UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended March 31, 2016

OR

For the transition period from              to             .

Commission file number: 001-33610

 

REX ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

 

366 Walker Drive

State College, Pennsylvania 16801

(Address of principal executive offices) (Zip Code)

(814) 278-7267

(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  x    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  x    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 (as defined in Rule 12b-2 of the Exchange Act). Check One:

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

73,357,014 common shares were outstanding on May 6, 2016.

 

 

 

 

 

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REX ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD MARCH 31, 2016

INDEX

 

 

 

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of sections 27A of the Securities Act of 1933, as amended, and 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this report, including, but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs, savings and plans and objectives of management for future operations, are forward-looking statements. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe” or “continue” or the negative thereof or similar terminology.

These forward-looking statements are subject to numerous assumptions, risks and uncertainties. Factors which may cause our actual results, performance or achievements to be materially different from those expressed or implied by us in forward-looking statements include, among others, the following:

Because these statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. You are cautioned not to place undue reliance on forward looking-statements, which speak

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only as of the date of this report. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.

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REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

($ in Thousands, Except Share and per Share Data)

 

See accompanying notes to the unaudited consolidated financial statements

 

 

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REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, $ in Thousands, Except per Share Data)

 

See accompanying notes to the unaudited consolidated financial statements

 

 

 

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REX ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

FOR THE THREE-MONTHS ENDED MARCH 31, 2016

(Unaudited, in Thousands)

 

See accompanying notes to the unaudited consolidated financial statements

 

 

 

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REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, $ in Thousands)

 

See accompanying notes to the unaudited consolidated financial statements

 

 

 

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REX ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

 

1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent oil, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian Basin and Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. In the Illinois Basin, we are focused on developmental oil drilling on our properties. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties.

The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. We report our interests in oil, NGL and natural gas properties using the proportional consolidation method of accounting. All intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.

For purposes of compliance with Accounting Standards Update (“ASU”) 2015-3, which we adopted on January 1, 2016, we have reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and approximately $11.9 million from Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. In addition, we adopted ASU 2015-17 on January 1, 2016, which eliminates the need to show deferred tax liabilities and assets as current and noncurrent. Our Consolidated Balance Sheet as of December 31, 2015 included $12.5 million in Long-Term Tax Assets and $12.5 million in Current Deferred Tax Liability. Reclassifying our Current Deferred Tax Liability to noncurrent allowed us to net our noncurrent asset and noncurrent liability together resulting in a net deferred tax balance of zero (see Note 5, Recently Issued Accounting Pronouncements, to our Consolidated Financial Statements for additional information). For purposes of consistency, we have reclassified $350.0 million and $325.0 million from 8.875% Senior Notes Due 2020 and 6.25% Senior Notes Due 2022, respectively, to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015.

The interim Consolidated Financial Statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Actual results may differ from those estimates and results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part, but not limited to, the volatility in prices for crude oil, NGLs and natural gas, future impact of financial derivative instruments, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market consumption, interruption in production, our ability to obtain additional capital, and the success of oil, NGL and natural gas recovery techniques.

Certain amounts and disclosures have been condensed or omitted from these Consolidated Financial Statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Therefore, these interim financial statements should be read in conjunction with the audited Consolidated Financial Statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015.

Discontinued Operations

Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 3, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.

 

2. FUTURE ABANDONMENT COST

Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the

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liability is reversed. If the fair value of a recorded future abandonment cost changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.

Accretion expense for each of the three-month periods ended March 31, 2016 and 2015 totaled approximately $0.9 million. These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells.

 

 

¹ Includes approximately $2.4 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

 

 

3. DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE

In December 2014, our board of directors approved a formal plan to sell Water Solutions Holdings, LLC (“Water Solutions”), of which we owned a 60% interest. In June 2015, we entered into a purchase and sale agreement with American Water Works Company, Inc. (“American Water”) pursuant to which American Water acquired Water Solutions for consideration of approximately $130.0 million, inclusive of cash and debt and subject to other customary adjustments. The sale closed in July 2015, and we received approximately $66.8 million in net proceeds, resulting in a gain of approximately $57.8 million. The transaction is recorded as Discontinued Operations.

 

Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such indirect costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.

 

 

 

4. BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS

Water Solutions

As described in Note 3 above, we sold Water Solutions pursuant to a purchase and sale agreement with American Water.  

ArcLight Capital Partners, LLC

On March 31, 2015, we entered into a joint venture agreement with an affiliate of ArcLight Capital Partners, LLC (“ArcLight”) to jointly develop 32 specifically designated wells in our Butler County, Pennsylvania operated area. ArcLight will participate and fund 35.0% of the estimated well costs for the designated wells. We expect to receive consideration for the transaction of approximately $67.0 million, with $16.6 million received at closing for wells that had previously been completed or were at that time in the process of being drilled and completed. The remainder of the proceeds will be received as additional wells are drilled and

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completed. Upon the attainment of certain return on investment and internal rate of return thresholds, 50.0% of ArcLight’s 35.0% working interest will revert back to us, leaving ArcLight with a 17.5% working interest. As of March 31, 2016, ArcLight had paid approximately $52.2 million for their interest in wells that have been drilled or are in the process of being drilled. As of March 31, 2016, all wells to be developed with ArcLight had been drilled and completed with four wells remaining to be placed into service.

The ArcLight transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by ArcLight. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from ArcLight are considered a recovery of costs and no gain or loss is recognized.

Benefit Street Partners, LLC

On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP will participate and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, 12 of which have already been drilled and completed and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, three of which have already been drilled and completed. We expect total consideration for this transaction to be $175.0 million with $37.1 million committed at closing. As of March 31, 2016, BSP had paid approximately $19.5 million for their interest in wells that had previously been completed. The remainder of the proceeds will be received as additional wells are completed. BSP also has the option to participate in the development of 36 additional wells in 2016 and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. In addition, BSP earns an assignment of 15%-20% working interest in acreage located within each of the units they participate. As of March 31, 2016, 15 of the initial 22 wells were in line and producing, three wells were drilled and awaiting completion and four wells were awaiting pipeline connection. In April 2016, BSP exercised their option to participate in four additional wells to be drilled and completed later in 2016.

The BSP transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by BSP. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from BSP are considered a recovery of costs and no gain or loss is recognized.

 

5. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40). The guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period ending after December 15, 2016 and for annual and interim periods thereafter. We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments in this ASU intend to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The ASU focuses on the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. In addition to reducing the number of consolidation models from four to two, the new standard places more emphasis on risk of loss when determining a controlling financial interest, reduces the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity and changes consolidation conclusions in several industries that typically make use of limited partnerships or variable interest entities. We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The standard requires an entity to present debt issuance costs related to a recognized liability as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. We adopted this ASU on January 1, 2016. In conjunction with the adoption of ASU 2015-03, we reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and $11.9 million from Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. Adoption did not have an impact on Net Income or Accumulated Deficit.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The amendments in this ASU affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards. This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the guidance

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is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services by following five steps:

1) Identify the contract(s) with a customer.

2) Identify the performance obligations in the contract.

3) Determine the transaction price.

4) Allocate the transaction price to the performance obligations in the contract.

5) Recognize revenue when (or as) the entity satisfies a performance obligation.

An entity should apply the amendments in this ASU using one of the following two methods:

1) Retrospectively to each prior reporting period presented.

2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications.

In July 2015, the FASB approved a one-year deferral of the effective date of this new standard so the guidance is effective for the reporting period beginning January 1, 2018, with early adoption permitted in the first quarter 2017. We are currently evaluating the new guidance and have not determined the impact this standard may have on our Consolidated Financial Statements or decided upon the method of adoption.

In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. We adopted this ASU on January 1, 2016. Our Consolidated Balance Sheet as of December 31, 2015 included $12.5 million in Long-Term Deferred Tax Assets and $12.5 million in Current Deferred Tax Liability. Reclassifying our Current Deferred Tax Liability to noncurrent allowed us to net our noncurrent asset and noncurrent liability together resulting in a net deferred tax balance of zero. Adoption did not have an impact on Net Income or Accumulated Deficit.

In February 2016, the FASB issued ASU 2016-02, Leases. Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date:

Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating this guidance and do not believe it will have a material impact due to our minimal number of operating leases.

In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. Under this update, several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. We are currently evaluating the impact of this standard.

 

6. CONCENTRATIONS OF CREDIT RISK

By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparties to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions and lenders in our Senior Credit Facility (see Note 7, Long-Term Debt, to our Consolidated Financial Statements). We have a master netting agreement in place with our counterparties that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the

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scheduled cash settlement date. For additional information, see Note 8, Derivative Instruments and Fair Value Measurements, to our Consolidated Financial Statements.

