rexx-10q_20180331.htm

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Accelerated filer

Non-accelerated filer

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Smaller reporting company

Emerging growth company

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files) Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

Some of the information, including all of the estimates and assumptions, in this report 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 variations thereon or similar terminology.

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

Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. You are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Most of these factors are difficult to anticipate and may be beyond our control. 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.

	March 31, 2018 (unaudited)			December 31, 2017
ASSETS
Current Assets
Cash and Cash Equivalents	$	25,090		$	15,247
Accounts Receivable		27,147			25,974
Taxes Receivable		48			2,049
Short-Term Derivative Instruments		7,732			8,008
Inventory, Prepaid Expenses and Other		9,997			4,614
Total Current Assets		70,014			55,892
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		991,617			1,086,625
Unevaluated Oil and Gas Properties		179,297			186,523
Other Property and Equipment		19,792			19,640
Wells and Facilities in Progress		52,271			38,660
Pipelines		16,803			16,803
Total Property and Equipment		1,259,780			1,348,251
Less: Accumulated Depreciation, Depletion and Amortization		(367,900	)		(463,899	)
Net Property and Equipment		891,880			884,352
Other Assets		35			44
Long-Term Derivative Instruments		2,880			1,719
Deferred Tax Assets - Long Term		130			130
Total Assets	$	964,939		$	942,137
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	70,394		$	62,354
Current Maturities of Long-Term Debt		869,197			834,325
Accrued Liabilities		49,243			45,218
Short-Term Derivative Instruments		64,671			14,892
Total Current Liabilities		1,053,505			956,789
Long-Term Derivative Instruments		10,576			14,249
Other Long-Term Debt		7,972			8,156
Other Deposits and Liabilities		6,866			7,153
Future Abandonment Cost		8,355			9,352
Total Liabilities	$	1,087,274		$	995,699
Commitments and Contingencies (See Note 12)
Stockholders’ Equity
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 3,987 issued and outstanding on March 31, 2018 and December 31, 2017	$	1		$	1
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 10,708,287 shares issued and outstanding on March 31, 2018 and 10,244,394 shares issued and outstanding on December 31, 2017.		11			10
Additional Paid-In Capital		654,534			652,917
Accumulated Deficit		(776,881	)		(706,490	)
Total Stockholders’ Equity		(122,335	)		(53,562	)
Total Liabilities and Stockholders’ Equity	$	964,939		$	942,137

	For the Three Months Ended March 31,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(69,793	)	$	2,683
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion		15,128			15,468
Loss (Gain) on Derivatives		46,426			(8,381	)
Cash Settlements of Derivatives		(2,009	)		(3,443	)
Equity-based Compensation Expense		1,018			71
Non-cash Exploration Expenses		—			11
Impairment Expense		8,168			1,546
Non-cash Interest Expense		4,161			6,081
Gain on Extinguishments of Debt		—			(249	)
(Gain) Loss on Sale of Assets		647			(1,834	)
Other Non-cash (Income) Expense		380			(66	)
Changes in operating assets and liabilities
Accounts Receivable		96			5,341
Taxes Receivable		2,001			—
Inventory, Prepaid Expenses and Other Assets		(5,853	)		422
Accounts Payable and Accrued Liabilities		25,637			(6,989	)
Other Assets and Liabilities		(89	)		(139	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		25,918			10,522
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		16,188			24,329
Acquisitions of Undeveloped Acreage		(620	)		(299	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(61,738	)		(25,476	)
NET CASH USED IN INVESTING ACTIVITIES		(46,170	)		(1,446	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit, net of Discounts		30,555			21,500
Repayments of Long-Term Debt and Line of Credit		—			(28,500	)
Repayments of Loans and Other Notes Payable		(460	)		(131	)
Debt Issuance Costs		—			(567	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		30,095			(7,698	)
NET INCREASE IN CASH		9,843			1,378
CASH – BEGINNING		15,247			3,697
CASH – ENDING	$	25,090		$	5,075
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest	$	5,594		$	1,541
Cash (Received) Paid for Income Taxes		(2,001	)		(163	)
NON-CASH ACTIVITIES
Change in fair value of contingent consideration receivable - sale of Illinois Basin	$	—		$	(1,417	)
Proceeds held in Escrow - non-cash component of Gain on Sale of Assets		150			5,000
Increase (Decrease) in Accounts Payable and Accrued Liabilities for Capital Expenditures		(13,730	)		(3,040	)
Increase Long Term Debt - Equipment Financing		345			607
Increase in Senior Notes carrying value net of Issuance Costs, Deferred Gain on Exchanges, and Net Discount due to Debt to Equity Conversions		—			5,208
Decrease in Bond Interest Payable due to Debt to Equity Conversions		—			(11	)
Increase in Common Stock outstanding due to Debt to Equity Conversions		—			281

Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent natural gas, NGL and condensate company with operations currently focused in the Appalachian Basin. We are focused on Marcellus Shale, Utica Shale and Upper Devonian Shale drilling and exploration activities. 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 natural gas, NGL and condensate 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 Consolidated Financial Statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.

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 natural gas, NGLs and crude oil, 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 natural gas, NGL and oil 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. 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, 2017.

Ability to Continue as a Going Concern, Covenant Violations and Planned Chapter 11 Reorganization

As of May 15, 2018, the date we filed our Consolidated Financial Statements with the Securities and Exchange Commission on Form 10-Q for the quarterly period ended March 31, 2018, we have not yet made the semi-annual interest payment to the holders of our second lien notes that was due April 2, 2018. The second lien notes provide for a 30-day grace period in which to pay the interest coupon due to the noteholders, which expired on May 2, 2018. Nonpayment of the interest due has resulted in an event of default under our term loan agreement and the second lien indentures. We received a notice of acceleration on April 27, 2018, from the lenders under our term loan agreement demanding immediate payment of all outstanding notes and loans, together with all accrued interest, fees, yield maintenance and call protection amounts. As of March 31, 2018, we recorded at fair value a liability for the yield maintenance and call protection amounts of approximately $53.0 million, recorded as Short-Term Derivative Instruments on our Consolidated Balance Sheet (see Note8, Derivative Instruments and Fair Value Measurements and Note 7, Long-Term Debt, to our Consolidated Financial Statements for additional information). For the three months ended March 31, 2018, we recorded a loss of approximately $53.0 million as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations in connection with various events occurring during the first quarter, which have led to the Company deciding to file Chapter 11 Bankruptcy which have caused these amounts to become due and payable. The outstanding balance of the term loan inclusive of the yield maintenance, call protection, accrued interest and fees was approximately $274.0 million as of March 31, 2018. In addition to the non-payment of second lien interest, we also encountered additional events of default related to certain non-financial covenants associated with our term loan agreement. These additional events of default are a result of our failure to timely deliver to the term loan lenders our unaudited quarterly financial statements for the quarter ended December 31, 2017 and our annual audited financial statements for the year ended December 31, 2017, as well as related inadvertent failures to provide accurate related written notices to the lenders, and written notices of the events of default in a subsequent draw request under the term loan agreement.

We have entered into forbearance agreements with each of the requisite lenders under our senior term loan facility and the second lien notes. The forbearance agreements do not constitute a waiver of the events of default related to the nonpayment of interest and other non-financial covenants defaults described above. The forbearance agreements specify that the lenders will forbear from taking any enforcement actions during the forbearance period, which extends through May 17, 2018, unless earlier terminated, but does not prevent acceleration of amounts owed. We do not have sufficient liquidity to repay these amounts. The Company has been unsuccessful in negotiating an alternative restructuring with its various stakeholders outside of a voluntary pre-arranged Chapter 11 bankruptcy filing. As such, the ability to conclude a successful negotiation with our lenders and note holders out of court is not expected to occur. An acceleration notice from the lenders of our senior term loan has been received and we lack the liquidity to pay these obligations. Given these circumstances, the Company is currently in the process of preparing to file for protection under Chapter

11 of the U.S. Bankruptcy Code which is expected to occur imminently following the filing of this Form 10-Q. There can be no assurances that the Company will be able to reorganize its capital structure on terms acceptable to the Company, its creditors, or at all.

The events of default and significant risks and uncertainties described above raise a substantial doubt about our ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of our discussions with the lenders under the term loan agreement and the holders of our second lien notes, or the outcome of the going concern uncertainty.

On May 12, 2017, we effected a one-for-ten reverse stock split. As a result of the reverse stock split, each ten shares of our common stock automatically combined into and became one share of our common stock. Any fractional shares which would have otherwise been due as a result of the reverse split were rounded up to the nearest whole share. As a result of the reverse stock split, we reduced the issued number of common shares from 99.0 million to 9.9 million. The reverse stock split automatically and proportionately adjusted, based on the one-for-ten split ratio, all issued and outstanding shares of our common stock, as well as common stock underlying stock options, warrants and other derivative securities outstanding at the time of the effectiveness of the reverse stock split. The exercise price on outstanding equity based-grants proportionately increased, while the number of shares available under our equity-based plans also was proportionately reduced. Share and per share data for the periods presented reflect the effects of this reverse stock split. References to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis.

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 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 totaled $0.3 million and $0.6 million for the three months ended March 31, 2018 and 2017, respectively. 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 $1.0 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

Effective January 1, 2018, we adopted Accounting Standards Codification (“ASC”) 606, “Revenue from Contracts with Customers,” using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018. Under the modified retrospective method, the Company recognizes the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no material adjustment was required as a result of adopting ASC 606. Results for reporting periods beginning on January 1, 2018 are presented under the new revenue standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The Company performed an analysis of the impact of adopting ASC 606 across all revenue streams and did not identify any changes to its revenue recognition policies that would result in a material impact to its consolidated financial statements. The Company also

implemented processes and controls to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the required disclosures under the standards.

Revenue from operations is derived from sales of natural gas, NGL and condensate products produced by our well properties for which we are the operator. A de minimis percentage of revenue is also earned from either working interests, royalty interests, or small override interests we hold in various non-operated well properties. Our sales revenue is generated from on-going daily or monthly sales of volumes of gas and oil commodities, the sales volumes determined by metering or other measurement methods at the delivery point when control of the commodities transfers to the customer.

We recognize sales of our natural gas, NGL and condensate products when control of the product is transferred to the customer at delivery points specified in each commodity purchase contract. Under our commodity sales contracts, the delivery of each unit of natural gas, NGLs or condensate represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled. There are no significant financing components associated with our revenues from sales to customers as payment terms are typically within 30 to 60 days of control transfer. Sales revenue recognized corresponds directly with the value to the customer of the Company’s performance completed to date. We record revenue from sales of our natural gas, NGL and condensate production in the amount equal to our net revenue interest in sales from the producing properties. Under ASC 606, the Company recognizes revenues based on a determination of when control of its commodities is transferred and whether it is acting as a principal or agent in certain transactions. All facts and circumstances of an arrangement are considered and judgment is often required in making this determination. The Company considers risk of loss an important indicator of when control transfers, which is comprised of risks associated with loss of product during processing. The Company concluded that title, custody, and acceptance are not by themselves determinative indicators of control, as such factors may be present in the case of a sale or the performance of a service.

As a result of this analysis, the Company concluded that the Company represents the principal and the ultimate third party is its customer, which implies that the Company maintains control of the product through the tailgate of gas processing plants in certain natural gas processing in accordance with the control model in ASC 606. As a result, there were no changes to the Company’s presentation of revenues and expenses for these agreements.

Our natural gas production is primarily sold under contracts that are typically priced at a differential to published commodity index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. NGL and condensate production is sold under contract pricing referenced to various liquids commodity index prices. All revenue from production is generated from our operations in the Appalachian Basin.

The Company uses the sales method to account for natural gas production imbalances. If the Company’s sales volume for a well exceeds the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.

Under the Company’s product sales contracts, its customers are invoiced once the Company’s performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to material contract assets or contract liabilities.

Our contracts with customers represent a series of performance obligations satisfied over time when a performance obligation is satisfied by the transfer of control over a product to the customer. The transfer of control is generally considered to occur when the Company has transferred custody, title, risk of loss and relinquished any repurchase rights or other similar rights. Our commodity

sales contracts are established to facilitate on-going sales of our products with our customers over the term of the contract, with pricing and delivery terms identified in each contract. We do not have contracts with customers that describe the performance obligation in terms of a defined gross total delivery volume over time. We utilized the practical expedient in ASC 606-10-50-14(A) which states that disclosure of the portion of a transaction price allocated to remaining performance obligations is not required if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts, each unit of product generally represents a separate performance obligation; therefore future sales volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

As of March 31, 2018 and December 31, 2017, we had trade receivable balances related to revenue from contracts with customers of approximately $19.6 million and $21.7 million, respectively.

The following table summarizes our disaggregated revenues recognized from contracts with customers in our Consolidated Statements of Operations for the three month periods ended March 31, 2018 and 2017.

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 agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, all of which have already been drilled, completed, placed in sales and paid for by BSP. BSP also agreed to participate in and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised its option to participate in 23 of these additional wells. Total consideration for this transaction could be up to $175.0 million with approximately $134.0 million committed as of March 31, 2018. BSP has paid for its interest in the elected wells as of December 31, 2017, and no additional elections have occurred during the quarter ended March 31, 2018. The remainder of the proceeds may be received if BSP makes additional elections as additional wells are drilled to total depth or placed in sales. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units in which it participates. As of March 31, 2018, all 45 committed wells were in line and producing.

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.

On January 11, 2017, we, together with MFC Drilling, Inc., and ABARTA Oil & Gas Co., Inc. sold substantially all of our jointly owned oil and gas interests in Noble, Guernsey, and Belmont Counties, Ohio, to Antero Resources Corporation. These interests comprised our Warrior South development area. The effective date for the transaction is October 1, 2016. The sales agreement includes representations, warranties, covenants and agreements as well as various provisions for purchase price and post-closing adjustments customary for transactions of this type. Total consideration for the transaction was approximately $50.0 million, with approximately $29.1 million net to us, subject to customary closing and post-closing adjustments. We received approximately $24.1 million of proceeds on January 11, 2017. Approximately $5.0 million of the total proceeds due to us was held in escrow and released to us in December 2017 . The sale of assets resulted in a gain on disposal of assets of approximately $1.8 million in January 2017. This gain includes the additional proceeds held in escrow. The sale of assets included 14 gross wells with associated production of 15 Mmcfe/d, with 9 Mmcfe/d net to us, and approximately 6,200 gross acres, with 4,100 acres net to us. This acreage was considered non-core to us. We used the proceeds from the transaction to pay down amounts outstanding under our prior revolving line of credit and for general corporate purposes.

