3 million compared to $12.9 million for the same period in 2016.  The capital expenditures during the three months ended March 31, 2017 related primarily to investments on the conventional shelf.  In addition, adjustments from working capital changes associated with investing activities increased net cash by $1.2 million in the three months ended March 31, 2017 compared to net cash usage of $20.7 million for the same period in 2016.  These amounts represent timing differences between when the work was performed and the payment.      

Net cash used by financing activities for the three months ended March 31, 2017 was $2.3 million and net cash provided by financing activities for the three months ended March 31, 2016 was $288.1 million.  The net cash used for the three months ended March 31, 2017 was primarily attributable to the interest payment on the 1.5 Lien Term Loan, which is reported as a financing activities under ASC 470-60.  The net cash provided for the three months ended March 31, 2016 was attributable to the net borrowings on the revolving bank credit facility.  

Derivative Financial Instruments.  From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility.  As of March 31, 2017, we had outstanding open derivatives for crude oil and natural gas.  These derivatives provide downside protection against a portion of our remaining 2017 production.  The oil swap contract provides cash inflows when the oil price is below $55.25.  The “two-way collar” contracts will provide cash inflows when crude oil or natural gas prices average are below $50.00 per barrel and $3.07 per MMBtu, respectively, in a month.  Conversely, these contracts may require cash payments and limit upside potential if prices exceed certain amounts.  See Financial Statements - Note 5 - Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Insurance Coverage.  We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells.  The current policy limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements.  We carry named windstorm coverage of $150.0 million for a total loss only (“TLO”) on our Mahogany platform (Ship Shoal 349) and do not have named windstorm coverage on any other of our properties.  The operational and named windstorm coverages are effective until June 1, 2017.  Coverage for pollution causing a negative environmental impact is provided under the well control and named windstorm sections of the policy.

Our general and excess liability policies are effective until May 1, 2018 and provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination.  With respect to the Oil Spill Financial Responsibility requirement under the Oil Pollution Act of 1990, we are required to evidence $150.0 million of financial responsibility to the BSEE and we have insurance coverage of such amount.  

Although we were able to renew our general and excess liability policies on May 1, 2017, and we expect to contract an Energy Package for the June 2017 – May 2018 timeframe, our insurers may not continue to offer this type and level of coverage to us in the future, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations.  We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurers will not pay our claims.  However, we are not aware of any financial issues related to any of our insurance underwriters that would affect their ability to pay claims.  We do not carry business interruption insurance.

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Capital Expenditures.  The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of oil, NGLs and natural gas, acquisition opportunities, available liquidity and the results of our exploration and development activities.  The following table presents our capital expenditures on an accrual basis for exploration, development and other leasehold costs and acquisitions.

 

The following table presents our exploration and development capital expenditures on an accrual basis geographically in the Gulf of Mexico:

 

Our capital expenditures for the three months ended March 31, 2017 were financed by cash flow from operations and cash on hand.  

The following table presents our offshore wells drilled based on a completed basis:

Both wells in the above table were successful.  

Exploration Activities.  During the first quarter of 2017, the A-18 at Mahogany was completed and began producing in January 2017.  At March 31, 2017, the A-16 BP1 well at Mahogany was completed and began producing in April 2017.  

Divestitures.  Periodically, we sell properties as part of the management of our property portfolio.  During the three months ended March 31, 2017, we did not have any property sales.

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Capital Expenditure Budget and Expected Production for 2017.  With consideration of the current commodity price environment and the outlook for the remainder of 2017, we have set our initial 2017 capital expenditure budget at $125.0 million, which excludes potential acquisitions.  Although this is an increase from the $48.6 million capital expenditures incurred in 2016, our current plan for 2017 is a significant reduction from 2015 and 2014 investment levels of $231.4 million and $630.0 million, respectively.  We have flexibility in our 2017 capital expenditure budget as we have no long term rig commitments and no pressure from co-owners to drill or complete a well.  Our 2017 production is expected to be positively impacted by the Ewing Bank 910 A-8 well, which began producing during March 2016 and had a workover performed in October 2016, the Mahogany A-18 well, which began producing in January 2017, and the Mahogany A-16 BP1 well, which began producing in April 2017.  Some of our expenditures planned for the remainder of 2017 are expected to impact production for 2017, while most are expected to impact 2018 production and beyond.  We expect 2017 production to be slightly higher than 2016, but factors such as natural production declines, unplanned downtime and well performance could lead to lower production in 2017.  We continue to closely monitor current and forecasted prices to assess if changes are needed to our plans.