We also depend on a relatively small number of purchasers for a substantial portion of our revenue. For the three months ended March 31, 2016, approximately 93.5% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 46.0% of commodity sales. We believe the continued growth in our Appalachian Basin operations will help us to minimize our future risks by diversifying our ratio of oil, NGLs and natural gas sales as well as the quantity of purchasers.

7. LONG-TERM DEBT

Senior Credit Facility

We maintain a revolving credit facility evidenced by a credit agreement, dated March 27, 2013 and most recently amended on March 13, 2016 (the “Senior Credit Facility”). As of March 31, 2016, the borrowing base under the Senior Credit Facility was $200.0 million; however, the Senior Credit Facility may be increased to up to $500.0 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed by the agreement. Within the Senior Credit Facility, a subfacility exists for up to $60.0 million of letters of credit.  Effective April 1, 2016, our borrowing base was further reduced to $190.0 million in connection with our senior note exchange described below. As of March 31, 2016, loans made under the Senior Credit Facility were set to mature on September 12, 2019. Our borrowing base is re-determined at least twice per year with the next re-determination scheduled to occur on or about July 1, 2016. In certain circumstances, we may be required to prepay the loans. Management does not believe that a prepayment will be required within the next twelve months. As of March 31, 2016, we had $158.0 million outstanding, approximately $41.0 million in outstanding undrawn letters of credit and approximately $1.0 million available to borrow. There were $111.5 million borrowings outstanding as of December 31, 2015. Our Senior Credit Facility restricts the amount of cash and cash equivalents that we can hold on our Consolidated Balance Sheet to a maximum of $15.0 million, with any excess to be used to pay down the outstanding Senior Credit Facility balance, however we retain the right to draw on the Senior Credit Facility so long as there are amounts available under our borrowing base.    

The Senior Credit Facility requires we meet, on a quarterly basis, financial requirements of a minimum consolidated current ratio and maximum net senior secured debt to EBITDAX. EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, such as our commercial bank lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized gains and losses from derivatives, exploration expense and other similar non-cash activity. The Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of consolidated current assets, which includes the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day, known as our current ratio, must not be less than 1.0 to 1.0. Our current ratio as of March 31, 2016 was approximately 0.6 to 1.0.  Due to our expectation that we would not be in compliance with the current ratio we previously received a waiver of this requirement from the lenders for the period ended March 31, 2016. We expect to be in compliance with the current ratio covenant at June 30, 2016 and beyond. Additionally, as of the last day of any fiscal quarter, our ratio of net senior secured debt to EBITDAX for the trailing twelve months must not exceed 2.75 to 1.0. Our maximum net senior secured debt to EBITDAX ratio was lowered to 2.75 to 1.0 from 3.0 to 1.0 in connection with our senior note exchange described below. Our ratio of net senior secured debt to EBITDAX as of March 31, 2016 was approximately 2.1 to 1.0.

In order to improve our liquidity positions to meet the financial requirements under our Senior Credit Facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions including (i) debt-for-equity exchanges, (ii) joint venture opportunities, (iii) minimizing our capital expenditures, (iv) improving our cash flows from operations, (v) effectively managing our working capital, (vi) adding hedging positions, and (vii) in- and out-of-court restructuring. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period needed to meet certain obligations.

Senior Notes

On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our new Senior Secured Second Lien Notes (the “New Notes”) and (ii) 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the New Notes are greater than the net carrying value of the Existing Notes. As such, no gain has been recognized and a new effective interest rate has been established.

In exchange for $324.0 million in aggregate principal amount of the 2022 Notes, representing approximately 92.6% of the outstanding aggregate principal amount of the 2020 Notes, and $309.1 million in aggregate principal amount of the 2022 Notes,

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representing approximately 95.1% of the outstanding aggregate principal amount of the 2022 Notes, we issued (i) $633.7 million aggregate principal amount of New Notes and (ii) issued 8.4 million Shares, which had a fair value of $6.5 million upon issuance. An additional $0.5 million aggregate principal amount of New Notes were issued to holders who were ineligible to accept the Shares. In addition, upon closing, we paid in cash accrued and unpaid interest on the Existing Notes accepted in the Exchange from the applicable last interest payment date totaling approximately $12.8 million. The remaining Existing Notes will continue to accrue interest at their historical rates. The New Notes will bear interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and 8.0% per annum payable in cash thereafter. Interest payments are due on April 1 and October 1 of each year, beginning on October 1, 2016 and ending on October 1, 2020. In connection with the Exchange, we incurred approximately $8.5 million in third-party debt issuance costs. These costs were recorded as Debt Exchange Expense in our Statement of Operations for the three-month period ended March 31, 2016.

We may redeem, at specified redemption prices, some or all of the New Notes at any time on or after April 1, 2018. We may also redeem up to 35% of the New Notes using the proceeds of certain equity offerings completed before April 1, 2018. If we sell certain of our assets or experience specific kinds of changes in control, we may be required to offer to purchase the New Notes from the holders.

Our Existing Notes and New Notes (collectively, the “Senior Notes”) are recorded as Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets.    

The Senior Notes contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Senior Notes or are otherwise excepted or permitted.  Certain of the limitations in the Indentures, including our ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25:1.  As of March 31, 2016, our Fixed Charge Coverage Ratio was 1.00.  We expect our Fixed Charge Coverage Ratio to improve in 2016 based on our projections of decreased interest expense related to the New Notes. As of March 31, 2016, we were limited to incurring an additional $68.9 million in debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default. In certain circumstances, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.  

As of March 31, 2016 and December 31, 2015, we had recorded on our Consolidated Balance Sheets approximately $2.2 million and $2.3 million, respectively, of a net premium related to the Senior Notes. The amortization of our net premium during the three months ended March 31, 2016, which follows the effective interest method, was approximately $0.1 million and was recorded as a credit to Interest Expense on our Consolidated Statement of Operations. Interest is payable semi-annually on our Existing Notes. Interest on the 2020 Notes is paid at a rate of 8.875% per annum on June 1 and December 1 of each year while interest on the 2022 Notes is paid at a rate of 6.25% per annum on February 1 and August 1 of each year.

In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at March 31, 2016 and December 31, 2015:

 

 

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The following is the principal maturity schedule for debt outstanding as of March 31, 2016:

 

 

 

8. DERIVATIVE INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of March 31, 2016 and December 31, 2015, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, calls, basis swaps and three-way collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as Gain on Derivatives, Net.

We enter into the majority of our derivative arrangements with five counterparties and have a netting agreement in place with these counterparties. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. For additional information on the credit risk regarding our counterparties, see Note 6, Concentrations of Credit Risk, to our Consolidated Financial Statements.

None of our commodity derivatives are designated for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain on Derivatives, Net under Other Expense. We received net cash settlements of $13.0 million and $10.6 million in relation to our commodity derivatives during the three months ended March 31, 2016 and 2015, respectively.

As of March 31, 2016, we had approximately 100.0% of our annualized oil production hedged through the remainder of 2016, over 100.0% and 50.0% of our annualized natural gas production hedged through the remainder of 2016 and 2017, respectively, and over 40.0% our annualized NGL production hedged through the remainder of 2016. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future drilling and completion or the natural decline of our oil and gas production.

Interest Rate Derivatives

We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of March 31, 2016, and December 31, 2015, we had $158.0 million and $111.5 million outstanding under our Senior Credit Facility, respectively, which is subject to variable rates of interest and $675.0 million of Senior Notes outstanding subject to fixed interest rates. See Note 7, Long-Term Debt, to our Consolidated Financial Statements for additional information on our Senior Credit Facility and Senior Notes.

As of March 31, 2016 and December 31, 2015, we did not have any interest rate derivatives outstanding. We utilize the mark-to-market accounting method to account for interest rate swap and swaptions. We recognize all gains and losses related to interest rate derivatives in the Consolidated Statements of Operations as Gain on Derivatives, Net under Other Expense. During the three months ended March 31, 2015, we received cash payments of approximately $0.5 million related to our interest rate swaptions.

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The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three months ended March 31, 2016 and 2015:

 

 

Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net asset of approximately $26.8 million and $35.8 million at March 31, 2016 and December 31, 2015, respectively.

Our open asset/(liability) financial commodity derivative instrument positions at March 31, 2016 consisted of:

 

 

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The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015 is summarized below: 

 

 

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

Level 1—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date.

Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars and other like derivative contracts, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

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Level 3—Unobservable inputs that are supported by little or no market activity. Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Our Level 2 fair value measurements are comprised of our derivative contracts, excluding our basis swap derivatives, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of March 31, 2016 and December 31, 2015, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party.