On March 13, 2018, the Company, entered into a Purchase and Sale Agreement with XPR Resources, LLC (“XPR”), pursuant to which the Company agreed to sell to XPR certain of its non-operated oil and gas interests in 61 wells located in Westmoreland, Centre and Clearfield Counties, Pennsylvania, along with associated production and other ancillary assets. The acreage sold was considered non-core to the Company. In a related transaction, the Company entered into a Membership Interest Purchase Agreement on the same date with COG2, LLC (“COG2”), an affiliate of XPR, pursuant to which the Company agreed to sell to COG2 its 40% membership interest in RW Gathering, LLC. Closing occurred on March 21, 2018, with an effective date for the transactions of January 1, 2018. Total consideration for the transactions was approximately $17.2 million, subject to customary closing and post-closing adjustments. We received approximately $16.4 million of proceeds on March 23, 2018, prior to closing adjustments. Approximately $0.2 million of the total proceeds due to us is being held in escrow. The sale of assets resulted in a loss on the disposal of assets of approximately $0.6 million in the first quarter of 2018.

In May 2014, the Financial Accounting Standards Board (the “FASB”) issued ASU 2014-09, Revenue from Contracts with Customers. The amendments in this ASU affect 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 in ASU 2014-09 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. The guidance provides a five step process to be applied in evaluating contracts under the new standard:

Subsequent to the issuance of ASU 2014-09, the FASB issued several additional Accounting Standards Updates to clarify implementation guidance, provide guidance regarding principal vs. agent considerations and identifying performance obligations, provide narrow-scope improvements, and provide additional disclosure guidance. ASU 2014-09 is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with the cumulative effect of applying the new standard recognized as an adjustment to retained earnings in the most current period presented in the financial statements. The standard is effective for annual reporting periods, and interim periods within that reporting period, beginning after December 15, 2017. We adopted the new standard effective January 1, 2018 using a modified retrospective approach. We did not require a cumulative adjustment to retained earnings as a result of adopting the standard.

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 the potential impact of this standard on our results of operations and internal control environment.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The amendments in the update provide guidance regarding the presentation in the statement of cash flows of eight specific cash flow disclosure issues:

Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. We adopted this standard effective January 1, 2018 on a retrospective basis. Adoption of the standard did not have an impact on the presentation of our consolidated statements of cash flows

In May 2017, the FASB issued ASU 2017-09, Stock Compensation - Scope of Modification Accounting, which provides guidance about the types of changes to terms or conditions of a share-based payment award that would require an entity to apply modification accounting. The new guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The amendments in this update should be applied prospectively to awards modified on or after the adoption date. We adopted this standard effective January 1, 2018. Adoption of the standard did not have a material impact on our consolidated financial statements.

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

We depend on a relatively small number of purchasers for a substantial portion of our revenue. For the three months ended March 31, 2018, approximately 97.8% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 60.1% of commodity sales. We believe the growth in our Appalachian estimated proved reserves, as well as the quantity of purchasers, will help us to minimize our future risks by diversifying our ratio of condensate and gas sales.

On April 28, 2017 (the “Effective Date”), we entered into a term loan agreement (“Term Loan”) with Angelo, Gordon Energy Servicer, LLC (“AGES”), as administrative agent, AGES, as collateral agent (in such capacity, the “Collateral Agent”), Macquarie Bank Limited, as issuing bank (in such capacity, the “Issuing Bank”), and the lenders from time to time party thereto. The Term Loan replaced our prior amended and restated senior secured revolving credit agreement with Royal Bank of Canada, as Administrative Agent, and the lenders from time to time party thereto (the “Prior Credit Agreement”). The Term Loan provides for a $143,500,000 secured term loan facility (the “Term Facility”) and a $156,500,000 secured delayed draw term loan facility (the “Delayed Draw Term Facility”), which includes a letter of credit sub-facility (the “Letter of Credit Sub-facility”). The proceeds of the initial loans under the Term Loan were used to refinance the loans then outstanding under the Prior Credit Agreement and payment of fees and expenses related thereto; the proceeds of future loans under the Delayed Draw Term Facility may be used for cash collateralizing letters of credit under the Letter of Credit Sub-facility and general corporate purposes. The maximum commitments of the lenders under the Term Loan were initially limited to $300,000,000. Amounts borrowed and repaid may not be re-borrowed. Unless accelerated pursuant to the terms of the Term Loan, the maturity date for the loans under the Term Facility and the loans drawn under the Delayed Draw Term Facility is the earlier of (a) April 28, 2021 and (b) the date that is six months prior to the maturity of our 1.00/8.00% Senior Secured Second Lien Notes due 2020 (the “Second Lien Notes”) unless less than $25,000,000 in aggregate principal amount of Second Lien Notes are then outstanding and no Event of Default (as defined in the Term Loan) exists on such date. Except as otherwise provided under the terms of the Term Loan in the case of an occurrence of an event of default, the commitments under the Delayed Draw Term Facility expire if not drawn prior to the earlier of (a) April 28, 2018 (which date may be extended for one year

with lender consent) and (b) the date upon which we terminate such commitments. As of March 31, 2018, we had $221.0 million in borrowings outstanding and approximately $32.0 million in outstanding undrawn letters of credit. We incurred approximately $3.5 million in debt issuance costs and $4.3 million in original issue discount (“OID”) related to the initial Term Loan borrowing. We incurred an additional $2.3 million in OID related to the Delayed Draw Term Facility. During the three months ended March 31, 2018, we amortized $0.3 million of debt issuance costs and $0.5 million of OID. The amortization of debt issuance costs and OID are reported as Interest Expense in our Consolidated Statement of Operations.

At March 31, 2018, approximately $7.7 million in deferred financing fees and OID were written off related to our Term Loan due to (i) the uncertainty regarding the Company’s ability to cure the default as discussed in Note 1, (ii) our inability to comply with certain financial covenants contained in our Term Loan and (iii) the acceleration notice received from the from the lenders the Term Loan. The amount written off is included in interest expense on the consolidated statements of operations for the period ended March 31, 2018.

Borrowings under the Term Loan bear interest at a rate per annum equal to the “Adjusted LIBO Rate” (subject to a 1.00% floor) plus an 8.75% per annum margin. The “Adjusted LIBO Rate” is equal to the product of the three month LIBOR rate multiplied by the statutory reserve rate. Upon the occurrence and continuance of an Event of Default all outstanding loans bear interest at a rate equal to 4.00% per annum plus the then-effective rate of interest. Interest is payable on the last business day of each March, June, September and December. Under the Term Loan, we will pay a 3.5% commitment fee on any unused portion of the Delayed Draw Term Facility.

The Term Loan requires us to prepay the loans with 100% of the net cash proceeds received from certain asset sales, swap terminations, incurrences of borrowed money indebtedness, casualty events and equity issuances, subject to certain exceptions and specified reinvestment rights. Prepayments based on 75% of excess cash flow (“excess cash flow” as defined in the Term Loan agreement represents EBITDAX less capital expenditures, cash payments for interest, cash payments for income taxes, and adjustments for certain non-cash expenses) are required until no more than $287,950,000 in aggregate principal amount of Second Lien Notes remain outstanding, at which time, prepayments based on 50% of excess cash flow will be required. Prepayments (including mandatory prepayments), terminations, refinancing, reductions and accelerations under the Term Loan are subject to a yield maintenance amount equal to the interest which would have accrued on such prepaid, terminated, refinanced, reduced or accelerated amount during the period beginning on the date of such prepayment, termination, refinancing, reduction or acceleration and ending on the date that is 30 months after the Effective Date and a call protection amount (a) during the period commencing on the Effective Date and ending on the date that is 30 months thereafter, in an amount equal to 3.0% of such prepaid, terminated, refinanced, reduced or accelerated amount and (b) during the period commencing on the date that is 30 months and one day after the Effective Date and ending on the date that is 36 months after the Effective Date, an amount equal to 1.0% of such prepaid, terminated, refinanced, reduced or accelerated amount. Some of the provisions are required to be bifurcated from the Term Loan and valued separately as derivatives. Due to the short-term nature of these amounts at March 31, 2018 they have been recorded at their fair value using Level 2 inputs. For the three months ended March 31, 2018, we recorded a fair value liability of approximately $53.0 million as Short-Term Derivative Instruments on our Consolidated Balance Sheet. For the three months ended March 31, 2018, we recorded a loss of approximately $53.0 million as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations in connection with various events occurring during the first quarter, which have led to the Company deciding to file Chapter 11 Bankruptcy which have caused these amounts to become due and payable. As of December 31, 2017, the fair value of these embedded derivatives was not material.

The Term Loan contains covenants that restrict our ability to, among other things, materially change the nature of our business, make dividend payments, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions.

The Term Loan also requires that we comply with the following financial covenants: (1) as of the last day of any fiscal quarter ending on or after December 31, 2017, the PDP Coverage Ratio (as defined in the Term Loan) will not be less than 1.65 to 1.00; (2) as of the last day of any fiscal quarter ending on or after March 31, 2017, the ratio of Net Senior Secured Debt (as defined in the Term Loan) as of such date to EBITDAX (as defined in the Term Loan) for the period of four fiscal quarters then ending on such day will not be greater than 3.25 to 1.00; and (3) as of the last day of any fiscal quarter ending on or after September 30, 2017 the ratio of EBITDAX for the four fiscal quarters then ending to cash interest expense will not be less than (i) 1.00 to 1.00 for any fiscal quarter ending on or before December 31, 2017 and (ii) 1.30 to 1.00 for each fiscal quarter thereafter. As of March 31, 2018, our PDP Coverage Ratio was 2.34 to 1.00, Net Senior Secured Debt to EBITDAX Ratio was 2.92 to 1.00 and EBITDAX to Cash Interest Expense was 2.51 to 1.00.

Our obligations under the Credit Agreement have been accelerated upon the occurrence of an Event of Default (as such term is defined in the Term Loan). See Note 1, Basis of Presentation and Principles of Consolidation and Note 18 Subsequent Events, for additional information on certain financial and non-financial covenant defaults that have occurred.

Obligations under the Term Loan are secured by mortgages on our oil and gas properties. In connection with the Term Loan, we, including our wholly owned subsidiaries, Rex Energy I, LLC, Rex Energy Operating Corp., PennTex Resources Illinois, Inc., Rex Energy IV, LLC, and R.E. Gas Development, LLC (collectively, the “Guarantors” and together with us, the “Grantors”), entered into an amended and restated guaranty and collateral agreement, dated as of April 28, 2017, in favor of the Collateral Agent for the lenders from time to time party to the Term Loan, the secured swap parties and the Issuing Bank (the “Guaranty and Collateral Agreement”). Pursuant to the Guaranty and Collateral Agreement, each of the Guarantors, jointly and severally, guaranteed the prompt and complete payment of our obligations under the Term Loan. In addition, each Grantor granted, as security for the prompt and complete payment and performance when due of such Grantor’s obligations, a security interest in substantially all of its assets, including equity interests in other Guarantors, as applicable.

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 Second Lien 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 Second Lien Notes are greater than the net carrying value of the Existing Notes. As such, no gain has been recognized within our GAAP basis financial statements and a new effective interest rate has been established. See Note 9, Income Taxes, to our Consolidated Financial Statements, for information regarding the tax treatment and impact of the Exchange for federal and state income tax purposes.

In exchange for $324.0 million in aggregate principal amount of the 2020 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) $633.2 million aggregate principal amount of Second Lien Notes and (ii) 8.4 million Shares, which had a fair value of $6.5 million upon issuance. An additional $0.5 million aggregate principal amount of Second Lien Notes were issued to holders who were ineligible to accept 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 Second Lien Notes bore interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and have borne interest at a rate of 8.0% per annum thereafter, payable in cash. Interest payments are due on April 1 and October 1 of each year, beginning October 1, 2016 and ending October 1, 2020. In connection with the Exchange, we incurred approximately $9.1 million in third-party debt issuance costs during the year ended December 31, 2016. These costs were recorded as Debt Exchange Expense in our Consolidated Statement of Operations.

The Company has not made the semi-annual interest payment to the holders of our Second Lien Notes that was due on April 2, 2018, and did not make the interest payment prior to the expiration of the 30 day grace period. Therefore, the maturity date of the Second Lien Notes is, upon requisite notice, subject to acceleration. This nonpayment of the semi-annual interest payment on the Second Lien Notes is an event of default under the Company’s Term Loan and under the indentures governing the Existing Notes, which upon requisite notice, would result in an acceleration of the maturity dates of the Term Loan and Existing Notes. See Note 1, Basis of Presentation and Principles of Consolidation and Note 18 Subsequent Events, for additional information on the non-payment of the semi-annual interest payment due.

Following the completion of the Exchange, we entered into debt-for equity exchanges during the remainder of 2016, with certain holders of our Existing Notes, as well as holders of our Second Lien Notes, in which such Existing Notes and Second Lien Notes were exchanged for unrestricted shares of our common stock. These exchanges resulted in the retirement of $27.7 million in aggregate principal amount of our remaining Existing Notes and $45.7 million in aggregate principal amount of our outstanding Second Lien Notes, in exchange for the issuance of a total of approximately 2.4 million shares of unrestricted common stock during the year ended December 31, 2016. During the year ended December 31, 2017 , we completed debt-for equity exchanges with certain holders of our Existing Notes. These exchanges resulted in the retirement of approximately $0.9 million in aggregate principal amount of our remaining Existing Notes, in exchange for approximately 0.1 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain for the three months ended March 31, 2017 of approximately $0.4 million, presented as Gain on Extinguishments of Debt in our Consolidated Statements of Operations.

We may redeem, at specified redemption prices, some or all of the Second Lien Notes at any time on or after April 1, 2018. We may also redeem up to 35% of the Second Lien 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 Existing Notes and the Second Lien Notes from the holders.

The Senior Notes are governed by indentures (the “Indentures”), which 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. The Indentures also contain customary events of default. In certain circumstances, the individual trustees under the Indentures or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.