Income Taxes.  During the three months ended March 31, 2017, we did not make any income tax payments or receive any refunds of significance.  As of March 31, 2017, we recorded current income tax receivables of $11.9 million and non-current income tax receivables of $59.8 million.  The current income tax receivables relates primarily to an NOL claim for 2016 carried back to 2006.  The non-current income taxes receivables relates to our NOL claims for the years 2012, 2013 and 2014 that were carried back to prior years filed on Form 1120X, U.S. Corporation Income Tax Return and to an estimated NOL claim for 2017 that is expected to be filed subsequent to December 31, 2017.  These receivables relate to claims made pursuant to IRC Section 172(f), (related to rules for “specified liability losses”) which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years.  See Financial Statements – Note7 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

Asset Retirement Obligations.  Each quarter, we review and revise our ARO estimates.  Our ARO at March 31, 2017 and December 31, 2016 were $326.8 million and $334.4 million, respectively.  Our plans include spending $78.3 million in 2017 for ARO compared to $72.3 million spent on ARO in 2016.  As our ARO are estimates for work to be performed in the future, and in the case of our non-current ARO, are for many years in the future, actual expenditures could be substantially different than our estimates.  See Risk Factors, under Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2016 for additional information.    

Contractual Obligations.  Updated information on certain contractual obligations is provided in Financial Statements – Note 2 – Long-Term and Note 4 – Asset Retirement Obligation, and under Part I, Item 1 of this Form 10-Q.  As of March 31, 2017, drilling rig commitments, excluding ARO drilling rig commitments, were approximately $4.2 million compared to $4.4 million as of December 31, 2016.  Except for scheduled utilization, other contractual obligations as of March 31, 2017 did not change materially from the disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, under Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2016.

Critical Accounting Policies

Our significant accounting policies are summarized in Financial Statements and Supplementary Data under Part II, Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2016.  Also refer to Financial Statements - Note 1 - Basis of Presentation under Part 1, Item 1 of this Form 10-Q.  

Recent Accounting Pronouncements

See Financial Statements - Note 1 - Basis of Presentation under Part 1, Item 1, of this Form 10-Q.  

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the three months ended March 31, 2017 did not change materially from the disclosures in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2016.  As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, 2016.  

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of oil, NGLs and natural gas, which fluctuate widely.  Oil, NGLs and natural gas price declines have adversely affected our revenues, net cash provided by operating activities and profitability and could have further impact on our business in the future.  As of March 31, 2017, we had open derivative contracts related to a portion of estimated production for the remainder of 2017.  We historically have not designated our commodity derivatives as hedging instruments and any future derivative commodity contracts are not expected to be designated as hedging instruments.  Use of these contracts may reduce the effects of volatile oil prices, but they also may limit future income from favorable price movements.  See Financial Statements - Note 5 - Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Interest Rate Risk.  As of March 31, 2017, we had no outstanding borrowings on our revolving bank credit facility.  The revolving bank credit facility has a variable interest rate, which is primarily impacted by the London Interbank Offered Rate and the margin, which ranges from 3.00% to 4.00% depending on the amount outstanding.  As of March 31, 2017, we did not have any derivative instruments related to interest rates.

Item 4.  Controls and Procedures

We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding required disclosures.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report.  Based on that evaluation, our CEO and CFO have each concluded that as of March 31, 2017, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended March 31, 2017, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.  

 

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PART II – OTHER INFORMATION

 

Item 1.  Legal Proceedings

See Part I, Item 1, Financial Statements – Note 9 – Contingencies, of this Form 10-Q for information on various legal matters.  

Item 1A.  Risk Factors  

Investors should carefully consider the risk factors included under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2016, together with all of the other information included in this document, in our Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management.

The potential effects of the continued weakness in crude oil prices are discussed under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2016 and also discussed in the Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Overview section of this Form 10-Q.

Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2016.

 

Item 6.  Exhibits

The exhibits to this report are listed in the Exhibit Index.

 

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on May 4, 2017.

 

 

 

 

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EXHIBIT INDEX

 

 

 

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