Our Level 3 fair value measurements are comprised of our natural gas basis swap contracts. The fair values recorded as of March 31, 2016 and December 31, 2015, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. The significant unobservable input used in the fair value measurement of our natural gas basis swaps was the estimate of future natural gas basis differentials. Significant variations in price differentials could result in a significantly different fair value measurement. The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of March 31, 2016 and December 31, 2015 are included in the table below.

 

The fair value of our derivative instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers and sellers for such assets and liabilities. During the three months ended March 31, 2016 and for the year ended December 31, 2015, there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value:

 

 

Net derivative asset values are determined primarily by quoted futures and options prices and utilization of the counterparties’ credit default risk and net derivative liabilities are determined primarily by quoted futures and options prices and utilization of our credit default risk. The credit default risk of our counterparties and us are based on metrics such as interest coverage, operating cash flow and leverage ratios that calculate the likelihood that a firm will be unable to repay its lenders or fulfill payment obligations.

The value of our oil derivatives are comprised of three-way collar, call protected swap and deferred put spread contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair values attributable to our oil derivatives as of March 31, 2016 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of swap, collars, swaption, three way collar, basis swap, cap swap, call and put spread contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of March 31, 2016 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted

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forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of March 31, 2016 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments.

The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended March 31, 2016 and 2015:

 

 

Changes in fair value on our Level 3 commodity derivative contracts outstanding for each of the three months ended March 31, 2016 and 2015, resulted in decreases of approximately $2.0 million. This amount has been included in Gain on Derivatives, Net in our Consolidated Statements of Operations.  

Future Abandonment Cost

We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Future Abandonment Costs, to our Consolidated Financial Statements for further information on asset retirement obligations, which includes a reconciliation of the beginning and ending balances.

Financial Instruments Not Recorded at Fair Value

The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements:

 

 

The fair value of the secured lines of credit approximates carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and would be classified as Level 2 in the fair value hierarchy.

The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 1 in the fair value hierarchy. The fair value of our capital leases and other obligations are determined using a discounted cash flow approach based on the interest rate and payment terms of the obligations and assumed discount rate. The fair values of the obligations could be significantly influenced by the discount rate assumptions, which is unobservable. Accordingly, the fair value of the capital leases and other obligations would be classified as Level 3 in the fair value hierarchy.

The carrying values of all classes of cash and cash equivalents, accounts receivables and accounts payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

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Other Fair Value Measurements

During the three months ended March 31, 2016, we recorded an other than temporary impairment of $14.2 million related to proved and unproved properties. We utilize quoted futures prices and other observable market data in determining the fair value. The inputs used in determining fair value as a part of the impairment expense calculation are considered to be Level 2 within the fair value hierarchy. For additional information on our impairment expense, see Note 15, Impairment Expense, to our Consolidated Financial Statements.

 

 

9. INCOME TAXES

We recognize deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.

Income tax included in continuing operations was as follows:

 

 

For the three months ended March 31, 2016 and 2015, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due to the recording of a valuation allowance. As of March 31, 2016 and 2015, we had a significant level of estimated future tax benefits that, given our past and future expectations of net losses, we do not expect to be able to fully utilize, thus limiting our ability to recognize future tax benefits. As a result of the Exchange, we generated approximately $543.2 million in cancellation of debt income as calculated by comparing the fair value of the New Notes and the face value of the Existing Notes. We expect to offset this income by utilizing our net operating loss carryforwards, resulting in a projected alternative minimum tax payment of approximately $5.5 million.

Income tax payments made during the three months ended March 31, 2016 and 2015 were negligible.  We received tax refunds during the three months ended March 31, 2015 of approximately $0.5 million.

 

10. CAPITAL STOCK

Common Stock

We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of March 31, 2016 and December 31, 2015, shares of common stock issued and outstanding totaled 66,041,227 and 55,741,229, respectively. 

Preferred Stock

As of March 31, 2016 and December 31, 2015, shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”) issued and outstanding totaled 12,836 and 16,100, respectively. During the first quarter of 2016, approximately 3,264 shares of Series A Preferred Stock were converted into approximately 1.8 million shares of common stock pursuant to the terms of the Series A Preferred Stock.

The annual dividend on each share of the Series A Preferred Stock is 6.0% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on February 15, May 15, August 15 and November 15 of each year.

We pay cumulative dividends, when and if declared, in cash, stock or a combination thereof, on a quarterly basis at a rate of $600 per share, or 6.0%, per year. Dividends that are not declared and paid in accordance with the quarterly schedule will accumulate from the most recent date upon which dividends were paid but will not bear interest. In February 2016, we suspended our quarterly dividend payment. No dividend has been declared by our board of directors in 2016. As of March 31, 2016 accumulated dividends in arrears totaled $2.1 million.  While the accumulation does not result in the presentation of a liability on the Consolidated Balance Sheets, the accumulated dividends are added to our Net Loss in the determination of Loss Attributable to Common Shareholders and related loss per share calculations.

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In 2015, we paid quarterly cash dividends of $150.00 per share for the periods of November 15, 2014 to February 15, 2015, February 15, 2015 to May 15, 2015, May 15, 2015 to August 15, 2015, and August 15, 2015 to November 15, 2015, respectively, each in the aggregate amount of $2.4 million. If we do not pay dividends for six consecutive quarterly periods, the holders of the shares of Series A Preferred Stock will have the right to elect two additional directors to serve on our board of directors.

 

 

11. EMPLOYEE BENEFIT AND EQUITY PLANS

Equity Plans

We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals one vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as cash flows from financing activities, rather than as cash flows from operating activities.

Stock Options

During the three-month period ended March 31, 2016, we issued 851,422 options to purchase shares of our common stock to 29 employees. We issued 80,000 options to purchase shares of our common stock for the three months ended March 31, 2015. Stock-based compensation expense relating to stock options outstanding for the three months ended March 31, 2016 and 2015 was negligible. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense. There were no stock options exercised for the three months ended March 31, 2016 and 2015. There was no tax benefit for the three-month periods ended March 31, 2016 and 2015.

A summary of the status of our issued and outstanding stock options as of March 31, 2016 is as follows:

 

The weighted average remaining contractual term for options outstanding at March 31, 2016 was 5.5 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at March 31, 2016 was 1.9 years and there was no aggregate intrinsic value.  As of March 31, 2016, unrecognized compensation expense related to stock options was $0.5 million.  

Restricted Stock Awards

During the three-month period ended March 31, 2016, the Compensation Committee approved the issuance of an aggregate of 420,901 shares of restricted common stock to 22 employees. During the three-month period ended March 31, 2015, the Compensation Committee approved the issuance of an aggregate of 1,336,295 shares of restricted stock to 126 employees and one non-employee contractor. Certain of our outstanding restricted stock awards granted in 2015 are subject to market-based vesting through a calculation of total shareholder return (“TSR”) of our common stock relative to a pre-defined peer group over a three-year period.

 

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The weighted average fair value of the TSR awards granted as of December 31, 2015 was $2.56 per share. There were no TSR awards granted as of March 31, 2016.  Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions:

 

 

 

Compensation expense associated with restricted stock awards was negligible and $3.0 million for the three-month period ended March 31, 2016 and 2015, respectively. During the first quarter of 2016, 235,573 performance stock awards were forfeited due to not meeting specified targets, which resulted in a one-time reduction to expense of approximately $1.5 million. During the first quarter of 2015, the board of directors approved a waiver to certain performance factors for restricted stock awards that vested in March 2015. This waiver resulted in the vesting of 189,872 restricted stock awards with associated expense of approximately $2.5 million. As of March 31, 2016, total unrecognized compensation cost related to restricted common stock grants was approximately $3.6 million, which will be recognized over a weighted average period of 1.5 years.

 

A summary of the restricted stock activity for the three months ended March 31, 2016 is as follows:

 

 

 

12. COMMITMENTS AND CONTINGENCIES

Legal Reserves

We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations.

The accrual of reserves for legal matters is included in Accrued Liabilities on our Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

There have been no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015. 

Environmental

Due to the nature of the oil and natural gas business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews of our policies and properties to identify changes in the environmental risk profile. In these reviews we evaluate whether there is a probable liability, its amount and the likelihood that the liability will be incurred. The amount of any potential

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liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort.

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. As of March 31, 2016, we know of no significant probable or possible environmental contingent liabilities.

Letters of Credit

At March 31, 2016, we had posted $41.0 million in various letters of credit to secure our drilling and related operations.

Lease Commitments

As of March 31, 2016, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three months ended March 31, 2016 and 2015, was approximately $0.3 million and $0.2 million, respectively. Lease commitments by year for each of the next five years are presented in the table below:

 

 

Capacity Reservation

We have a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest in Butler County, Pennsylvania to process our produced natural gas. In the event that we do not process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $10.9 million in 2016, $16.5 million in 2017, $16.5 million in 2018, $16.5 million in 2019, $16.6 million in 2020 and $97.9 million thereafter, assuming our average net revenue interest in the region of approximately 53%. Charges incurred for unutilized processing capacity with MarkWest during the three-month period ended March 31, 2016 and 2015 were $0.6 million and $0.2 million, respectively.