As of March 31, 2018 and December 31, 2017, we had recorded on our Consolidated Balance Sheets approximately $12.8 million and $14.0 million, respectively, of net premium/discounts related to the Senior Notes. The amortization of our net premium/discounts , which follows the effective interest method, increased interest expense by approximately $1.2 million for the three months ended March 31, 2018. The amortization of our net premium/discounts decreased interest expense by approximately $3.8 million for the three months ended March 31, 2017. 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. Total interest expense for the three months ended March 31, 2018 is composed of non-cash amortization of $4.4 million, cash interest payments of $6.8 million, capitalized interest of $(1.2) million and an increase in accrued interest of $12.6 million. Total interest expense for the three months ended March 31, 2017 is composed of non-cash amortization of $6.3 million, cash interest payments of $1.3 million and an increase in accrued interest of $1.5 million.

The weighted average interest rate on borrowed balances under the Term Loan for the three months ended March 31, 2018 was approximately 10.5%. The weighted average interest rate on the Senior Credit Facility for the three months ended March 31, 2017 was approximately 3.7%. The average interest rate on our capital leases for the three months ended March 31, 2018 and 2017 was approximately 16.8% and 11.0%, respectively. As of March 31, 2018, the Deferred Gain on Debt Restructurings, Net includes Unamortized Premiums/Discounts of $12.8 million, Unamortized Debt Issuance Costs of $30.8 million and Unamortized Deferred Gain on Debt Restructurings of $27.7 million.

			December 31, 2017
			Principal		Unamortized net Premium / Discount			Unamortized Debt Issuance Costs			Deferred Gain on Debt Restructurings, Net			Net Carrying Value

Term Loans, Net
	Term Loan Draw - due April 2020		$	189,500	$	(4,711	)	$	(2,761	)	$	—		$	182,028

Senior Notes, Net
	8.875% Senior Notes due 2020		$	7,333	$	—		$	—		$	(60	)	$	7,273
	6.25% Senior Notes due 2022			5,363		—			—			(67	)		5,296
	1% / 8% Second Lien Senior Notes due 2020			587,606		—			—			50,196			637,802
			$	600,302	$	—		$	—		$	50,069		$	650,371

Other Long-Term Debt
	Long-Term Capital Leases and Other Notes Payable- Equipment Financing
		Due March, 2021												$	632
		Due June, 2021													1,418
		Due September, 2021													1,578
		Due May 2022													6,454
		Total Capital Lease Obligations												$	10,082
		Less: Current Portion of Capital Leases and Other Notes Payable													(1,926	)
														$	8,156

As of December 31, 2017, the Deferred Gain on Debt Restructurings, Net includes Unamortized Premiums/Discounts of $14.0 million, Unamortized Debt Issuance Costs of $33.6 million and Unamortized Deferred Gain on Debt Restructurings of $30.4 million.

The following is the principal maturity schedule for debt outstanding as of March 31, 2018:

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, 2018 and December 31, 2017, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, 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 (Loss) on Derivatives, Net in the Consolidated Statement of Operations.

We enter into the majority of our derivative arrangements with two 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 (Loss) on Derivatives, Net under Other Expense. We paid net cash settlements of $2.0 million and $3.4 million in relation to our commodity derivatives during the three months ended March 31, 2018 and 2017, respectively.

We entered into the Term Loan in April 2017, which included certain call protection and yield maintenance provisions that require accelerated payments upon certain events. Prepayments (including mandatory prepayments), terminations, certain events of default, refinancing, reductions and accelerations under the Term Loan are subject to a yield maintenance amount equal to the interest which would have accrued on such prepaid, terminated, refinanced, reduced or accelerated amount during the period beginning on the date of such prepayment, termination, refinancing, reduction or acceleration and ending on the date that is 30 months after the Effective Date and a call protection amount (a) during the period commencing on the Effective Date and ending on the date that is 30 months thereafter, in an amount equal to 3.0% of such prepaid, terminated, refinanced, reduced or accelerated amount and (b) during the period commencing on the date that is 30 months and one day after the Effective Date and ending on the date that is 36 months after the Effective Date, an amount equal to 1.0% of such prepaid, terminated, refinanced, reduced or accelerated amount.

Some of the provisions are required to be bifurcated from the Term Loan and valued separately as derivatives. Due to the short-term nature of these amounts at March 31, 2018 they have been recorded at their fair value using Level 2 inputs. For the three months ended March 31, 2018, we recorded a fair value liability of approximately $53.0 million as Short-Term Derivative Instruments on our Consolidated Balance Sheet. For the three months ended March 31, 2018, we recorded a loss of approximately $53.0 million as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations in connection with various events occurring during the first quarter, which have led to the Company deciding to file Chapter 11 Bankruptcy which have caused these amounts to become due and payable. As of December 31, 2017, the fair value of these embedded derivatives was not material. As of December 31, 2017, the fair value of these embedded derivatives was not material.

In conjunction with the sale of our Illinois Basin operations, we executed a contract with the buyer that would allow us to receive future cash payments from the buyer if index pricing targets as defined in the contract are achieved at specified future dates. We have evaluated the contract and concluded that it meets the definition and requirements for accounting treatment as a derivative instrument, as prescribed in ASC 815-10-15-83. We recorded the contract at its initial fair value of approximately $1.2 million as additional consideration in the calculation of the gain on the sale of the assets. Fair value was determined through application of mathematical models designed to provide fair value estimates utilizing probability measures and the market index measures underlying the contract. The fair value will be adjusted at each future reporting period for the duration of the contract, which concludes June 30, 2019. As of March 31, 2018 and December 31, 2017, the contingent consideration contract was valued at $2.1 million and $1.7 million, respectively. For the three month period ended March 31, 2018, the average index price for oil as specified in the contract was in excess of the required threshold price for the quarter, and we recognized income of approximately $0.8 million, representing the discounted fair value of the additional consideration earned during the quarter. The contract stipulates that the buyer will remit to us $0.9 million not later than April 15, 2019, for the consideration earned during the three months ended March 31, 2018. The discounted fair value of approximately $0.8 million is included in Accounts Receivable on our Consolidated Balance Sheets as of March 31, 2018.

The following table summarizes the location and amounts of gains and losses on our derivative instruments, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three months ended March 31, 2018:

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 liability of approximately $64.6 million and approximately $19.4 million at March 31, 2018 and December 31, 2017, respectively.

Our open asset/(liability) financial commodity derivative instrument positions at March 31, 2018 consisted of:

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2018 - Swaps		139,250	Bbls	$	—	$	—	$	—	$	57.55		$	(811	)
2018 - Collars		9,000	Bbls		—		53.00		60.00		—			(47	)
2018 - Three-Way Collars		57,000	Bbls		42.11		51.32		61.14		—			(222	)
2019 - Swaps		53,500	Bbls		—		—		—		49.04			(425	)
2019 - Collars		60,250	Bbls		—		45.00		55.07		—			(161	)
2019 - Three-Way Collars		51,000	Bbls		38.82		48.82		58.31		—			(201	)
2020 - Swaps		24,000	Bbls		—		—		—		50.63			(146	)
2020 - Collars		71,750	Bbls				45.00		55.10					(215	)
2020 - Three-Way Collars		33,725	Bbls		39.39		49.39		57.04		—			(116	)
2021 - Swaps		15,000	Bbls		—		—		—		50.40			(36	)
2021 - Collars		63,750	Bbls		—		45.00		55.02		—			(197	)
2021 - Three-Way Collars		13,250	Bbls		39.10		49.10		60.41		—			(45	)
2022 - Swaps		6,750	Bbls		—		—		—		50.00			—
2022 - Collars		36,000	Bbls		—		45.00		54.75		—			(107	)
2022 - Three-Way Collars		5,500	Bbls		40.00		50.00		60.50		—			(11	)
		639,725	Bbls										$	(2,740	)
Natural Gas
2018 - Swaps		18,342,500	Mcf		—		—		—		2.98		$	2,400
2018 - Three-Way Collars		7,600,000	Mcf		2.33		2.89		3.49		—			1,124
2018 - Calls		4,370,000	Mcf		—		—		3.97		—			(38	)
2018 - Collars		3,965,000	Mcf		—		2.60		3.04		—			(153	)
2018 - Basis Swaps - Dominion South		10,625,000	Mcf		—		—		—		(0.82	)		(2,056	)
2018 - Basis Swaps - Texas Gas		11,000,000	Mcf		—		—		—		(0.13	)		448
2019 - Swaps		11,620,000	Mcf		—		—		—		2.84			255
2019 - Three-Way Collars		11,250,000	Mcf		2.29		2.76		3.34		—			282
2019 - Collars		9,051,750	Mcf		—		2.56		3.04		—			(270	)
2019 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.84	)		(2,721	)
2020 - Swaps		5,542,500	Mcf		—		—		—		2.88			135
2020 - Three-Way Collars		7,680,000	Mcf		2.27		2.73		3.24		—			279
2020 - Collars		6,760,000	Mcf		—		2.56		3.04		—			(153	)
2020 - Basis Swaps - Dominion South		7,320,000	Mcf		—		—		—		(0.84	)		(1,519	)
2021 - Swaps		3,875,000	Mcf		—		—		—		2.77			(5	)
2021 - Three-Way Collars		4,083,750	Mcf		2.21		2.68		3.13		—			66
2021 - Collars		3,530,000	Mcf		—		2.53		3.05		—			(77	)
2021 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(273	)
2022 - Swaps		2,730,000	Mcf		—		—		—		2.73			(42	)
2022 - Three-Way Collars		2,047,500	Mcf		2.15		2.65		3.10		—			21
2022 - Collars		2,195,000	Mcf		—		2.51		3.05		—			(52	)
2022 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(273	)
2023 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(273	)
2024 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(273	)
		160,963,000	Mcf										$	(3,168	)
NGLs
2018 - C3+ NGL Swaps		1,137,405	Bbls		—		—		—		34.05		$	(5,540	)
2018 - Ethane Swaps		1,302,000	Bbls		—		—		—		12.22			750
2019 - C3+ NGL Swaps		957,943	Bbls		—		—		—		29.98			(1,883	)
2019 - C5 Collars		113,040	Bbls		—		45.00		54.83		—			(495	)
2019 - Ethane Swaps		1,317,750	Bbls		—		—		—		12.61			805
2019 - C5 Three-Way Collars		7,536	Bbls		—		32.31		50.00		55.75			(24	)
2020 - C3+ NGL Swaps		347,689	Bbls		—		—		—		30.40			(996	)
2020 - C5 Collars		28,260	Bbls		—		45.00		54.83		—			(124	)
2020 - Ethane Swaps		1,150,750	Bbls		—		—		—		12.37			113
2020 - C5 Three-Way Collars		41,225	Bbls		—		34.87		49.94		57.36			(82	)
2021 - C3+ NGL Swap		210,206	Bbls		—		—		—		31.62			(402	)
2021 - Ethane Swaps		805,000	Bbls		—		—		—		12.32			93
2021 - C5 Three-Way Collars		63,398	Bbls		—		38.99		48.99		60.40			(37	)
2022 - C3+ NGL Swap		62,966	Bbls		—		—		—		32.60			(114	)
2022 - Ethane Swaps		379,250	Bbls		—		—		—		12.31			52
2022 - C5 Three-Way Collars		22,460	Bbls		—		39.11		49.11		60.41			(9	)
		7,946,878	Bbls										$	(7,893	)

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, 2018 and December 31, 2017 is summarized below:

	March 31,			December 31,
($ in Thousands)	2018			2017
Short-Term Derivative Assets:
NGL—Swaps	$	1,549		$	928
Natural Gas—Swaps		2,672			3,734
Natural Gas—Collars		—			183
Natural Gas—Basis Swaps		448			191
Natural Gas—Three-Way Collars		1,222			1,721
Contingent Consideration - Sale of Illinois Basin		1,841			1,251
Total Short-Term Derivative Assets	$	7,732		$	8,008
Long-Term Derivative Assets:
NGL—Swaps	$	1,511		$	409
Natural Gas—Swaps		404			411
Natural Gas—Basis Swaps		—			—
Natural Gas—Three-Way Collars		675			429
Contingent Consideration - Sale of Illinois Basin		290			470
Total Long-Term Derivative Assets	$	2,880		$	1,719
Total Derivative Assets	$	10,612		$	9,727
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	(46	)	$	(31	)
Crude Oil—Three-Way Collars		(289	)		(92	)
Crude Oil—Swaps		(914	)		(518	)
NGL—Swaps		(7,205	)		(10,281	)
NGL—Collars		(124	)		—
Natural Gas—Three-Way Collars		(25	)		(49	)
Natural Gas—Collars		(206	)		(146	)
Natural Gas—Basis Swaps		(2,738	)		(3,621	)
Natural Gas—Call		(38	)		(154	)
Natural Gas—Swaps		(121	)		—
Embedded Derivatives		(52,965	)		—
Total Short - Term Derivative Liabilities	$	(64,671	)	$	(14,892	)
Long-Term Derivative Liabilities:
Crude Oil—Three-Way Collars	$	(306	)	$	(161	)
Crude Oil—Swaps		(504	)		(202	)
Crude Oil—Collars		(681	)		(425	)
NGL—Swaps		(2,977	)		(4,482	)
NGL—Collars		(495	)		(385	)
NGL—Three Way Collars		(152	)		(66	)
Natural Gas—Swaps		(212	)		(423	)
Natural Gas—Swaption		—			—
Natural Gas—Basis Swaps		(4,650	)		(7,120	)
Natural Gas—Collars		(499	)		(713	)
Natural Gas—Call		—			—
Natural Gas—Three-Way Collars		(100	)		(272	)
Total Long-Term Derivative Liabilities	$	(10,576	)	$	(14,249	)
Total Derivative Liabilities	$	(75,247	)	$	(29,141	)

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.

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 composed of our derivative contracts and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, probability factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of March 31, 2018 and December 31, 2017 were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party.

We had no Level 3 commodity derivative contracts outstanding as of March 31, 2018 or December 31, 2017.

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, 2018 and for the year ended December 31, 2017 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 composed 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, 2018 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 composed 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, 2018 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (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. Our NGL derivatives are composed 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, 2018 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.

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.

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.

During the three months ended March 31, 2018 and 2017, we recorded other than temporary impairments of $8.2 million and $1.5 million, respectively, related to proven and unproved properties. We primarily use proved reserve reports in our determination of impairment of proved properties. These proved reserve reports are generated with inputs that are primarily established internally with the use of internally developed engineering estimates and methodologies. The inputs used in determining fair value as a part of the impairment expense calculation are considered to be Level 3 within the fair value hierarchy. Impairment considerations for unproved properties include future development plans for the leases, remaining months on the lease’s primary term, and market value for similar acreage in the area. For additional information on our impairment expense, see Note 15, Impairment Expense, to our Consolidated Financial Statements.

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.

Management estimates the annual effective income tax rate quarterly, based on current annual forecasted results. Items unrelated to current year ordinary income are recognized entirely in the period identified as a discrete item of tax. The quarterly income tax provision is composed of tax on ordinary income provided at the most recent estimated annual effective tax rate, adjusted for the tax effect of these discrete items.

For the three months ended March 31, 2018, the estimated annual effective tax rate applied to ordinary losses from operations was 0.0%. The estimated annual effective tax rate differs from the U.S. statutory rate of 21.0% primarily due to the effect of maintaining a full valuation allowance against our deferred tax assets. Discrete period tax expense was not material and is also offset by a full valuation allowance resulting in zero tax expense for the period.

For the three months ended March 31, 2017 the estimated annual effective tax rate applied to ordinary losses from operations was 0.0%. The estimated annual effective tax rate differs from the U.S. statutory rate of 35.0% primarily due to the effect of maintaining a full valuation allowances against our deferred tax assets. Discrete period tax expense was not material and is also offset by a full valuation allowance resulting in zero tax expense for the period.

No income tax payments were made for the three months ended March 31, 2018 and 2017. Tax refunds received during the three months ended March 31, 2018 were approximately $2.0 million, and refunds received during the three months ended March 31, 2017 were negligible.

On December 22, 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was enacted. The Tax Act significantly changed the Internal Revenue Code, reducing the Federal statutory corporate income tax rate from 35% to 21%, allowing for bonus depreciation on certain qualified property, eliminating the alternative minimum tax for corporate taxpayers, adding new limitations on the deductibility of business interest expense deduction for net operating losses. The Tax Act also authorizes the Treasury Department to issue regulations with respect to the new provisions. We are still in the process of fully analyzing the Tax Cuts and Jobs Act and its effects on the Company. We cannot predict how the changes in the Tax Cuts and Jobs Act, regulations, or other guidance issued under it or conforming or non-conforming state tax rules might affect us or our business. In addition, there can be no assurance that U.S. tax laws, including the corporate income tax rate, will not undergo significant changes in the near future.

As discussed in Note 1, Basis of Presentation and Principles of Consolidation, references to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis.

On May 5, 2017, our common shareholders approved a decrease in the number of authorized shares from 200,000,000 to 100,000,000 common shares, contingent upon the effectiveness of a reverse stock split, which occurred on May 12, 2017. As of March 31, 2018, we have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of March 31, 2018 and December 31, 2017, shares of common stock issued and outstanding totaled 10,708,287 and 10,244,394, respectively. During the three months ended March 31, 2017, we issued approximately 0.3 million shares of our common stock in conjunction with debt for equity exchanges completed with certain holders of our Senior Notes. See Note 7, Long-Term Debt, to our Consolidated Financial Statements for additional information regarding our debt and equity exchanges.

As of both March 31, 2018 and December 31, 2017, 3,987 shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”), were issued and outstanding.

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. Dividends of $1.8 million were declared by our Board of Directors in 2017, bringing dividends in arrears current through August 15, 2016. Dividends declared and paid in 2017 were composed of cash dividends of $150.00 per share in the aggregate amount of $1.2 million, for the periods of November 15, 2016 to February 15, 2016 and February 15, 2016 to May 15, 2016 and we paid a dividend of $150.00 per share in the aggregate amount of $0.6 million for the period of May 15, 2016 to August 15, 2016, which was paid in shares of the Company’s common stock. As of March 31, 2018, we paid a dividend of $150.00 per share in the aggregate amount of $0.6 million for the period of August 15, 2016 to November 15, 2016, which was paid in shares of the Company’s common stock. As of March 31, 2018, accumulated dividends in arrears totaled $3.0 million. While the accumulation does not result in the presentation of a liability on the Consolidated Balance Sheets, the accumulation of unpaid dividends during the current reporting period is included in our Net Income (Loss) in the determination of Net Income (Loss) Attributable to Common Shareholders and related earnings per share calculations.

If dividends are in arrears and unpaid for six or more quarterly periods (whether or not consecutive), 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. We do not intend to make the dividend payment due on May 15, 2018, which will result in a total of six quarterly dividend payments in arrears.

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.

During the three months ended March 31, 2018 and 2017, no new options to purchase shares of our common stock were granted. Stock-based compensation expense from operations relating to stock options outstanding for the three months ended March 31, 2018 and 2017 was negligible and $0.1 million, respectively. 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 during the three months ended March 31, 2018. There was no tax benefit related to stock option exercises for each of the three-month periods ended March 31, 2018 and 2017.

A summary of the status of our issued and outstanding stock options as of March 31, 2018 is as follows:

The weighted average remaining contractual term for options outstanding at March 31, 2018 was 4.5 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at March 31, 2018 was 4.3 years

and there was no aggregate intrinsic value. As of March 31, 2018, unrecognized compensation expense related to stock options was negligible.

During the three months ended March 31, 2018, there were no issuances of restricted common stock to employees. During the three months ended March 31, 2017, the Compensation Committee approved the issuance of an aggregate of 101,237 shares of restricted stock to 28 employees. 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.

The weighted average fair value of the TSR awards granted as of December 31, 2015 was $2.56 per share. There have been no TSR awards granted subsequent to December 31, 2015. 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 from restricted stock awards associated with our operations was $1.1 million and $0.9 million for the three months ended March 31, 2018 and 2017, respectively. During the three months ended March 31, 2018, the board of directors approved a waiver to certain performance factors for restricted stock awards that vested in March 2018. This waiver resulted in the vesting of approximately 29,411 restricted stock awards with associated expense of approximately $0.9 million. During the first quarter of 2017, 179,519 performance stock awards were forfeited due to not meeting specified targets, which resulted in a net reversal of prior compensation expense of approximately $0.1 million for the quarter. As of March 31, 2018, total unrecognized compensation cost related to restricted common stock grants was approximately $0.4 million, which will be recognized over a weighted average period of 1.3 years.

A summary of the restricted stock activity for the three months ended March 31, 2018 is as follows:

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.

For the quarter ended March 31, 2018, there were no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017, as supplemented by our Periodic Report on Form 10-Q for the period ended March 31, 2018.

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 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, 2018, we know of no significant probable or possible environmental contingent liabilities.

As of March 31, 2018, we have posted $32.0 million in various letters of credit to secure our drilling and related operations.

As of March 31, 2018, 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, 2018 and 2017 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:

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 utilize the plants to process quantities of gas sufficient to meet specified volume commitments, we may be obligated to pay approximately $12.8 million in 2018, $16.9 million in 2019, $17.0 million in 2020, $16.9 million in 2021, $17.0 million in 2022 and $66.5 million thereafter, assuming our average net revenue interest in the region of approximately 54%. Charges incurred for unutilized processing capacity with MarkWest during the three months ended March 31, 2018 and 2017 were $0.6 million and $1.6 million, respectively.

We have contracted with a water district in Ohio to supply bulk water in support of our Ohio drilling operations. The contract is effective from July 5, 2017 through July 4, 2022. Over the duration the contract, we are obligated to purchase 150 million gallons of water at a fixed price of $7.50 per 1,000 gallons. As of March 31, 2018, our future commitment for unpurchased volumes is approximately $0.6 million.

We have contracted drilling rig services for one rig to support our Appalachian Basin operations. The minimum cost to retain the rig would require gross payments of approximately $1.2 million for the remainder of 2018, which would be partially offset by other working interest owners, whose interest and share of these expenses vary from well to well. Our current development program ended in early April and we expect to pay the associated early termination fees by the end of the third quarter of 2018. We also have contracted completion services in the Appalachian Basin. The minimum gross cost to retain these completion services is approximately $2.8 million for the remainder of 2018, which would be partially offset by other working interest owners, whose interests and share of these expenses vary from well to well.

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 natural gas, NGLs and condensate. 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 $370.1 million through 2029.

For the three months ended March 31, 2018 and 2017, we incurred expenses related to the transportation, processing and marketing of our natural gas, condensate and NGLs of approximately $31.1 million and $26.3 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, 2018 and 2017, we incurred fees related to unutilized capacity commitments of approximately $0.7 million and $0.7 million, respectively. 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:

On June 14, 2016, we, through our wholly owned subsidiaries, Penntex Resources Illinois, LLC, Rex Energy I, LLC, Rex Energy IV, LLC, Rex Energy Marketing, LLC, R. E. Ventures Holdings, LLC, and Rex Energy Operating Corp. (collectively, “Rex”), entered into a Purchase and Sale Agreement (the “Agreement”) with Campbell Development Group, LLC (“Campbell”). An addendum executed in conjunction with the Agreement allows for Rex to receive from Campbell potential additional proceeds of up to $9.9 million, in installments of $0.9 million per quarter, over the period beginning with the quarter ending December 31, 2016, and ending with the quarter ending June 30, 2019. For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of West Texas Intermediate (“WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. As of March 31, 2018, the first six of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI of five out of the six below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds for the first five measurement periods. As of March 31, 2018 the calculated average spot price of WTI was above the threshold price in the agreement, we then have qualified to receive the additional proceeds for the current period. As of March 31, 2018, we have the potential to receive up to $4.5 million of additional proceeds if the WTI exceeds the price per Bbl as specified in the agreement. Proceeds earned for any quarter are payable to us within one year and fifteen days following the end of the quarter in which additional proceeds are earned. For additional information, see Note 10, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.

In 2012, Pennsylvania 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. All fees owed are due on April 1 of each year. For the three months ended March 31, 2018 and 2017, we recorded expense of approximately $0.6 million and $0.8 million, respectively. We record expenses related to the impact fees as Production and Lease Operating Expense. As of March 31, 2018, approximately $0.6 million was accrued for the 2018 impact fees.

Basic income (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, 2018 and 2017, we excluded stock options to purchase 75,363 shares and 117,122 shares, respectively, of our common stock, due to the exercise price of all exercisable outstanding options exceeding the average market price of our common shares during the period. For the three months ended March 31, 2018, there were no performance-based restricted shares excluded. For the three months ended March 31, 2017, we excluded performance-based restricted stock of 43,124 shares, 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, 2018 and 2017, we excluded the assumed conversion of preferred stock equating to 221,502 common shares, due to the antidilutive effect caused by the assumed conversion. The following table sets forth the computation of basic and diluted earnings per common share:

RW Gathering, LLC (“RW Gathering”) is a Delaware limited liability company that we jointly owned with WPX Energy Inc. (“WPX”) and Summit Discovery Resources II, LLC and Sumitomo Corporation (collectively, “Sumitomo”), with our ownership equaling 40%. RW Gathering owns gas-gathering and other midstream assets that service jointly owned properties in Westmoreland and Clearfield Counties, Pennsylvania. Effective as of January 1, 2018, we sold our 40% interest in RW Gathering to COG2, LLC in connection with the sale of our interest in 61 wells located in Westmoreland, Centre and Clearfield Counties, Pennsylvania (the “Westmoreland Sale”). For additional information regarding the Westmoreland Sale, see Note 4, Business and Oil and Gas Property Dispositions, to our Consolidated Financial Statements.

During the three months ended March 31, 2017, 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 December 31, 2017, there were no receivables or payables due between RW Gathering and us.

For the three months ended March 31, 2018 and 2017, impairment expenses incurred were approximately $8.2 million and $1.5 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 2018 included approximately $6.9 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio. Impairments of proved properties in our Westmoreland County operations totaled approximately $1.2 million during the first three months of 2018. 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 and future development plans. Our estimates of future cash flows attributable to our oil and gas properties could decline if commodity prices decline, which may result in our incurrence of additional impairment expense. As of March 31, 2018, we continued to carry the costs of undeveloped properties of approximately $179.3 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale and for which we currently have development, trade or lease extension plans.

The expense incurred during the first three months of 2017 included proved properties of approximately $0.8 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which were in Butler County, Pennsylvania and Warrior North in Ohio. Impairments of proved properties in our Butler County operations totaled approximately $0.7 million during the first three months of 2017

For the three months ended March 31, 2018 and 2017, exploration expenses for continuing operations incurred were approximately $0.2 million, respectively. Approximately $0.1 million of the expense incurred in 2018 was due to geological and geophysical type expenditures and the remaining $0.1 million was due to delay rentals. Approximately $0.1 million of the expense incurred in 2017 was due to geological and geophysical type expenditures and the remaining $0.1 million was due to delay rentals.

As of March 31, 2018, we had $600.3 million aggregate principal amount 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, 2018:

The non-guarantor subsidiaries include certain consolidated subsidiaries, including 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, 2018, 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, 2018 and December 31, 2017, the condensed consolidating statements of operations for the three months ended March 31, 2018 and 2017, and the condensed consolidating statements of cash flows for the three months ended March 31, 2018 and 2017.