Operational Commitments

We have contracted drilling rig services on one rig to support our Appalachian Basin operations. The minimum cost to retain this rig would require gross payments of approximately $1.7 million in 2016, $2.3 million in 2017 and $0.3 million in 2018, which would be partially offset by other working interest owners, which vary from well to well. During the first quarter of 2015, we terminated two rig contracts earlier than their original term. To satisfy the early release, we incurred approximately $4.8 million in early termination fees, which were classified as Other Operating Expense in our Consolidated Statement of Operations for the three months ended March 31, 2015. Approximately $2.3 million of this amount was paid in January 2015 and $2.5 million in January 2016. We also have agreements for contracted completion services in the Appalachian Basin. The minimum gross cost to retain the completion services is approximately $4.0 million in 2016, which would be partially offset by other working interest owners, which vary from well to well.

Natural Gas Gathering, Processing and Sales Agreements

During the normal course of business, we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our oil, natural gas and NGLs. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $418.0 million through 2021.

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For the three months ended March 31, 2016 and 2015, we incurred expenses related to the transportation, processing and marketing of our oil, natural gas and NGLs of approximately $21.5 million and $18.9 million, respectively. Expense related to these agreements makes up a substantial portion of our Lease Operating Expense, which we expect to continue as existing agreements commence and new transportation, processing and marketing agreements are entered that will enable us to sell our product. During the three months ended March 31, 2016 and 2015, we incurred approximately $0.4 million and $0.9 million, respectively, in fees related to unutilized capacity commitments. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:

 

 

Pennsylvania Impact Fee

In 2012, Pennsylvania state legislators instituted a natural gas impact fee on producers of unconventional natural gas. The fee is imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. The fee for each unconventional gas well is determined using the following matrix, with vertical unconventional gas wells being charged 20% of the applicable rates:

^(a) Pricing utilized for determining annual fee is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the 12-month period ending December 31.

All fees owed are due on April 1 of each year. For the three months ended March 31, 2016 and 2015, we recorded expense of approximately $0.5 million and $0.6 million, respectively. We record expenses related to the impact fees as Production and Lease Operating Expense. As of March 31, 2016, approximately $3.6 million was accrued for the 2015 impact fees and a portion of 2016 impact fees.

 

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13. EARNINGS PER COMMON SHARE

Basic loss per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For the three months ended March 31, 2016 and March 31, 2015, we excluded stock options to purchase 1.3 million shares and 0.5 million shares of our common stock, respectively, due to our Net Loss from Continuing Operations. For the three months ended March 31, 2016 and 2015, we excluded performance-based restricted stock of 0.7 million shares and 1.3 million shares, respectively, due to performance metrics that have not yet been attained (for additional information on our non-cash compensation plans, see Note 11, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). We utilize the if-converted method for calculating the impact of our 6.0% Convertible Perpetual Preferred Stock on diluted earnings per share. Under the if-converted method, convertible preferred stock is assumed as converted to common shares for the weighted average period outstanding. For the three months ended March 31, 2016, we excluded the assumed conversion of preferred stock equating to approximately 7.1 million shares due to our Net Loss from Continuing Operations. The following table sets forth the computation of basic and diluted earnings per common share:

 

 

 

  

14. EQUITY METHOD INVESTMENTS

RW Gathering, LLC

We own a 40% non-operated interest in RW Gathering, LLC (“RW Gathering”), which owns gas-gathering assets to facilitate development in our Appalachian Basin operations. During the second quarter of 2015 we incurred a 100% impairment charge of $17.5 million related to RW Gathering. We did not make any capital contributions to RW Gathering during the first three months of 2016 and 2015. During each of the three months ended March 31, 2016 and March 31, 2015, RW Gathering incurred net losses from continuing operations of $0.5 million. The loss incurred was due to insurance fees, bank fees, rent expenses and depreciation expense. Historically, we recorded our share of the net losses on the Statements of Operations as Loss on Equity Method Investments. As of June 30, 2015, we discontinued applying the equity method of accounting for our share of net losses due to our investment being reduced to zero.

During each of the three-month periods ended March 31, 2016 and 2015, we incurred approximately $0.2 million in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of March 31, 2016 and December 31, 2015, there were no receivables or payables due between RW Gathering and us.

 

15. IMPAIRMENT EXPENSE

For the three months ended March 31, 2016 and 2015, impairment expenses incurred were approximately $14.2 million and $7.0 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the first three months of 2016 included proved property impairments of approximately $3.5 million attributable to conventional oil properties in the Illinois

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Basin. In addition to the proved properties, we also incurred unproved property impairments of approximately $10.7 million related to unconventional assets in the Appalachian Basin. The impairments were identified through an analysis of market conditions and future development plans that were in existence as of each period end, related to these properties, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. The primary reason for the decrease in estimated future cash flows of our assets is attributable to the continued depression of current and estimated future commodity prices as of March 31, 2016. Our estimates of future cash flows attributable to our oil and gas properties could decline further if commodity prices continue to decline, which may result in our incurrence of additional impairment expense. As of March 31, 2016, we continued to carry the costs of undeveloped properties of approximately $257.7 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans.

The expenses incurred during the first quarter of 2015 included approximately $4.0 million related to proved properties in our non-operated dry gas region of Clearfield County, Pennsylvania. The remaining $3.0 million of impairment expense in the first quarter of 2015 was incurred in relation to undeveloped leases that expired or were expected to expire without being developed, primarily in the Appalachian Basin.

 

16. EXPLORATION EXPENSE

For the three months ended March 31, 2016 and 2015, we incurred approximately $1.0 million and $0.5 million, respectively, in exploration expenses.  Approximately $0.2 million of the expense incurred in 2016 was due to geological and geophysical type expenditures and the remaining $0.8 million was due to two exploratory wells that were abandoned at various stages that resulted in dry hole expense in the Appalachian Basin.  The expense incurred in 2015 was due to geological and geophysical type expenditures.

 

17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

As of March 31, 2016, we had an aggregate of $675.0 million of outstanding Senior Notes, as shown in Note 7, Long-Term Debt, to our Consolidated Financial Statements. The Senior Notes are guaranteed by certain of our wholly-owned subsidiaries, or guarantor subsidiaries. Unless otherwise noted below, each of the following guarantor subsidiaries are wholly-owned by Rex Energy Corporation and have provided guarantees of the Senior Notes that are joint and several and full and unconditional as of March 31, 2016:

The non-guarantor subsidiaries include certain consolidated subsidiaries, including Water Solutions, R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of March 31, 2016, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries.

The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of March 31, 2016 and December 31, 2015, the condensed consolidating statements of operations for each of the three-month periods ended March 31, 2016 and 2015, and the condensed consolidating statements of cash flows for each of the three-month periods ended March 31, 2016 and 2015.

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REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF MARCH 31, 2016

($ in Thousands)

 

 

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REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2016

($ in Thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDING MARCH 31, 2016

($ in Thousands)

 

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REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

AS OF DECEMBER 31, 2015

($ in Thousands)

 

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REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2015  

($ in Thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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REX ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDING MARCH 31, 2015

($ in Thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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18. SUBSEQUENT EVENTS

 

Debt and Preferred Stock Exchanges

 

During April 2016, we completed two privately negotiated exchanges of shares of our common stock for outstanding 2020 Notes, 2022 Notes, New Notes and our Series A Preferred Stock. In total, we exchanged approximately $17.2 million of 2020 Notes, $9.7 million of 2022 Notes, $2.2 million of New Notes and $13.8 million in face value of the Series A Preferred Stock for approximately 7.1 million shares of our common stock. In each transaction, the holders waived all accrued and unpaid interest. The shares of our common stock were issued under Section 3(a)(9) of the Securities Act of 1933, as amended.

 

Borrowing Base Reduction

 

In conjunction with the Exchange, effective April 1, 2016, we amended certain terms of our Senior Credit Facility including the reduction of our borrowing base from $200.0 million to $190.0 million effective April 1, 2016. As of March 31, 2016, we had approximately $158.0 million outstanding under our Senior Credit Facility and $41.0 million of undrawn letters of credit. On April 1, 2016, we paid down borrowings under our Senior Credit Facility by $9.5 million on April 1, 2016 to be in compliance with the amendment. This amount was recorded as Current Maturities of Long-Term Debt on our Consolidated Balance Sheet as of March 31, 2016.