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	25,087		$	—		$	3		$	—		$	25,090
Accounts Receivable		26,345			—			802			—			27,147
Taxes Receivable		—			—			48			—			48
Short-Term Derivative Instruments		5,891			—			1,841			—			7,732
Inventory, Prepaid Expenses and Other		3,245			—			6,752			—			9,997
Total Current Assets		60,568			—			9,446			—			70,014
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		991,617			—			—			—			991,617
Unevaluated Oil and Gas Properties		179,297			—			—			—			179,297
Other Property and Equipment		19,792			—			—			—			19,792
Wells and Facilities in Progress		52,271			—			—			—			52,271
Pipelines		16,803			—			—			—			16,803
Total Property and Equipment		1,259,780			—			—			—			1,259,780
Less: Accumulated Depreciation, Depletion and Amortization		(367,900	)		—			—			—			(367,900	)
Net Property and Equipment		891,880			—			—			—			891,880
Other Assets		35			—			—			—			35
Intercompany Receivables		—			—			1,096,898			(1,096,898	)		—
Investment in Subsidiaries – Net		(2,805	)		—			(287,208	)		290,013			—
Long-Term Derivative Instruments		2,589			—			291			—			2,880
Deferred Tax Assets - Long Term		—			—			130			—			130
Total Assets	$	952,267		$	—		$	819,557		$	(806,885	)	$	964,939
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	70,394		$	—		$	—		$	—		$	70,394
Current Maturities of Long-Term Debt		2,082			—			867,115			—			869,197
Accrued Liabilities		22,478			—			26,765			—			49,243
Short-Term Derivative Instruments		11,706			—			52,965			—			64,671
Total Current Liabilities		106,660			—			946,845			—			1,053,505
Long-Term Derivative Instruments		10,576			—			—			—			10,576
Other Long-Term Debt		7,972			—			—			—			7,972
Other Deposits and Liabilities		6,866			—			—			—			6,866
Future Abandonment Cost		8,355			—			—			—			8,355
Intercompany Payables		1,092,492			4,406			—			(1,096,898	)		—
Total Liabilities		1,232,921			4,406			946,845			(1,096,898	)		1,087,274
Stockholders’ Equity
Preferred Stock		—			—			1			—			1
Common Stock		—			—			11			—			11
Additional Paid-In Capital		177,143			—			654,534			(177,143	)		654,534
Accumulated Deficit		(457,797	)		(4,406	)		(781,834	)		467,156			(776,881	)
Total Stockholders’ Equity		(280,654	)		(4,406	)		(127,288	)		290,013			(122,335	)
Total Liabilities and Stockholders’ Equity	$	952,267		$	—		$	819,557		$	(806,885	)	$	964,939

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	65,025		$	—	$	—		$	—		$	65,025
Other Operating Revenue		4			—		—			—			4
TOTAL OPERATING REVENUE		65,029			—		—			—			65,029
OPERATING EXPENSES
Production and Lease Operating Expense		33,846			—		—			—			33,846
General and Administrative Expense		5,506			—		1,019			—			6,525
Loss on Disposal of Assets		647			—		—			—			647
Impairment Expense		8,168			—		—			—			8,168
Exploration Expense		228			—		—			—			228
Depreciation, Depletion, Amortization and Accretion		15,128			—		—			—			15,128
Other Operating Expense		203			—		—			—			203
TOTAL OPERATING EXPENSES		63,726			—		1,019			—			64,745
INCOME (LOSS) FROM OPERATIONS		1,303			—		(1,019	)		—			284
OTHER INCOME (EXPENSE)
Interest Expense		(670	)		—		(21,977	)		—			(22,647	)
(Loss) Gain on Derivatives, Net		5,325			—		(51,751	)		—			(46,426	)
Other Expense		(1,004	)		—		—			—			(1,004	)
Income From Equity in Consolidated Subsidiaries		—			—		4,954			(4,954	)		—
TOTAL OTHER INCOME (EXPENSE)		3,651			—		(68,774	)		(4,954	)		(70,077	)
INCOME (LOSS) BEFORE INCOME TAX		4,954			—		(69,793	)		(4,954	)		(69,793	)
Income Tax Benefit		—			—		—			—			—
NET INCOME (LOSS)	$	4,954		$	—	$	(69,793	)	$	(4,954	)	$	(69,793	)
Preferred Stock Dividends		—			—		(598	)		—			(598	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	4,954		$	—	$	(70,391	)	$	(4,954	)	$	(70,391	)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net (Loss) Income	$	4,954		$	—	$	(69,793	)	$	(4,954	)		(69,793	)
Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities
Depreciation, Depletion, Amortization and Accretion		15,128			—		—			—			15,128
(Gain) Loss on Derivatives, Net		(5,325	)		—		51,751			—			46,426
Cash Settlements of Derivatives		(2,009	)		—		—			—			(2,009	)
Equity-based Compensation Expense		(1	)		—		1,019			—			1,018
Impairment Expense		8,168			—		—			—			8,168
Non-cash Interest Expense		—			—		4,161			—			4,161
Loss on Disposal of Assets		647			—		—			—			647
Other Non-Cash Expense		380			—		—			—			380
Changes in operating assets and liabilities
Accounts Receivable		96			—		—			—			96
Taxes Receivable		—			—		2,001			—			2,001
Inventory, Prepaid Expenses and Other Assets		(1,610	)		—		(4,243	)		—			(5,853	)
Accounts Payable and Accrued Liabilities		12,992			—		12,645			—			25,637
Other Assets and Liabilities		(89	)		—		—			—			(89	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		33,331			—		(2,459	)		(4,954	)		25,918
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		23,143			—		(28,097	)		4,954			—
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		16,188			—		—			—			16,188
Acquisitions of Undeveloped Acreage		(620	)		—		—			—			(620	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(61,738	)		—		—			—			(61,738	)
NET CASH USED IN INVESTING ACTIVITIES		(23,027	)		—		(28,097	)		4,954			(46,170	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit, net of Discounts		—			—		30,555			—			30,555
Repayments of Loans and Other Long-Term Debt		(460	)		—		—			—			(460	)
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES		(460	)		—		30,555			—			30,095
NET INCREASE IN CASH		9,843			—		—			—			9,843
CASH – BEGINNING		15,244			—		3			—			15,247
CASH - ENDING	$	25,087		$	—	$	3		$	—		$	25,090

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	15,244		$	—		$	3		$	—		$	15,247
Accounts Receivable		25,974			—			—			—			25,974
Taxes Receivable		—			—			2,049			—			2,049
Short-Term Derivative Instruments		8,008			—			—			—			8,008
Inventory, Prepaid Expenses and Other		2,106			—			2,508			—			4,614
Total Current Assets		51,332			—			4,560			—			55,892
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,086,625			—			—			—			1,086,625
Unevaluated Oil and Gas Properties		186,523			—			—			—			186,523
Other Property and Equipment		19,640			—			—			—			19,640
Wells and Facilities in Progress		38,660			—			—			—			38,660
Pipelines		16,803			—			—			—			16,803
Total Property and Equipment		1,348,251			—			—			—			1,348,251
Less: Accumulated Depreciation, Depletion and Amortization		(463,899	)		—			—			—			(463,899	)
Net Property and Equipment		884,352			—			—			—			884,352
Other Assets		44			—			—			—			44
Intercompany Receivables		—			—			1,072,637			(1,072,637	)		—
Investment in Subsidiaries – Net		(2,484	)		—			(272,261	)		274,745			—
Long-Term Derivative Instruments		(2	)		—			1,721			—			1,719
Deferred Tax Assets - Long Term		—			—			130			—			130
Total Assets	$	933,242		$	—		$	806,787		$	(797,892	)	$	942,137
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	62,354		$	—		$	—		$	—		$	62,354
Current Maturities of Long-Term Debt		1,926			—			832,399			—			834,325
Accrued Liabilities		32,214			—			13,004			—			45,218
Short-Term Derivative Instruments		14,892			—			—			—			14,892
Total Current Liabilities		111,386			—			845,403			—			956,789
Long-Term Derivative Instruments		14,249			—			—			—			14,249
Long-Term Debt		—			—			—			—			—
Other Long-Term Debt		8,156			—			—			—			8,156
Other Deposits and Liabilities		7,153			—			—			—			7,153
Future Abandonment Cost		9,352			—			—			—			9,352
Intercompany Payables		1,068,231			4,406			—			(1,072,637	)		—
Total Liabilities		1,218,527			4,406			845,403			(1,072,637	)		995,699
Stockholders’ Equity
Preferred Stock		—			—			1			—			1
Common Stock		—			—			10			—			10
Additional Paid-In Capital		177,144			—			652,917			(177,144	)		652,917
Accumulated Deficit		(462,429	)		(4,406	)		(691,544	)		451,889			(706,490	)
Total Stockholders’ Equity		(285,285	)		(4,406	)		(38,616	)		274,745			(53,562	)
Total Liabilities and Stockholders’ Equity	$	933,242		$	—		$	806,787		$	(797,892	)	$	942,137

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	52,065		$	—	$	—		$	—		$	52,065
Other Operating Expense		6			—		—			—			6
TOTAL OPERATING REVENUE		52,071			—		—			—			52,071
OPERATING EXPENSES
Production and Lease Operating Expense		28,934			—		—			—			28,934
General and Administrative Expense		4,461			—		73			—			4,534
Gain on Disposal of Assets		(1,834	)		—		—			—			(1,834	)
Impairment Expense		1,546			—		—			—			1,546
Exploration Expense		220			—		—			—			220
Depreciation, Depletion, Amortization and Accretion		15,468			—		—			—			15,468
Other Operating Income		(21	)		—		—			—			(21	)
TOTAL OPERATING EXPENSES		48,774			—		73			—			48,847
INCOME (LOSS) FROM OPERATIONS		3,297			—		(73	)		—			3,224
OTHER INCOME (EXPENSE)													—
Interest Expense		(365	)		—		(8,778	)		—			(9,143	)
(Loss) Gain on Derivatives, Net		9,798			—		(1,417	)		—			8,381
Other Expense		(28	)		—		—						(28	)
Debt Exchange Expense		—			—		—			—			—
Gain on Extinguishments of Debt		—			—		249						249
Income (Loss) From Equity in Consolidated Subsidiaries		—			—		12,702			(12,702	)		—
TOTAL OTHER INCOME (EXPENSE)		9,405			—		2,756			(12,702	)		(541	)
(LOSS) INCOME BEFORE INCOME TAX		12,702			—		2,683			(12,702	)		2,683
Income Tax Benefit		—			—		—			—			—
NET INCOME (LOSS)		12,702			—		2,683			(12,702	)		2,683
Preferred Stock Dividends		—			—		(598	)		—			(598	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	12,702		$	—	$	2,085		$	(12,702	)	$	2,085

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	12,702		$	—	$	2,683		$	(12,702	)	$	2,683
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion		15,468			—		—			—			15,468
(Gain) Loss on Derivatives, Net		(9,798	)		—		1,417			—			(8,381	)
Cash Settlements of Derivatives		(3,443	)		—		—			—			(3,443	)
Equity-based Compensation Expense		11			—		60			—			71
Non-cash Exploration Expense		11			—		—			—			11
Gain on Disposal of Assets		(1,834	)		—		—			—			(1,834	)
Gain on Extinguishments of Debt		—			—		(249	)		—			(249	)
Non-cash Interest Expense		—			—		6,081			—			6,081
Impairment Expense		1,546			—		—			—			1,546
Other Non-Cash Income		(66	)		—		—			—			(66	)
Changes in operating assets and liabilities
Accounts Receivable		5,174			—		167			—			5,341
Inventory, Prepaid Expenses and Other Assets		410			—		12			—			422
Accounts Payable and Accrued Liabilities		(8,298	)		—		1,309			—			(6,989	)
Other Assets and Liabilities		(139	)		—		—			—			(139	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		11,744			—		11,480			(12,702	)		10,522
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		(8,789	)		—		(3,913	)		12,702			—
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		24,329			—		—			—			24,329
Acquisitions of Undeveloped Acreage		(299	)		—		—			—			(299	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(25,476	)		—		—			—			(25,476	)
NET CASH USED IN INVESTING ACTIVITIES		(10,235	)		—		(3,913	)		12,702			(1,446	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit, net of Discounts		—			—		21,500			—			21,500
Repayments of Long Term Debt and Lines of Credit		—			—		(28,500	)		—			(28,500	)
Repayments of Loans and Other Long-Term Debt		(131	)		—		—			—			(131	)
Debt Issuance Costs		—			—		(567	)		—			(567	)
NET CASH USED IN FINANCING ACTIVITIES		(131	)		—		(7,567	)		—			(7,698	)
NET INCREASE IN CASH		1,378			—		—			—			1,378
CASH – BEGINNING		3,694			—		3			—			3,697
CASH - ENDING	$	5,072		$	—	$	3		$	—		$	5,075

On April 3, 2018, Rex Energy Corporation (“Rex Energy”), and the subsidiary guarantors under the Term Loan Credit Agreement, dated as of April 28, 2017 (the “Credit Agreement”), among Rex Energy, as borrower, certain subsidiaries of Rex Energy, as guarantors, Angelo, Gordon Energy Servicer, LLC, as administrative agent and collateral agent (the “Agent”), and the lenders party thereto (the “Lenders”), entered into a forbearance agreement with the Agent and the requisite Lenders (the “First Forbearance Agreement”).

Under the First Forbearance Agreement, the Agent and the Lenders agreed to forbear from exercising their rights and remedies under the Credit Agreement in respect of certain defaults and alleged defaults thereunder, which include a cross-default as a result of our failure to make an interest payment due on April 2, 2018 pursuant to the terms of the indenture governing the Second Lien Notes and certain financial reporting defaults by us under the Credit Agreement. Under the First Forbearance Agreement, that forbearance continued through April 16, 2018, unless certain specified circumstances caused an earlier termination of that forbearance.

On April 16, 2018, the parties to the First Forbearance Agreement entered into a limited waiver and second forbearance agreement (the “Second Forbearance Agreement”). Pursuant to the terms of the Second Forbearance Agreement, the Agent and Lenders agreed to continue the forbearance through April 23, 2018, unless certain specified circumstances caused an earlier termination of that forbearance. The Second Forbearance Agreement also permitted us to borrow $34,129,754.54 of Delayed Draw Loans (as defined in the Credit Agreement) to cash collateralize the existing letter of credit exposure under the Credit Agreement. On April 23, 2018, Rex Energy, the Agent, the requisite Lenders and Macquarie Bank Limited, in its capacity as the issuer of Letters of Credit under the Credit Agreement, executed a limited waiver and third forbearance agreement (the “Third Forbearance Agreement”), further extending the forbearance period to May 2, 2018. The Third Forbearance Agreement provides that the Agent and the Borrower may agree to extend such forbearance period further. In accordance with the terms of the Third Forbearance Agreement, the Agent and the Borrower agreed to extend the forbearance period through May 9, 2018. On May 10, 2018, Rex Energy, the Agent and the requisite Lenders executed a Limited Waiver and Fourth Forbearance Agreement (the “Fourth Forbearance Agreement” and together with the First Forbearance Agreement, the Second Forbearance Agreement and the Third Forbearance Agreement, the “Forbearance Agreements”), further extending the forbearance period to May 17, 2018. Under the Fourth Forbearance Agreement, the Lenders also agreed to lend us up to approximately $6.2 million of additional delayed draw loans under the Credit Agreement, notwith standing that the indebtedness under the Credit Agreement has been accelerated and the lenders’ commitments thereunder have been terminated.

Subject to the terms of the Forbearance Agreements, as a result of the existing defaults referred to above, the Agent and the Lenders have the right to exercise their rights and remedies under the Credit Agreement, including, but not limited to, the right to enforce their security interest in our and the subsidiary guarantors’ assets pledged as collateral to secure obligations under the Credit Agreement and to pursue collection from us and the subsidiary guarantors.

The Forbearance Agreements do not cure or waive the existing defaults. Further, the Forbearance Agreements do not prevent the Agent from accelerating the amounts owed under the Credit Agreement, but prevent the Agents from taking any enforcement actions with respect to any accelerated obligations during the applicable forbearance period. Upon expiration or termination of the applicable forbearance period for any reason, the Agent and the Lenders will be able to exercise all rights and remedies granted to them under the Credit Agreement.

On April 27, 2018, we received from the Agent a written notice of acceleration of the outstanding amounts due under the Credit Agreement, including notes and loans, together with all accrued interest thereon, all fees, any yield maintenance amount, any call protection amount and any other similar amounts thereon (the “Notice of Acceleration”). As a result of the Notice of Acceleration, the aggregate amount due under the Credit Agreement is approximately $255 million, not including any yield maintenance and call protection amounts due pursuant to the terms of the Credit Agreement. However, because the applicable forbearance period is in effect and continuing, the Agent is prevented from taking any enforcement actions with respect to the accelerated amounts.

We entered into the Forbearance Agreements to provide us with time to continue discussions with our lenders and other holders of our securities, including the Second Lien Notes, our preferred stock, and our common stock, regarding potential transactions, or to otherwise opportunistically consider strategic financing proposals that management believes may be beneficial to us and our stakeholders. There can be no assurance that we will reach any agreement with any stakeholders on a financial restructuring by the end of the applicable forbearance period, if at all, or that the currently applicable forbearance period will be extended.

On May 3, 2018, Rex Energy, certain of its subsidiaries and certain holders (the “Holders”) of our Second Lien Notes entered into a Forbearance Agreement (the “Second Lien Forbearance Agreement”), pursuant to which the Holders agreed to forebear, and to direct the trustee with respect to the Second Lien Notes to forbear, through May 9, 2018 (unless certain specified circumstances cause an earlier termination), from exercising their rights and remedies under the indenture governing the Second Lien Notes in respect of certain defaults thereunder, including a default as a result of our failure to make an interest payment due under that indenture. The Second Lien Forbearance Agreement does not cure or waive the existing defaults. The Second Lien Forbearance Agreement provides that we and the Holders may agree to extend such forbearance period further. In accordance with the terms of the Second Lien Forbearance Agreement, we and the Holders agreed to extend the forbearance period through May 17, 2018.

On April 2, 2018, we did not make the semiannual payment of interest due in respect of our Second Lien Notes. Because we did not make such interest payment within the applicable 30-day grace period, the Second Lien Notes are currently subject to acceleration, upon requisite notice. In addition, the failure to make such interest payment is an event of default under the indentures governing the Existing Notes. On May 3, 2018, we received from the trustee under such indentures written notices of acceleration of the Existing Notes.

On April 3, 2018, we received a Staff Determination Letter from the Listing Qualifications Department (the “Staff”) of The Nasdaq Stock Market LLC (“Nasdaq”) indicating that, based on our continued non-compliance with Nasdaq Listing Rule 5550(b), our common stock would be suspended from trading on Nasdaq at the opening of business on April 12, 2018, and a Form 25-NSE would be filed with the Securities and Exchange Commission, which would remove the Company’s common stock from listing and registration on Nasdaq, in each case unless the Company requests an appeal before the Nasdaq Hearings Panel (the “Panel”). The Company did not appeal this determination. Nasdaq filed a Form 25-NSE on April 19, 2018. Following the delisting of our common stock from Nasdaq, our common stock has been quoted on the OTC Markets Group’s Pink marketplace.

As previously disclosed, on November 16, 2017, the Staff notified us that we did not comply with Nasdaq’s continued listing requirements because (i) our reported stockholders’ equity as of September 30, 2017 was less than $2.5 million and (ii) we did not meet the alternative criteria for continued listing set forth in Nasdaq Listing Rule 5550(b) based on market value of listed securities or net income from continuing operations. We were provided with the opportunity to present our plan to regain compliance with that requirement for the Staff’s review and did so by submissions dated January 2, 2018 and January 19, 2018. By letter dated January 25, 2018, the Staff granted our request for an extension to evidence compliance with Nasdaq Listing Rule 5550(b) until March 12, 2018 to enter into a balance sheet restructuring agreement that would enable it to comply with this requirement and until May 15, 2018 to obtain shareholder approval for and to close such a transaction. Because we had not entered into a restructuring agreement that would enable us to regain compliance with Nasdaq Listing Rule 5550(b), we did not timely satisfy the terms of the extension, which resulted in the Staff’s April 3, 2018 determination letter.

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, 2017 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.

We are an independent natural gas, NGL and condensate company operating in the Appalachian Basin, where we are focused on our Marcellus Shale, Utica Shale and Upper Devonian Shale drilling and exploration activities. 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, with a regional office in Cranberry, Pennsylvania.

We believe the outlook for our business is favorable despite the continued uncertainty of natural gas and oil 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 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 natural gas and oil 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.

On March 13, 2018, the Company, entered into a Purchase and Sale Agreement with XPR Resources, LLC (“XPR”), pursuant to which the Company agreed to sell to XPR certain of its non-operated oil and gas interests in 61 wells located in Westmoreland and Clearfield Counties, Pennsylvania, along with associated production and other ancillary assets. The acreage sold was considered non-core to the Company. In a related transaction, the Company entered into a Membership Interest Purchase Agreement on the same date with COG2, LLC (“COG2”), an affiliate of XPR, pursuant to which the Company agreed to sell to COG2 its 40% membership interest in RW Gathering, LLC. Closing occurred on March 21, 2018, with an effective date for the transactions of January 1, 2018. Total consideration for the transactions was approximately $17.2 million, subject to customary closing and post-closing adjustments. We received approximately $16.4 million of proceeds on March 23, 2018. Approximately $0.2 million of the total proceeds due to us is being held in escrow. The sale of assets resulted in a loss on the disposal of assets of approximately $0.6 million in the first quarter of 2018.

Ability to Continue as a Going Concern, Covenant Violations and Planned Chapter 11 Reorganization

As of May 15, 2018, the date we filed our Consolidated Financial Statements with the Securities and Exchange Commission on Form 10-Q for the quarterly period ended March 31, 2018, we have not yet made the semi-annual interest payment to the holders of our second lien notes that was due April 2, 2018. The second lien notes provide for a 30-day grace period in which to pay the interest coupon due to the noteholders, which expired on May 2, 2018. Nonpayment of the interest due has resulted in an event of default under our term loan agreement and the second lien indentures. We received a notice of acceleration on April 27, 2018, from the lenders under our term loan agreement demanding immediate payment of all outstanding notes and loans, together with all accrued interest, fees, yield maintenance and call protection amounts. As of March 31, 2018, we recorded at fair value a liability for the yield maintenance and call protection amounts of approximately $53.0 million, recorded as Short-Term Derivative Instruments on our Consolidated Balance Sheet (see Note 8, Derivative Instruments and Fair Value Measurements and Note 7, Long-Term Debt, to our Consolidated Financial Statements for additional information. For the three months ended March 31, 2018, we recorded a loss of approximately $53.0 million as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations in connection with various events occurring during the first quarter, which have led to the Company deciding to file Chapter 11 Bankruptcy which have caused these amounts to become due and payable. As of March 31, 2018, the outstanding balance of the Term Loan was $274.0 million, inclusive of yield maintenance, call protection, accrued interest and fees. In addition to the non-payment of second lien interest, we also encountered additional events of default related to certain non-financial covenants associated with our term loan agreement. These additional events of default are a result of our failure to timely deliver to the term loan lenders our unaudited

quarterly financial statements for the quarter ended December 31, 2017 and our annual audited financial statements for the year ended December 31, 2017, as well as related inadvertent failures to provide accurate related written notices to the lenders, and written notices of the events of default in a subsequent draw request under the term loan agreement.

We have entered into forbearance agreements with each of the requisite lenders under our senior term loan facility and the second lien notes. The forbearance agreements do not constitute a waiver of the events of default related to the nonpayment of interest and other non-financial covenants defaults described above. The forbearance agreements specify that the lenders will forbear from taking any enforcement actions during the forbearance period, which extends through May 17, 2018, unless earlier terminated, but does not prevent acceleration of amounts owed. We do not have sufficient liquidity to repay these amounts. The Company has been unsuccessful in negotiating an alternative restructuring with its various stakeholders, outside of a voluntary pre-arranged Chapter 11 bankruptcy filing. As such, the ability to conclude a successful negotiation with our lenders and note holders out of court is not expected to occur. An acceleration notice from the lenders of our senior term loan has been received and we lack the liquidity to pay these obligations. Given these circumstances, the Company is currently in the process of preparing to file for protection under Chapter 11 of the U.S. Bankruptcy Code which is expected to occur imminently following the filing of this Form 10-Q. There can be no assurances that the Company will be able to reorganize its capital structure on terms acceptable to the Company, its creditors, or at all.

During the three months ended March 31, 2018, we produced 19,872 MMcfe. Overall, our production for the three months ended March 31, 2018 averaged 216 MMcfe per day. As of March 31, 2018, we had six gross (4.0 net) wells drilled and awaiting completion. As of March 31, 2018, we had seven gross (5.0 net) wells resting or awaiting pipeline connection. Our drilling and completion activity for the period indicated is set forth in the table below.

Our development program for the remainder of 2018 contemplates the drilling of one gross (0.5 net) wells and the completion of seven gross (4.5 net) wells. We are not anticipating any changes to this program as a result of the planned Chapter 11 bankruptcy filing and believe we will have access to ample liquidity to complete the drilling and completion of these wells in the second quarter of 2018.

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 natural gas during the three months ended March 31, 2018 averaged approximately $2.69 per Mcf, as compared to $3.16 Mcf for the same period in 2017. Our realized price, before derivative settlements, for condensate during the three months ended March 31, 2018 averaged approximately $57.17 per barrel, as compared to $46.07 per barrel for the same period in 2017. Our realized price, before derivative settlements, for C3+ NGLs during the three months ended March 31, 2018 averaged approximately $37.45 per barrel, as compared to $30.84 per barrel for the same period in 2017. Our realized price, before derivative settlements, for ethane during the three months ended March 31, 2018 averaged approximately $10.11 per barrel as compared to $9.48 per barrel for the same period in 2017.

For the three months ended March 31, 2018, we recorded impairment expense of approximately $8.2 million. Decreases in commodity prices will decrease our natural gas, NGL and condensate revenues and could reduce the amount of natural gas, NGL and condensate 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, 2018, approximately $544.7 million, or 84.7%, of our evaluated oil and natural gas properties were located in our Butler Marcellus operating area. Based on estimates of future cash flows, 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 properties totaled approximately $98.7 million as of March 31, 2018.

During the first quarter of 2017, we entered into privately negotiated debt-to-equity exchanges with certain holders of 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”) in exchange for unrestricted shares of our common stock. These exchanges resulted in the retirement of $0.2 million of our Existing Notes, in exchange for the issuance of approximately 0.3 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain of approximately $0.2 million, included as a component of Gain (Loss) on Extinguishments of Debt in our Consolidated Statement of Operations for the three months ended March 31, 2017.

paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised its option to participate in 23 of these additional wells. Total consideration for this transaction could be up to $175.0 million with approximately $134.0 million committed as of March 31, 2018. BSP has paid for its interest in elected wells as of December 31, 2017, and no additional elections have occurred during the quarter ended March 31, 2018. The remainder of the proceeds may be received if BSP makes additional elections as additional wells are drilled to total depth or placed in sales. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units in which it participates. As of March 31, 2018, all 45 committed wells were in line and producing.

The following table sets forth summary information regarding natural gas, NGL and condensate production and product prices for the three months ended March 31, 2018:

The following table sets forth summary information regarding natural gas, NGL and condensate revenues, production volumes, average product prices and average production costs for the three months ended March 31, 2018:

Operating revenue for the three months ended March 31, 2018 increased 24.9% when compared to the same periods in 2017. The increase in operating revenue for the three months ended March 31, 2018 can be primarily attributed to higher production volumes and condensate and NGL prices. Our production increased to 19,871 MMcfe for the three month period ended March 31, 2018 from 15,604 MMcfe for the three month period ended March 31, 2017, or approximately 27.4%. For the three month period ended March 31, 2018, our realized sales price for natural gas decreased to $2.69 per Mcf from $3.16 per Mcf, condensate increased to $57.17 per barrel from $46.07 per barrel, C3+ NGLs increased to $37.45 per barrel from $30.84 per barrel, and ethane increased to $10.11 per barrel from $9.48 per barrel, respectively, when compared to the same period in 2017.

Operating expenses increased $15.9 million for the three months ended March 31, 2018, as compared to the same periods in 2017. Operating expenses are primarily composed of: Production and Lease Operating Expenses, G&A Expenses, Other Operating Expense, Exploration Expenses, Impairment Expense and DD&A Expenses. The increase in operating expenses were largely attributable to an increase in production and lease operating expense due to higher production volume, impairment charges, a loss on the disposal of an asset and higher G&A expenses due to employee costs. The increase of many of these operating expenses is consistent with our overall drilling activity, which is in accordance with our capital plan. The increase in impairment was largely due to undeveloped leases that expired or are expected to expire without being developed.

Comparison of the Three Months Ended March 31, 2018 to the Three Months Ended March 31, 2017

Gas, condensate and NGL revenue, including the effects of cash settled derivatives, for the three-months ended March 31, 2018 is summarized in the following table:

Average realized price received for natural gas, NGLs and condensate during the first quarter of 2018, after the effect of derivative activities, was $3.17 per Mcfe, an increase of 1.6%, or $0.05 per Mcfe, from the same period in 2017. The average price for natural gas, after the effect of derivative activities, decreased 9.3%, or $0.28 per Mcf, to $2.76 per Mcf. The average price for condensate, after the effect of derivative activities, increased 15.3%, or $7.04 per barrel, to $53.17 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, increased 27.4%, or $6.90 per barrel, to $32.09 per barrel. The average price for ethane, after the effect of derivative activities, increased 12.3%, or $1.20 per barrel, to $10.92 per barrel. Our derivative activities effectively decreased net realized prices by $0.10 per Mcfe and $0.22 per Mcfe in the first quarter of 2018 and 2017, respectively.