 

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The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements for the year ended December 31, 2015 included in our Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

We use a variety of financial and operational measurements at interim periods to analyze our performance. These measurements include an analysis of production and sales revenue for the period; EBITDAX, a non-GAAP financial measurement; lease operating expenses per Mcf equivalent (“LOE per Mcfe”); and general and administrative (“G&A”) expenses per Mcfe.

Overview of Our Business

We are an independent oil and gas company operating in the Appalachian Basin and the Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. In the Illinois Basin we are focused on our developmental oil drilling on our properties. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties. We are headquartered in State College, Pennsylvania, and have regional offices in Bridgeport, Illinois and Cranberry, Pennsylvania.

We believe the outlook for our business is favorable despite the continued uncertainty of oil and gas prices. Our resource base, risk management, including an active hedging program, and disciplined investment of capital provide us with an opportunity to exploit and develop our positions and maximize efficiency in our key operating areas. We continue to focus on maintaining financial flexibility while pursuing an active, technology-driven drilling program to develop and maximize the value of our existing acreage as market conditions continue to evolve.

However, a continued prolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities of our proved reserves, and may result in write-downs of the carrying values of our oil and natural gas properties and revisions to our capital budget or development program. We discuss these matters in further detail under, among other places, “Commodity Prices,” “Impairment Expense,” “Capital Resources and Liquidity,” and “Volatility of Oil, NGL and Natural Gas Prices” below as well as in Note 15, “Impairment Expense”, to our Consolidated Financial Statements.

We have historically divided our operations into two principal business segments, exploration and production and field services. During the third quarter of 2015, we sold Water Solutions Holdings, LLC (“Water Solutions”) and its related subsidiaries, which accounted for the majority of our field services segment. The sale of Water Solutions closed in July 2015, and we received approximately $66.8 million in proceeds for our 60% interest, net of customary selling expenses. Unless otherwise noted, information presented in management’s discussion and analysis are for continuing operations.

2016 Activity

During the three months ended March 31, 2016, we produced 17,251 MMcfe in the Appalachian Basin. In the Illinois Basin, we produced 158 MBbls during the three months ended March 31, 2016. Overall, our production for the three months ended March 31, 2016 averaged 200 MMcfe per day. As of March 31, 2016, we had five gross (1.8 net) wells drilled and awaiting completion and four gross (2.0 net) wells resting or awaiting pipeline connection. Our drilling and completion activity for the period indicated in each of our regions is set forth in the table below.

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Three Months Ended March 31, 2016 and 2015

 

 

Commodity Prices

Our development plans are sensitive to current and projected commodity prices which have been and are expected to continue to be volatile. Our realized price, before derivative settlements, for oil during the three months ended March 31, 2016, averaged approximately $28.71 per barrel, as compared to $39.54 per barrel for the same period in 2015. Our realized price, before derivative settlements, for natural gas during the three months ended March 31, 2016, averaged approximately $1.37 per Mcf, as compared to $2.46 per Mcf for the same period in 2015. Our realized price, before derivative settlements, for C3+ NGLs during the three months ended March 31, 2016, averaged approximately $12.20 per barrel, as compared to $11.50 per barrel for the same period in 2015. Our realized price, before derivative settlements, for ethane during the three months ended March 31, 2016, averaged approximately $6.04 per barrel, as compared to $6.58 per barrel for the same period in 2015.

For the three months ended March 31, 2016, we recorded impairment expense of approximately $14.2 million. Further decreases in commodity prices will decrease our oil, NGL and natural gas revenues and could reduce the amount of oil, NGL and natural gas reserves that we can economically produce. A prolonged period of depressed commodity prices or further declines in projected future commodity prices could require additional write-downs of the carrying values of our properties.

Because we follow the successful efforts method of accounting our impairment tests are largely based on estimates of future commodity prices, changes in development and operating costs, taxes, operational efficiencies, changes in technology and access to capital, which makes predicting any future write-downs difficult and uncertain. In an effort to quantify the impact of continued low commodity pricing levels or further declines in future prices, we offer the following: as of March 31, 2016, approximately 76% of our evaluated oil and natural gas properties were located in our Butler Marcellus operating area. Estimated future cash flows for these properties as of March 31, 2016, exceeded net book value by over 50%, indicating that substantial further decreases in commodity prices combined with a lack of access to capital or a detrimental change to costs or operating efficiencies, would need to occur in order for us to experience a write-down. Our remaining evaluated properties outside of the Butler Marcellus operating area are more sensitive to the current commodity price environment. These properties could experience additional write-downs if estimates of future commodity prices decline further. The net book value of these remaining evaluated and unevaluated properties total approximately $145.7 million.

Senior Note Exchange

On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our new Senior Secured Second Lien Notes (the “New Notes”) and (ii) 10.1 million shares of our common stock (the “Shares”).

In exchange for $324.0 million in aggregate principal amount of the 2022 Notes, representing approximately 92.6% of the outstanding aggregate principal amount of the 2020 Notes, and $309.1 million in aggregate principal amount of the 2022 Notes, representing approximately 95.1% of the outstanding aggregate principal amount of the 2022 Notes, we issued (i) $633.7 million aggregate principal amount of New Notes and (ii) issued 8.4 million Shares. An additional $0.5 million aggregate principal amount of

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New Notes were issued to holders who were ineligible to accept the Shares. In addition, upon closing we paid in cash accrued and unpaid interest on the Existing Notes accepted in the Exchange from the applicable last interest payment date totaling approximately $12.8 million. The New Notes will bear interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and 8.0% per annum payable in cash thereafter. Interest payments are due on April 1 and October 1 of each year, beginning October 1, 2016 and ending on October 1, 2020. In connection with the Exchange, we incurred approximately $8.5 million in third-party debt issuance costs. These costs were recorded as Loss on Debt Restructuring in Statement of Operations for the three-month period ended March 31, 2016.

Benefit Street Partners, LLC Joint Venture

On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP will participate and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, 12 of which have already been drilled and completed, and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, three of which have already been drilled and completed. We expect total consideration for this transaction to be $175.0 million with $37.1 million committed at closing. As of March 31, 2016, BSP had paid approximately $19.5 million for their interest in wells that had previously been completed. The remainder of the proceeds will be received as additional wells are completed. BSP has the option to participate in the development of 36 additional wells in 2016 and would fund 65.0% of the estimated well costs for the designated well in return for 65.0% working interest. In addition, BSP will earn a 15%-20% working interest in each of the units that they participate. As of March 31, 2016, 15 of the initial 22 wells were in line and producing, three wells were drilled and awaiting completion and four wells were awaiting pipeline connection. In April 2016, BSP exercised their option to participate in four additional wells to be drilled and completed later in 2016.

Results of Continuing Operations

The following table sets forth summary information regarding oil, NGL and natural gas production and product prices for the three months ended March 31, 2016 and 2015.

 

 

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The following table sets forth summary information by basin regarding oil, NGL and natural gas revenues, production volumes, average product prices and average production costs for the three months ended March 31, 2016 and 2015.

 

General Overview

Operating revenue for the three months ended March 31, 2016 decreased 43.6% when compared to the same period in 2015. The decrease in operating revenue for the three months ended March 31, 2016, can be primarily attributed to lower commodity prices and lower production in the Illinois Basin, partially offset by higher production in the Appalachian Basin. In the Appalachian Basin, our production grew to 17,250.8 MMcfe for the three-month period ended March 31, 2016, from 16,577.2 MMcfe for the three-month period ended March 31, 2015, or approximately 4.1%, while production in the Illinois Basin decreased to 158.3 MBbls during the quarter ended March 31, 2016, from 179.8 MBbls during the same period in 2015, or approximately 12.0%. The decrease in production in Illinois is primarily related to the natural decline of our conventional oil producing properties in conjunction with shutting in certain wells that are marginally economic. We are currently evaluating strategies to reduce the production declines in the Illinois Basin and will continue to be opportunistic with new well development.

For the three months ended March 31, 2016, we spent approximately $20.3 million on drilling projects, facilities and related equipment, undeveloped acreage and asset acquisitions, which was offset by approximately $19.5 million in proceeds from BSP. Approximately 96.5% of our capital expenditures in 2016 have been in the Appalachian.

Operating expenses decreased $6.5 million for the three months ended March 31, 2016, as compared to the same period in 2015. Operating expenses primarily comprise: Production and Lease Operating Expenses, G&A Expenses, Other Operating Expense, Exploration Expenses, Impairment Expense and DD&A Expenses. The decreases in operating expenses were largely attributable to G&A Expenses, DD&A and Other Operating Expense. The decrease of many of these operating expenses is consistent with the overall decrease in activity within the industry in conjunction with a decrease in the cost of goods and services and other cost control measures that we have implemented.