Our realized sales price for natural gas was lower than the average Henry Hub NYMEX pricing by approximately $0.32 per Mcf during the first quarter of 2018, primarily due to basis differentials in the northeastern United States, which were partially offset by sales to the Gulf Coast, which receive Henry Hub NYMEX pricing. 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, including transportation of 130,000 Mcf per day to the Gulf Coast.

Production volumes in the first quarter of 2018 increased 27.4%, or 4,268.2 MMcfe, from the first quarter of 2017 primarily the success of our Marcellus and Utica Shale horizontal drilling activities and the sale of our Warrior South assets during first quarter of 2017, which decreased volumes during the prior year. Natural gas production increased approximately 11.1%, condensate production increased approximately 56.1%, C3+ NGL production increased approximately 29.8% and ethane production increased approximately 79.5%.

Overall, our production for the first quarter of 2018 averaged 215,997 Mcfe per day, of which 55.4% was attributable to natural gas, 3.5% to condensate, 16.5% to C3+ NGLs and 24.5% to ethane production.

Statements of Operations for the three months ended March 31, 2018 and 2017 are as follows:

	For the Three Months Ended March 31,
($ in Thousands)	2018			2017			Change			%
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	65,025		$	52,065		$	12,960			24.9	%
Other Operating Revenue		4			6			(2	)		(33.3	)%
TOTAL OPERATING REVENUE		65,029			52,071			12,958			24.9	%
OPERATING EXPENSES
Production and Lease Operating Expense		33,846			28,934			4,912			17.0	%
General and Administrative Expense		6,525			4,534			1,991			43.9	%
Loss (Gain) on Disposal of Assets		647			(1,834	)		2,481			(135.3	)%
Impairment Expense		8,168			1,546			6,622			428.3	%
Exploration Expense		228			220			8			3.6	%
Depreciation, Depletion, Amortization and Accretion		15,128			15,468			(340	)		(2.2	)%
Other Operating (Income) Expense		203			(21	)		224			(1,066.7	)%
TOTAL OPERATING EXPENSES		64,745			48,847			15,898			32.5	%
INCOME FROM OPERATIONS		284			3,224			(2,940	)		(91.2	)%
OTHER INCOME (EXPENSE)
Interest Expense		(22,647	)		(9,143	)		(13,504	)		147.7	%
(Loss) Gain on Derivatives, Net		(46,426	)		8,381			(54,807	)		(653.9	)%
Other Expense		(1,004	)		(28	)		(976	)		3,485.7	%
Gain on Extinguishments of Debt		—			249			(249	)		(100.0	)%
TOTAL OTHER EXPENSE		(70,077	)		(541	)		(69,536	)		12,853.2	%
INCOME (LOSS) BEFORE INCOME TAX		(69,793	)		2,683			(72,476	)		(2,701.3	)%
Income Tax Benefit		—			—			—		N/A
NET (LOSS) INCOME		(69,793	)		2,683			(72,476	)		(2,701.3	)%

Production and Lease Operating Expense increased approximately $4.9 million, or 17.0%, in the first quarter of 2018 from the same period in 2017. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells, firm capacity expense related to additional avenues in delivering our products and variable costs such as transportation, marketing, processing and gathering. Transportation, marketing, processing and gathering fees accounted for approximately 88.4% of our total Production and Lease Operating Expense in the first quarter of 2018, as compared to 90.7% from the same period in 2017. 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 were $1.70 and $1.85 per Mcfe for the three months ended March 31, 2018 and 2017, respectively. The decrease on a per unit basis is due to flowing higher volumes, which has limited our unutilized reservation fees

G&A Expense for the first quarter of 2018 increased approximately $2.0 million, or 43.9%, to $6.5 million from the same period in 2017. The increase was mostly due to employee costs and expense associated with the vesting of our restricted stock, which was approximately $1.4 million and $0.9 million, respectively. Partially offsetting these expenses was a decrease in consulting fees.

Impairment Expense for the first quarter of 2018 was approximately $8.2 million. We evaluate impairment of our properties when events occur that indicate that the carrying value of these properties may not be recoverable. The expense incurred during the first quarter of 2018 included approximately $6.9 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio. Based on the current commodity price environment, we do not expect to develop these properties prior to expiration of the associated leases. Impairment of proved properties in our Westmoreland County operations totaled approximately $1.2 million during the first quarter of 2018. 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, 2018, which indicated that the full 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, downward revisions of proved reserves may be significant and could result in additional impairment expense.

Exploration Expense for the first quarter of 2018 was approximately $0.2 million, which remained flat from the prior year. The expense incurred in 2018 was mostly due to geological and geophysical type expenditures and delay rentals, which is the same as the first quarter of 2017.

DD&A Expense for the first quarter of 2018 decreased approximately $0.4 million, or 2.2%, from $15.5 million for the same period in 2017. Contributing to the decrease in DD&A expense was a true up of ARO accretion during the first quarter of 2018.

Other Operating Expense for the first quarter of 2018 increased approximately $0.2 million as compared to the same period in 2017. The expense in 2018 was primarily related to a firm capacity commitments and inventory adjustments.

Interest Expense for the first quarter of 2018 was approximately $22.6 million as compared to $9.1 million for the same period in 2017. The increase in interest expense is primarily due to interest charges incurred on the term loan and fees charged on available but undrawn borrowing base of the Delayed Draw Term Loan established in April 2017, an increase in interest on the Senior Notes, due to a change in the rate from 1% to 8% and the write-off of deferred financing fees and OID related to our term loan. We discuss our Term Loan and Senior Notes in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

(Loss) Gain on Derivatives, net included a loss of approximately $46.4 million for the first quarter of 2018 as compared to a gain of $8.4 million for the same period in 2017. The gain recorded for the first quarter of 2018 included cash payments for commodity derivatives of $1.2 million while the gain incurred in the first quarter of 2017 included cash receipts of approximately $3.4 million for commodity derivatives. Changes related to our commodity derivatives were attributable to the volatility of natural gas, NGL and oil commodity prices along with changes in our portfolio of outstanding derivatives. Losses from derivative activities generally reflect higher natural gas, NGL and oil 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 gas, NGL and oil production volumes given the highly volatile gas, NGL and oil commodities market. In addition to our commodity derivatives, we incurred a loss of approximately $53.0 million related to our Term Loan embedded derivatives.

We believe natural gas, NGL and oil 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 2017 and 2018, 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.

Gain on Extinguishments of Debt for the first quarter of 2018 was zero. Gain on extinguishments of debt for the first quarter of 2017 totaled approximately $0.2 million, resulting from debt to equity exchanges with certain holders of our Senior Notes. We discuss the debt to equity exchanges in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Income Tax Expense for continuing operations for the first quarter of 2018 and 2017 was zero, due to the full valuation allowances we maintain against our net deferred tax assets.

Net Income (Loss) Attributable to Rex Energy for the first quarter of 2018 was a loss of approximately $69.8 million, as compared to income of $2.7 million for the same period in 2017 as a result of factors discussed above.

EBITDAX (Non-GAAP) from operations increased approximately $8.9 million to $24.5 million for the three-month period ended March 31, 2018, as compared to the same period in 2017. The increase in EBITDAX can be primarily attributed to the increased production volumes for natural gas, NGLs and condensate, resulting in increased operating revenues and add backs of interest and impairment expense, which are higher than the prior year..

LOE per Mcfe measures the average cost of extracting natural gas, NGLs and condensate from our 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 natural gas and NGL reserves in the ground. LOE per Mcfe decreased $0.15 to $1.70 for the three months ended March 31, 2018 as compared to $1.85 for the same period in 2017. Our LOE is largely composed of variable type costs such as transportation, marketing, processing and gathering. For the first quarter of 2018, transportation, capacity and processing fees accounted for approximately 88.4% of our total Production and Lease Operating Expense as compared to 90.7% during the same period of 2017. 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 into include firm capacity rights, for which we may incur a fee for unused capacity. As we continue to grow our operations, we expect our lifting cost to decrease as we gain additional efficiencies of scale and utilize all of our firm capacity and transportation commitments.

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 were approximately $0.33 for the three month period ended March 31, 2018, as compared to $0.29 for the same period in 2017. The increases in G&A costs in 2018 is due primarily to employee costs and non-cash compensation expense.

As of May 15, 2018, the date we filed our Consolidated Financial Statements with the Securities and Exchange Commission on Form 10-Q for the quarterly period ended March 31, 2018, we have not yet made the semi-annual interest payment to the holders of our second lien notes that was due April 2, 2018. The second lien notes provide for a 30-day grace period in which to pay the interest coupon due to the noteholders, which expired on May 2, 2018. Nonpayment of the interest due has resulted in an event of default under our term loan agreement and the second lien indentures. We received a notice of acceleration on April 27, 2018, from the lenders under our term loan agreement demanding immediate payment of all outstanding notes and loans, together with all accrued interest, fees, yield maintenance and call protection amounts. As of March 31, 2018, the yield maintenance and call protection amount totaled approximately $53.0 million and the outstanding balance of the Term Loan was $274.0 million, inclusive of yield maintenance, call protection, accrued interest and fees. In addition to the non-payment of second lien interest, we also encountered additional events of default related to certain non-financial covenants associated with our term loan agreement. These additional events of default are a result of our failure to timely deliver to the term loan lenders our unaudited quarterly financial statements for the quarter ended December 31, 2017 and our annual audited financial statements for the year ended December 31, 2017, as well as related inadvertent failures to provide accurate related written notices to the lenders, and written notices of the events of default in a subsequent draw request under the term loan agreement.

We have entered into forbearance agreements with each of the requisite lenders under our senior term loan facility and the second lien notes. The forbearance agreements do not constitute a waiver of the events of default related to the nonpayment of interest and other non-financial covenants defaults described above. The forbearance agreements specify that the lenders will forbear from taking any enforcement actions during the forbearance period, which extends through May 17, 2018, unless earlier terminated, but does not prevent acceleration of amounts owed. We do not have sufficient liquidity to repay these amounts. The Company has been unsuccessful in negotiating an alternative restructuring with its various stakeholders, outside of a voluntary pre-arranged Chapter 11 bankruptcy filing. As such, the ability to conclude a successful negotiation with our lenders and note holders out of court is not expected to occur. An acceleration notice from the lenders of our senior term loan has been received and we lack the liquidity to pay these obligations. Given these circumstances, the Company is currently in the process of preparing to file for protection under Chapter 11 of the U.S. Bankruptcy Code which is expected to occur imminently following the filing of this Form 10-Q. There can be no assurances that the Company will be able to reorganize its capital structure on terms acceptable to the Company, its creditors, or at all.

As a result of the aforementioned covenant violations and subsequent forbearance agreements, we are restricted from any further borrowings under our Term Loan. In tandem with current negotiations with the various stakeholders in our Term Loan and Senior Notes, we have been negotiating a new Debtor-In-Possession financing agreement (the “DIP Facility”) which will allow us to continue operations during the bankruptcy process.

Our primary needs for cash are for the exploration, development and acquisition of gas and oil properties. During the three months ended March 31, 2018, we spent $62.7 million of capital on asset acquisitions, drilling projects, facilities and related equipment and acquisitions of unproved acreage. We funded our capital program with proceeds from the sale of our Westmoreland County assets, proceeds from the Term Loan and cash from operations. The remainder of our 2018 capital budget is expected to be funded primarily by cash on hand and cash flows from operations. While not yet finalized, we intend to fund the rest of our expenditures in 2018 with proceeds from the DIP Facility.

Our cash flows from operations are driven by commodity prices and production volumes. Prices for natural gas, NGLs and oil 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, we have primarily used cash flows from operations, borrowings from lines of credit and net proceeds from debt and equity offerings to fund the exploration and development of our gas and oil interests. As of March 31, 2018, we had approximately $25.1 million of cash on hand and outstanding borrowings under our Term Loan of approximately $221.0 million with an additional $32.0 million of undrawn letters of credit outstanding. As of March 31, 2018, there was no additional availability under our Term Loan.

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 natural gas, NGL and condensate reserves. If commodity prices decrease, our operating cash flows may decrease, which could reduce 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 natural gas, NGL and condensate reserves through acquisitions and our development and exploration programs, we may also suffer a reduction in our operating cash flows and access to funds under our Term Loan.

Due to the depressed commodity price environment, in January 2016, we suspended payment of our quarterly dividend on shares of our Series A Convertible, Perpetual Preferred Stock (“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. In April and July 2017, we declared a quarterly dividend of $0.6 million, based on $150.00 per share on our Preferred Stock ($1.50 per depositary share, each representing 1/100 interest in a share of Preferred Stock) payable on May 15, 2017 and August 15, 2017, respectively; each dividend payment was applied to the earliest dividend in arrears at the time of payment. In October 2017and January 2018, we declared a quarterly dividend in the same amount; these dividend payments were paid in stock on November 15, 2017 and February 15, 2018, respectively, and were applied to the earliest dividend still in arrears at the time of payment. Any subsequent quarterly dividends declared and paid will be applied to the earliest dividend then in arrears until the arrearage is satisfied and dividends are current. In April 2018, we again suspended payment of our quarterly dividend on our Preferred Stock. As a result of having dividends in arrears on our Preferred Stock, we are not currently 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 public offerings of 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 outstanding 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. 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.

In connection with certain of our marketing, transportation and processing agreements, we may be obligated to pay minimum fees of $231.0 million over the next five years, depending on our levels of production. In connection with certain of these agreements, we have guaranteed the payment of obligations up to a maximum of $370.2 million over the life of the agreements, which range from two to 20 years. These guarantees will decrease over time as the commitments are satisfied.