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Comparison of the Three Months Ended March 31, 2016 to the Three Months Ended March 31, 2015

Oil, NGL and gas revenue, including the effects of cash settled derivatives, for the three-month periods ended March 31, 2016 and 2015 is summarized in the following table:  

Average realized price received for oil, NGLs and natural gas during the first quarter of 2016, after the effect of derivative activities, was $2.40 per Mcfe, a decrease of 34.4%, or $1.26 per Mcfe, from the same period in 2015. This decrease was primarily due to a decrease in commodity prices during the quarter, partially offset by positive cash settlements on derivatives. The average price for natural gas, after the effect of derivative activities, decreased 28.0%, or $0.82 per Mcf, to $2.10 per Mcf. The average price for oil and condensate, after the effect of derivative activities, decreased 28.5%, or $14.64 per barrel, to $36.78 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, decreased 30.4%, or $7.97 per barrel, to $18.24 per barrel. The average price for ethane, including the effect of derivatives, during the three months ended March 31, 2016 was approximately $6.37 per barrel as compared to $6.70 per barrel during the same period in 2015. Our derivative activities effectively increased net realized prices by $0.72 per Mcfe in the first quarter of 2016 and $0.60 per Mcfe in the first quarter of 2015.

Our realized sales price for natural gas differed from the average Henry Hub NYMEX pricing by approximately $0.62 per Mcf during the first quarter of 2016 primarily due to basis differentials in the northeastern United States, which were partially offset by sales on the Texas Eastern pipeline, receiving M3 pricing, a New York area index. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. In addition, we have been targeting sales points outside of the northeastern United States and have executed capacity agreements to transport natural gas volumes to the Midwest and the Gulf Coast.

Production volumes in the first quarter of 2016 increased 3.1% from the first quarter of 2015 primarily due to success of our Marcellus and Utica Shale horizontal drilling activities in the Appalachian Basin, where production increased approximately 4.1%, or 673.6 Mcfe. Natural gas production decreased approximately 1.7%, oil and condensate production decreased approximately 29.8%, C3+ NGL production decreased approximately 6.0% and our ethane production increased approximately 131.7%. Our production continues to be positively impacted by strong drilling results in the Appalachian Basin.

Overall, our production for the first quarter of 2016 averaged 200,006 Mcfe per day, of which 62.8% was attributable to natural gas, 9.8% to oil and condensate, 17.3% to C3+ NGLs and 10.0% was a result of ethane production.

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Statements of Operations for the three-month periods ended March 31, 2016 and 2015 are as follows:

 

Production and Lease Operating Expense increased approximately $1.1 million, or 3.8%, in the first quarter of 2016 from the same period in 2015. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells in the Appalachian Basin and related production as they relate to variable type costs such as transportation, marketing, processing and gathering. Transportation, marketing, processing and gathering fees accounted for approximately 71.2% of our total Production and Lease Operating Expense in the first quarter of 2016, as compared to 65.0% from the same period in 2015. During the first quarter of 2016, approximately $0.4 million of our Production and Lease Operating Expense was related to unutilized transportation, capacity and processing commitments, as compared to $0.8 million for same period in 2015. As we continue to develop our core areas of operation we expect that fees incurred from unutilized commitments will decrease. These types of agreements typically have a term of several years and we expect fees associated with these agreements to continue to comprise a significant portion of our Production and Lease Operating Expense. On a per unit of production basis, our lifting costs increased to $1.66 per Mcfe in the three months ended March 31, 2016 from $1.65 per Mcfe in the same period in 2015.

G&A Expense for the first quarter of 2016 decreased approximately $3.6 million, or 37.2%, to $6.1 million from the same period in 2015. We have undertaken several cost control measures during the first three months of 2016, including reductions in bonus compensation, reductions in head count, a decrease in travel expenditures, less usage of third-party consultants and pricing concessions received from suppliers and service providers.  During the first quarter of 2016, the board of directors approved certain performance factors for restricted stock that vested in March 2016.  These performance factors resulted in reduced expense due to forfeitures on performance-based restricted stock awards of approximately $1.6 million.

Impairment Expense for the first quarter of 2016 was approximately $14.2 million. We evaluate impairment of our properties when events occur that indicates that the carrying value of these properties may not be recoverable. The expense incurred during the first quarter of 2016 included $3.5 million of proved property impairment and $10.7 million of undeveloped acreage impairment.  The proved property impairment of approximately $3.5 million was attributable to our conventional oil properties in the Illinois Basin.  The unproved property impairment consisted of approximately $10.7 million in the Appalachian Basin. Based on the current commodity price environment, we do not expect to develop these properties prior to expiration of the associated leases.  The impairments were identified through an analysis of market conditions and future development plans related to these properties that were in existence as of March 31, 2016, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. Any amount of future impairments are difficult to predict, however, if commodity prices decline further, downward revisions of proved reserves may be significant and could result in additional impairment expense.

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Approximately $4.0 million of the expense incurred during 2015 was due to non-operated dry gas proved properties in Clearfield County, Pennsylvania and was directly attributable to the decrease in current and estimated future natural gas pricing as of March 31, 2015. The remaining $3.0 million was due to unproved property impairments related to expiring leases that will not be developed.

Exploration Expense for the first quarter of 2016 was approximately $1.0 million, as compared to $0.5 million for same period in 2015. Approximately $0.2 million of the expense incurred in 2016 was due to geological and geophysical type expenditures and $0.8 million was due to two exploratory wells that were abandoned at various stages that resulted in dry hole expense in the Appalachian Basin. The expense incurred in 2015 was due to geological and geophysical type expenditures.  As a result of the decrease in commodity prices, we have decreased our levels of spending with regards to geological and geophysical activities.

DD&A Expense for the first quarter of 2016 decreased approximately $6.7 million, or 25.7%, from $26.1 million for the same period in 2015. Contributing to the decrease in DD&A expense were lower first quarter depreciable asset value from impact of 2015 impairment, partially offset by lower year end reserves, which were triggered by the ongoing lower commodity pricing environment and the related effect on our estimated proved reserves, when compared to the same period in 2015.

Other Operating Expense for the first quarter of 2016 decreased to approximately $0.3 million from $5.2 million in the first quarter of 2015. The decrease in expense is related to the early termination of two drilling rig contracts before expiration of their original term during the first quarter of 2015. Our net termination expenses totaled approximately $5.0 million.

Interest Expense for the first quarter of 2016 was approximately $13.0 million as compared to $12.0 million for the same period in 2015. The increase in interest expense is primarily due to having a larger outstanding balance on our Senior Credit Facility for the quarter compared to the outstanding balance for the same period in 2015. We discuss our senior notes and revolving credit facility in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Gain on Derivatives, net included a gain of approximately $4.0 million for the first quarter of 2016 as compared to a gain of $17.1 million for the same period in 2015. The gain recorded for the first quarter of 2016 included cash receipts for commodity derivatives of $13.0 million while the gain incurred in the first quarter of 2015 included cash receipts of approximately $11.1 million for commodity and interest rate derivatives. Changes were attributable to the volatility of oil, NGL and natural gas commodity prices along with changes in our portfolio of outstanding derivatives. Losses from derivative activities generally reflect higher oil, NGL and natural gas prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of oil, NGL and gas production volumes given the highly volatile oil, NGL and gas commodities market.

We believe oil, NGL and natural gas prices will remain volatile and could decline further. Although we have entered into derivative contracts covering a portion of our production volumes for the remainder of 2016 and 2017, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future.

Debt Exchange Expense for the first quarter of 2016 totaled approximately $8.5 million. These charges relate to our exchange of senior unsecured notes for senior secured second lien notes completed on March 31, 2016. We accounted for the exchange as a troubled debt restructuring, which mandates that current third-party expenses be charged against income in the current period.

Income Tax (Expense) Benefit was an expense of approximately $2.1 million for the first quarter of 2016, as compared to a benefit of $0.1 million for the same period in 2015. Our effective tax rate during the three months ended March 31, 2016 was approximately (3.6%), as compared to 0.5% during the comparable period in 2015. Our effective tax rate in the first quarter of 2016 was different than the statutory rate of 35% due to the recording of a valuation allowance. As of March 31, 2016, we had a significant level of future tax benefits, some of which are not expected to be fully utilized, therefore limiting our ability to recognize further tax benefits. As a result of the Exchange, we generated approximately $543.2 million in cancellation of debt income as calculated by comparing the fair value of the New Notes and the face value of the Existing Notes. We expect to offset this income by utilizing our net operating loss carryforwards, resulting in a projected alternative minimum tax payment of approximately $5.5 million.

Net Loss Attributable to Rex Energy for the first quarter of 2016 was approximately $60.1 million of loss as compared to $17.8 million for the same period in 2015 as a result of factors discussed above.

 

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EBITDAX (Non-GAAP)

EBITDAX (Non-GAAP) from continuing operations decreased approximately $22.4 million to $6.9 million for the three-month period ended March 31, 2016, as compared to the same period in 2015.  The decrease in EBITDAX can be primarily attributed to decreased average sales prices for oil, natural gas and NGLs, resulting in decreased operating revenues. See “Non-GAAP Financial Measures” for our reconciliation of EBITDAX to net income.

LOE per Mcfe

LOE per Mcfe measures the average cost of extracting oil, NGLs and natural gas from our basin reserves during the period. This measurement is also commonly referred to in the industry as our “lifting cost”. It represents the average cost of extracting one Mcf of natural gas equivalent from our oil, NGL and natural gas reserves in the ground. LOE per Mcfe increased to $1.66 for the three months ended March 31, 2016, as compared to $1.65 for the same period in 2015. Our LOE is largely comprised of variable type costs such as transportation, marketing, processing and gathering. For the first three months of 2016, transportation, capacity and processing fees accounted for approximately 71.2% of our total Production and Lease Operating Expense as compared to 65.0% during the same period of 2015. These agreements typically have a term of several years, and we expect them to continue to comprise a significant portion of our Production and Lease Operating Expense. Various agreements that we have entered include firm capacity rights, for which we may incur a fee for unused capacity. The increase in our LOE per Mcfe when comparing the three months ended March 31, 2016 to same period in 2015, is primarily due to our increased production in the Appalachian Basin combined with our relatively consistent levels of fixed expenses. As we continue to grow our operations, particularly those in the Appalachian Basin, which have lower operating costs, we expect our lifting cost to decrease as we gain additional efficiencies of scale and utilize all of our firm capacity and transportation commitments.

G&A Expenses per Mcfe

Our G&A expenses include fees for well operating services, marketing, non-field level employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our G&A expenses in relation to our production because these expenses have a direct impact on our profitability. G&A expenses per Mcfe decreased to approximately $0.33 for the three-month period ended March 31, 2016, as compared to $0.55 for the same period in 2015. The year-over-year decrease is predominately due to further cost control measures and headcount reductions implemented during first quarter 2016 in response to our decreased capital plan related to commodity price declines combined with our increase in production.

Capital Resources and Liquidity

Our primary needs for cash are for the exploration, development and acquisition of oil and gas properties. During the three months ended March 31, 2016, we spent $20.3 million of capital on asset acquisitions, drilling projects, facilities and related equipment and acquisitions of unproved acreage, which was partially offset by $19.5 million in proceeds we received from the closing of the BSP joint venture. We funded our capital program with proceeds from our Senior Credit Facility, cash flow from operations and with funds we received from the closing of the BSP joint venture. The remainder of our 2016 capital budget of $15.0 million to $40.0 million is expected to be funded primarily by cash on hand, cash flow from operations, and potential future asset sales and joint ventures.

Our cash flows from operations are driven by commodity prices and production volumes. Prices for oil, NGLs and gas are driven by, among other things, seasonal influences of weather, national and international economic and political environments and, increasingly, from national and global supply and demand for hydrocarbons. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Historically, cash flows from operations, borrowings from our revolving credit facility and net proceeds from debt and equity offerings have been primarily used to fund exploration and development of our oil and gas interests. As of March 31, 2016, we had approximately $24.9 million of cash on hand and outstanding borrowings under our $200.0 million revolving credit facility of approximately $158.0 million with an additional $41.0 million of undrawn letters of credit outstanding. In conjunction with the closing of our Exchange of Existing Notes, our borrowing base was reduced to $190.0 million on April 1, 2016. The next borrowing

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base redetermination will occur on or about July 1, 2016. In May 2016, a third-party midstream partner drew an outstanding letter of credit in the amount of $3.9 million related to an ongoing gas transportation project for which we declined to provide additional collateral. Both parties intend to honor the original transportation agreement and the terms within that agreement.

Our ability to fund our capital expenditure program is dependent upon the level of commodity prices and the success of our exploration programs in replacing our existing oil, NGL and natural gas reserves. If commodity prices decrease further, our operating cash flows may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. The effects of commodity prices on cash flows can be mitigated through the use of commodity derivatives. If we are unable to replace our oil, NGL and natural gas reserves through our acquisitions, development and exploration programs, we may also suffer a reduction in our operating cash flows and access to funds under our revolving credit facility. At March 31, 2016, we were in compliance with all required debt covenants under our revolving credit facility, with the exception of our minimum current ratio requirement of 1.0 to 1.0 for which we received a waiver from the lenders for the period ended March 31, 2016. Subsequent to March 31, 2016, we expect this ratio to improve and do not expect to incur any covenant violations.

Due to the current depressed commodity price environment, in January 2016, we suspended payment of our quarterly dividend on shares of our Series A Convertible, Perpetual Preferred Stock. We have the ability to continue to suspend dividend payments and will continue to evaluate the payment of these dividends on a quarterly basis. As a result of not declaring the first quarter dividend on our Series A Preferred Stock, we are no longer eligible to use Form S-3 registration statements. Until we are again eligible to use Form S-3, we will be required to use a registration statement on Form S-1 to register securities with the SEC (for initial issuance or resale) or issue securities in private placements, which could increase the cost of raising capital. We may need to take additional actions in the future to address current industry trends and maintain our ability to pay expenses and service our indebtedness, including, but not limited to, selling assets or raising capital by issuing additional debt or equity securities.

We have Existing Notes and New Notes (together, the “Senior Notes”) that are governed by indentures with substantially similar terms and provisions (the “Indentures”).  The Indentures contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted.  Certain of the limitations in the Indentures, including our ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25:1.  As of March 31, 2016, our Fixed Charge Coverage Ratio was 1.00:1.  We expect our Fixed Charge Coverage Ratio to improve in 2016 based on our projections of decreased interest expense related to our Senior Notes.  As of March 31, 2016, we were limited to incurring an additional $68.9 million in debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default, including cross-default features with any other indebtedness. In certain circumstances, the Trustee or the holders of the Senior Notes may declare all outstanding notes to be due and payable immediately.

We are not restricted as to our borrowings under our revolving credit facility; however we are subject to the minimum financial requirements detailed in Note 7, Long-Term Debt, to our Consolidated Financial Statements. If we are unable to comply with these financial requirements, an event of default could result which would permit acceleration of outstanding debt and could permit our lenders to foreclose on our mortgaged properties. In order to improve our liquidity position to meet the financial requirements under our revolving credit facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions including (i) debt-for-equity exchanges, (ii) joint venture opportunities, (iii) minimizing our capital expenditures, (iv) improving our cash flows from operations, (v) effectively managing our working capital (vi) adding additional hedging positions and (vii) in- and out-of-court restructuring. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transaction can be consummated within the period needed to meet certain obligations. In addition, our Senior Credit Facility restricts the amount of cash and cash equivalents that we can hold on our Consolidated Balance Sheet to a maximum of $15.0 million, with any excess to be used to pay down the outstanding Senior Credit Facility balance, however we retain the right to draw on the revolving credit facility so long as there are amounts available under our borrowing base.

Future Liquidity Considerations

In connection with certain marketing, transportation and processing agreements that we have entered into, we may be obligated to pay minimum fees in connection with these agreements of $232.1 million over the next five years, depending on our levels of production. In connection with certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $418.0 million over the life of the agreements. As the commitments are satisfied, these guarantees will decrease over time.

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Our revolving credit facility contains a number of restrictive covenants and limitations that will impose significant operating and financial restrictions on us. In particular, our financial covenants require us to maintain a minimum consolidated current ratio of 1.0 to 1.0 and a maximum ratio of net senior-secured debt to EBITDAX, a non-GAAP measure, of 2.75 to 1.0. Failure to comply with these covenants could have an adverse effect on our business. If an event of default under our revolving credit facility occurs and remains uncured, the lenders thereunder:

 

 

In order to improve our liquidity positions to meet the financial requirements under our revolving credit facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions including (i) debt-for-equity exchanges, (ii) joint venture opportunities, (iii) minimizing our capital expenditures, (iv) improving our cash flows from operations, (v) effectively managing our working capital, (vi) adding hedging positions, (vii) and in- and out-of-court restructuring. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period needed to meet certain obligations.

Financial Condition and Cash Flows for the Three Months Ended March 31, 2016 and 2015

The following table summarizes our sources and uses of funds for the periods noted:

 

Net cash provided by (used in) operating activities decreased from cash provided by operating activities of $11.4 million in the first quarter of 2015 to cash used of $18.9 million for the same period in 2016. This was primarily due to a reduction in oil, natural gas and NGL prices and an increase in lease operating expenses. These decreases in cash flow were partially offset by increases in production in our Appalachian Basin operations and a decrease in Other Operating Expenses.

Net cash used in investing activities decreased by approximately $66.3 million from the first three months of 2016 to $0.8 million as compared to the same period in 2015. This change is primarily attributed to lower activity levels related to the currently depressed commodity price environment and $19.5 million received from our joint venture with BSP in 2016 compared with the $67.9 million of capital activity during the first quarter of 2015, net of $16.6 million received from our joint venture with ArcLight.

Net cash provided by financing activities increased by approximately $0.5 million for the first three months of 2016 to $43.5 million from $43.0 million over the same period in 2015. The increase in cash provided is primarily due to dividends paid and contributions to consolidated joint venture partners in the first quarter of 2015, which was partially offset by higher debt issuance costs during the first quarter of 2016.

As market conditions warrant and subject to our contractual restrictions in the Credit Facility or otherwise, liquidity position and other factors, we may from time to time seek to recapitalize, refinance or otherwise restructure our capital structure in open market or privately negotiated transactions, which may include, among other things, repurchases of shares of our common stock or outstanding debt, including our senior unsecured notes, by tender offer or otherwise. The amounts involved in any such transaction, individually or in the aggregate, may be material.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing oil, NGL and natural gas prices. If the price of oil, NGLs and natural gas increases or decreases, there could be a corresponding increase or decrease in the operating cost that we are required to bear for operations, as well as an increase or decrease in revenues.

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Critical Accounting Policies and Recently Adopted Accounting Pronouncements

During the quarter ended March 31, 2016, there were no material changes to the critical accounting policies previously reported by us in our Annual Report on Form 10-K for the year ended December 31, 2015. We describe critical recently adopted and issued accounting standards in Part I, Item 1. Financial Statements—Note 5, “Recently Issued Accounting Pronouncements.”

Non-GAAP Financial Measures

EBITDAX

“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, DD&A, unrealized losses from financial derivatives, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of its financial statements, such as our commercial bank lenders to analyze such things as:

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (the most directly comparable GAAP financial measure) in measuring our performance, nor should it be used as an exclusive measure of cash flows, because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions, and other sources and uses of cash, which are disclosed in our consolidated statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and because this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.

We believe that EBITDAX assists our lenders and investors in comparing our performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs. In addition, because we use capital assets, DD&A are also necessary elements of our costs. Finally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.

To compensate for these limitations, we believe it is important to consider both net income determined under GAAP and EBITDAX to evaluate our performance.

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The following table presents a reconciliation of our net income to EBITDAX for each of the periods presented:

 

¹ Non-Recurring costs for the three months ended March 31, 2016 are due to debt issuance costs related to our exchange of unsecured senior notes. Non-Recurring costs for the three months ended March 31, 2015 are due to net fees incurred to terminate two drilling rig contracts earlier than their original term.

Volatility of Oil, NGL and Natural Gas Prices

Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil, NGLs and natural gas. We account for our natural gas and oil exploration and production activities under the successful efforts method of accounting. To mitigate some of our commodity price risk, we engage periodically in certain other limited derivative activities including price swaps and costless collars in order to establish some price floor protection.

For the three months ended March 31, 2016, we received net settlements on oil, NGL and natural gas derivatives of approximately $13.1 million as compared to receiving net settlements of approximately $10.6 million for the three months ended March 31, 2015. These gains and losses are reported as Gain on Derivatives, Net in our Consolidated Statements of Operations. As of March 31, 2016, we had approximately 100.0% of our annualized oil production hedged through the remainder of 2016, over 100.0% and 50.0% of our annualized natural gas production hedged through the remainder of 2016 and 2017, respectively, and over 40.0% of our annualized NGL production hedged through the remainder of 2016. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future drilling and completion activity or the natural decline of our oil and gas production.

Our primary sources of production and revenue are located in the Appalachian Basin. Natural gas prices in the Appalachian Basin are exposed to regional differentials when compared to NYMEX pricing. During the three months ended March 31, 2016, our average realized prices for natural gas was lower than the average NYMEX prices over the same period by approximately $0.62 per Mcf. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. We have basis swaps in place for 17,665 MMcf at an average differential to Henry Hub NYMEX of $0.89 per Mcf for the remainder of 2016 in addition to basis swaps for 19,150 MMcf at an average differential to Henry Hub NYMEX of $0.30 per Mcf for 2017. For the three months ended March 31, 2016, we paid cash settlements on our basis differential derivatives of approximately $0.3 million.

While the use of derivative arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of oil, NGLs and natural gas. We enter into all of our derivatives transactions with five counterparties and have a netting agreement in place with our counterparties. While we do not obtain collateral to support the agreements, we do monitor the financial viability of our counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have additional risk of financial loss because the price received for the product at the actual

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physical delivery point may differ from the prevailing price at the delivery point required for settlement of the derivative transaction. Moreover, our derivatives arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivatives will vary from time to time.

For a summary of our current oil, NGL and natural gas derivative positions at March 31, 2016, refer to Part I, Item 1. Financial Statements—Note 8, “Derivative Instruments and Fair Value Measurements”.

Contractual Obligations

In addition to our capital expenditure program, we are committed to making cash payments in the future on various types of contracts and obligations. Our contractual obligations include long-term debt, operating leases, operational commitments, other loans and notes payable, derivative obligations, firm commitments under sales, gathering and processing agreements and asset retirement obligations. Since December 31, 2015, there have been no material changes to our contractual obligations, other than an increase in long-term debt due to our borrowings under the Senior Credit Facility. See Part I, Item 1. Financial Statements—Note 7, “Long-Term Debt” for additional information on the Senior Credit Facility.

Off-Balance Sheet Arrangements

We do not currently use any off-balance sheet arrangements to enhance our liquidity or capital resource position, or for any other purpose.

We are exposed to various market risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decrease for a substantial period of time or decline significantly, revenues and cash flows would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, NGLs and natural gas. Conversely, increases in the market prices for oil, NGLs and natural gas can have a favorable impact on our financial condition, results of operations and capital resources. Based on production through March 31, 2016, we project that a 10% decline in the price per barrel of oil and NGLs and the price per Mcf of gas from the first three months of the 2016 average would reduce our gross revenues, before the effects of derivatives, for the remaining nine months of 2016 by approximately $9.1 million.

We have designed our hedging program to reduce the risk of price volatility for our production in the oil, NGL and natural gas markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we use include swaps, collars, put spreads, put options, basis swaps, swaptions and three way collars. The volume of derivative instruments that we may use are governed by the risk management policy and can vary from year to year, but under most circumstances will apply to only a portion of our current and anticipated production, and will provide only partial price protection against declines in oil, NGL and natural gas prices. We are exposed to market risk on our open contracts, to the extent of changes in market prices of oil, NGLs and natural gas. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties should default, this protection might be limited as we might not receive the benefits of the hedges.

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At March 31, 2016, we had the following commodity derivative contracts outstanding:

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and prime rate based, as determined by our lenders, and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on our obligations. As of March 31, 2016, we did not have any interest rate derivatives in place, however we do from time to time enter interest rate derivatives to manage our interest rate exposure. We did not have any interest rate derivatives in place as of December 31, 2015. Based on our total debt as of March 31, 2016 of approximately $833.4 million, a 1.0% change in interest rates would impact our interest expense by approximately $8.3 million.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Such controls include those designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), to allow timely decisions regarding required disclosure.

Our management (with the participation of our CEO and CFO) has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our CEO and CFO have concluded that, as of March 31, 2016, our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were effective to provide reasonable assurance that information

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required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) promulgated under the Exchange Act) during the quarter ended March 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations Inherent in All Controls

Our management, including our CEO and CFO, recognizes that the disclosure controls and procedures and internal controls (discussed above) cannot prevent all errors or all attempts at fraud. Any controls system, no matter how well-crafted and operated, can only provide reasonable, and not absolute, assurance of achieving the desired control objectives. Because of the inherent limitations in any control system, no evaluation or implementation of a control system can provide complete assurance that all control issues and all possible instances of fraud have been, or will be, detected.

 

 

 

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PART II

OTHER INFORMATION

 

The information set forth under the subsections Legal Reserves and Environmental in Note 12, Commitments and Contingencies, to our Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q is incorporated herein by reference.

During the quarter ended March 31, 2016, there were no material changes to the risk factors previously reported in our Annual Report on Form 10-K for the year ended December 31, 2015.

Item 6.Exhibits.

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this Quarterly Report on Form 10-Q and incorporated herein by reference.

 

 

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

 

 

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EXHIBIT INDEX

 

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* These exhibits are filed herewith.

+The exhibits and schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S-K. The company will furnish copies of such exhibits and schedules to the Securities and Exchange Commission upon request.

 

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