Our Term Loan contains a number of restrictive covenants and limitations that impose significant operating and financial restrictions on us. Our financial covenants require us to maintain a maximum “Ratio of Net Senior Secured Debt to EBITDAX” of 3.25 to 1.0, a minimum “Ratio of EBITDAX to Interest Expense” of 1.0 to 1.0, increasing to 1.3 to 1.0 for quarterly periods ending on or after March 31, 2018 and a minimum “PDP Coverage Ratio” of 1.65 to 1.00. Failure to comply with these covenants could have a material adverse effect on our business. As of March 31, 2018, our Net Senior Secured Debt to EBITDAX Ratio was 2.92 to 1.00 and EBITDAX to Interest Expense ratio was 2.51 to 1.00 and our PDP Coverage Ratio was 2.34 to 1.00. If an event of default under our Term Loan occurs and remains uncured, among other things, the lenders thereunder:

Due to other specified events of default described above, we are currently restricted from any further borrowing under our Term Loan. We have entered into forbearance agreements with each of the requisite lenders under our senior term loan facility and the second lien notes. The forbearance agreements do not constitute a waiver of the events of default related to the nonpayment of interest and other non-financial covenants defaults described above. The forbearance agreements specify that the lenders will forbear from taking any enforcement actions during the forbearance period, which extends through May 17, 2018, unless earlier terminated, but does not prevent acceleration of amounts owed. We do not have sufficient liquidity to repay these amounts. The Company has been unsuccessful in negotiating an alternative restructuring with its various stakeholders, outside of a voluntary pre-arranged Chapter 11 bankruptcy filing. As such, the ability to conclude a successful negotiation with our lenders and note holders out of court is not expected to occur. An acceleration notice from the lenders of our senior term loan has been received and we lack the liquidity to pay these obligations. Given these circumstances, the Company is currently in the process of preparing to file for protection under Chapter 11 of the U.S. Bankruptcy Code which is expected to occur imminently following the filing of this Form 10-Q. There can be no assurances that the Company will be able to reorganize its capital structure on terms acceptable to the Company, its creditors, or at all.

Financial Condition and Cash Flows for the three months ended March 31, 2018 and 2017

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

Net cash provided by operating activities during the first three months of 2018 increased $15.7 million as compared to the same period in 2017. This was primarily due to increases in accounts payable, partially offset by interest expense accruals and write-offs.

Net cash used in investing activities during the first three months of 2018 increased $45.1 million as compared to the same period in 2017. This was primarily due to capital development expenditures in the first three months of 2018 of approximately $62.1 million, which was $36.6 million higher than in the same period of 2017, coupled with a decrease in joint venture capital reimbursements of approximately $8.1 million as compared to the same period in 2017.

Net cash provided by financing activities during the first three months of 2018 increased by approximately $37.8 million from net cash used in financing activities during the same period in 2017, primarily due to borrowings made on our Term Loan.

As market conditions warrant and subject to our contractual restrictions in the Term Loan, our Indentures 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 outstanding equity securities or outstanding debt, including our Senior Notes, by tender offer, exchange or otherwise. The amounts involved in any such transaction, individually or in the aggregate, may be material.

Our results of operations and cash flows are affected by changing natural gas, NGL and oil prices. If the price of natural gas, NGLs and oil 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.

During the quarter ended March 31, 2018, 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, 2017. We describe critical recently adopted and issued accounting standards in Part I, Item 1. Financial Statements—Note 5, “Recently Issued Accounting Pronouncements.”

“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.

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

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 natural gas, NGLs and oil. 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, 2018, we paid net settlements on natural gas, NGL and oil derivatives of approximately $1.2 million, as compared to paying net settlements of approximately $3.4 million for the same period in 2017. These gains and losses are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.

Our primary sources of production and revenue are located in the Appalachian Basin. Natural gas prices in the Appalachian Basin are exposed to regional basis differentials when compared to NYMEX pricing. During the three months ended March 31, 2018, our average realized prices for natural gas were lower than the average NYMEX prices over the same period by approximately $0.32 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 Dominion South basis swaps in place for 10,625 MMcf at an average differential to Henry Hub NYMEX of $0.82 per Mcf for the remainder of 2018 in addition to Dominion South basis swaps for 12,775 MMcf at an average differential to Henry Hub NYMEX of $0.84 per Mcf for 2019. For the three months ended March 31, 2018, we paid cash settlements on our basis differential derivatives of approximately $0.8 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 have entered into the majority of our derivatives transactions with two 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 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 natural gas, NGL and oil derivative positions at March 31, 2018, refer to Part I, Item 1. Financial Statements - Note 8, “Derivative Instruments and Fair Value Measurements”.

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, 2017, there have been no material changes to our contractual obligations, other than an increase in long-term debt due to our borrowings our Term Loan. See Part I, Item 1. Financial Statements—Note 7, “Long-Term Debt” for additional information on the Senior Credit Facility and Term Loan.

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, 2018, we project that a 10% decline in the price per barrel of NGLs and oil and the price per Mcf of gas from the first three months of 2018 average would reduce our gross revenues, before the effects of derivatives, for the remaining nine months of 2018 by approximately $19.5 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.

At March 31, 2018, we had the following commodity derivative contracts outstanding:

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2018 - Swaps		139,250	Bbls	$	—	$	—	$	—	$	57.55		$	(811	)
2018 - Collars		9,000	Bbls		—		53.00		60.00		—			(47	)
2018 - Three-Way Collars		57,000	Bbls		42.11		51.32		61.14		—			(222	)
2019 - Swaps		53,500	Bbls		—		—		—		49.04			(425	)
2019 - Collars		60,250	Bbls		—		45.00		55.07		—			(161	)
2019 - Three-Way Collars		51,000	Bbls		38.82		48.82		58.31		—			(201	)
2020 - Swaps		24,000	Bbls		—		—		—		50.63			(146	)
2020 - Collars		71,750	Bbls				45.00		55.10					(215	)
2020 - Three-Way Collars		33,725	Bbls		39.39		49.39		57.04		—			(116	)
2021 - Swaps		15,000	Bbls		—		—		—		50.40			(36	)
2021 - Collars		63,750	Bbls		—		45.00		55.02		—			(197	)
2021 - Three-Way Collars		13,250	Bbls		39.10		49.10		60.41		—			(45	)
2022 - Swaps		6,750	Bbls		—		—		—		50.00			—
2022 - Collars		36,000	Bbls		—		45.00		54.75		—			(107	)
2022 - Three-Way Collars		5,500	Bbls		40.00		50.00		60.50		—			(11	)
		639,725	Bbls										$	(2,740	)
Natural Gas
2018 - Swaps		18,342,500	Mcf		—		—		—		2.98		$	2,400
2018 - Three-Way Collars		7,600,000	Mcf		2.33		2.89		3.49		—			1,124
2018 - Calls		4,370,000	Mcf		—		—		3.97		—			(38	)
2018 - Collars		3,965,000	Mcf		—		2.60		3.04		—			(153	)
2018 - Basis Swaps - Dominion South		10,625,000	Mcf		—		—		—		(0.82	)		(2,056	)
2018 - Basis Swaps - Texas Gas		11,000,000	Mcf		—		—		—		(0.13	)		448
2019 - Swaps		11,620,000	Mcf		—		—		—		2.84			255
2019 - Three-Way Collars		11,250,000	Mcf		2.29		2.76		3.34		—			282
2019 - Collars		9,051,750	Mcf		—		2.56		3.04		—			(270	)
2019 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.84	)		(2,721	)
2020 - Swaps		5,542,500	Mcf		—		—		—		2.88			135
2020 - Three-Way Collars		7,680,000	Mcf		2.27		2.73		3.24		—			279
2020 - Collars		6,760,000	Mcf		—		2.56		3.04		—			(153	)
2020 - Basis Swaps - Dominion South		7,320,000	Mcf		—		—		—		(0.84	)		(1,519	)
2021 - Swaps		3,875,000	Mcf		—		—		—		2.77			(5	)
2021 - Three-Way Collars		4,083,750	Mcf		2.21		2.68		3.13		—			66
2021 - Collars		3,530,000	Mcf		—		2.53		3.05		—			(77	)
2021 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(273	)
2022 - Swaps		2,730,000	Mcf		—		—		—		2.73			(42	)
2022 - Three-Way Collars		2,047,500	Mcf		2.15		2.65		3.10		—			21
2022 - Collars		2,195,000	Mcf		—		2.51		3.05		—			(52	)
2022 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(273	)
2023 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(273	)
2024 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(273	)
		160,963,000	Mcf										$	(3,168	)
NGLs
2018 - C3+ NGL Swaps		1,137,405	Bbls		—		—		—		34.05		$	(5,540	)
2018 - Ethane Swaps		1,302,000	Bbls		—		—		—		12.22			750
2019 - C3+ NGL Swaps		957,943	Bbls		—		—		—		29.98			(1,883	)
2019 - C5 Collars		113,040	Bbls		—		45.00		54.83		—			(495	)
2019 - Ethane Swaps		1,317,750	Bbls		—		—		—		12.61			805
2019 - C5 Three-Way Collars		7,536	Bbls		—		32.31		50.00		55.75			(24	)
2020 - C3+ NGL Swaps		347,689	Bbls		—		—		—		30.40			(996	)
2020 - C5 Collars		28,260	Bbls		—		45.00		54.83		—			(124	)
2020 - Ethane Swaps		1,150,750	Bbls		—		—		—		12.37			113
2020 - C5 Three-Way Collars		41,225	Bbls		—		34.87		49.94		57.36			(82	)
2021 - C3+ NGL Swap		210,206	Bbls		—		—		—		31.62			(402	)
2021 - Ethane Swaps		805,000	Bbls		—		—		—		12.32			93
2021 - C5 Three-Way Collars		63,398	Bbls		—		38.99		48.99		60.40			(37	)
2022 - C3+ NGL Swap		62,966	Bbls		—		—		—		32.60			(114	)
2022 - Ethane Swaps		379,250	Bbls		—		—		—		12.31			52
2022 - C5 Three-Way Collars		22,460	Bbls		—		39.11		49.11		60.41			(9	)
		7,946,878	Bbls										$	(7,893	)

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, 2018, 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, 2017. Based on our total debt as of March 31, 2018, of approximately $879.8 million, a 1.0% change in interest rates would impact our interest expense by approximately $8.8 million.

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, 2018, 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 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.

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, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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.

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 , 2018, 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, 2017.

As of the date of this report, the Company is six quarters in arrears with respect to the payment of dividends on its Preferred Stock. As of the date of this report, accumulated dividends in arrears totaled approximately $3.6 million.

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.

			PAGE
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements	5
		Consolidated Balance Sheets as of March 31. 2018 (Unaudited) and December 31, 2017	5
		Consolidated Statements of Operations (Unaudited) for the three-month periods ended March 31, 2018 and March 31, 2017	6
		Consolidated Statement of Changes in Stockholders’ Equity (Unaudited) for the three-month period ended March 31, 2018	7
		Consolidated Statements of Cash Flows (Unaudited) for the three-month periods ended March 31, 2018 and March 31, 2017	8
		Notes to Consolidated Financial Statements (Unaudited)	9
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	40
	Item 3.	Quantitative and Qualitative Disclosure About Market Risk	52
	Item 4.	Controls and Procedures	54
PART II. OTHER INFORMATION			55
	Item 1.	Legal Proceedings	55
	Item 1A.	Risk Factors	55
	Item 6.	Exhibits	56
SIGNATURES			57

($ in Thousands)	March 31, 2018
Beginning Balance at January 1, 2018	$	9,939
Future Abandonment Obligation Incurred	$	1
Future Abandonment Obligation Settled	$	(100	)
Future Abandonment Obligation Cancelled or Sold	$	(878	)
Future Abandonment Obligation Revision of Estimated Obligation	$	99
Future Abandonment Obligation Accretion Expense	$	257
Total Future Abandonment Cost¹	$	9,318

	Three Months Ended March 31,
($ in Thousands)	2018		2017
Revenues from Contracts with Customers by Product
Natural Gas	$	28,576	$	29,633
NGLs		28,704		17,761
Condensate		6,612		3,409
Total	$	63,892	$	50,803

2018(a)	$	822,833
2019		2,341
2020		2,739
2021		2,582
2022		861
Thereafter		—
Total (b)	$	831,356

	Common Stock					Preferred Stock
	Shares			Par Value		Shares		Par Value		Additional Paid- In Capital		Accumulated Deficit			Total Stockholders’ Equity
BALANCE December 31, 2017		10,244		$	10		4	$	1	$	652,917	$	(706,490	)	$	(53,562	)
Equity Based Compensation		—			—		—		—		1,019		—			1,019
Issuance of Restricted Stock, Net of Forfeitures		(27	)		—		—		—		—		—			—
Preferred Dividends in Arrears Paid in Common Shares		491			1		—		—		598		(598	)		1
Net Loss		—			—		—		—		—		(69,793	)		(69,793	)
BALANCE March 31, 2018		10,708		$	11		4	$	1	$	654,534	$	(776,881	)	$	(122,335	)

				Fair Value Measurements at March 31, 2018
($ in Thousands)	Total Carrying Value as of March 31, 2018			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(11,670	)	$	—	$	(11,670	)	$	—
Embedded Derivatives	$	(52,965	)	$	—	$	(52,965	)	$	—

				Fair Value Measurements at December 31, 2017
($ in Thousands)	Total Carrying Value as of December 31, 2017			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(19,414	)	$	—	$	(19,414	)	$	—

		Outstanding				Exercisable
Exercise Price		Number Outstanding at March 31, 2018		Weighted-Average Exercise Price		Number Exercisable at March 31, 2018		Weighted-Average Exercise Price
	9.70		2,750	$	9.70		919	$	9.70
	16.90		60,327	$	16.90		41,276	$	16.90
	49.00		4,000	$	49.00		4,000	$	49.00
	50.40		3,070	$	50.40		3,070	$	50.40
	104.20		2,217	$	104.20		2,217	$	104.20
	223.40		3,000	$	223.40		3,000	$	223.40
			75,364	$	30.49		54,482	$	35.95

	Three Months Ended March 31, 2018	Year Ended December 31, 2017
Expected Dividend Yield	0.0%		0.0	%
Risk-Free Interest Rate	1.0%		1.0	%
Expected Volatility – Rex Energy	58.6%		58.6	%
Expected Volatility – Peer Group	29.8%-85.0%	29.8%-85.0%
Market Index	35.6%		35.6	%
Expected Life	Three Years	Three Years

	Number of Shares			Weighted-Average Grant Date Fair Value
Restricted stock awards, as of December 31, 2017		200,475		$	13.62
Awards		—			—
Forfeitures		(27,318	)		15.24
Vested		(56,335	)		24.65
Restricted stock awards, as of March 31, 2018	$	116,822		$	7.92

($ in Thousands)
2018	$	37,992
2019		50,875
2020		49,522
2021		46,551
2022		46,090
Thereafter		461,109
Total	$	692,139

Calendar Quarter Ending	West Texas Intermediate ("WTI") Average Price per Bbl (a)
6/30/2018	$	61.75
9/30/2018	$	62.25
12/31/2018	$	62.75
3/31/2019	$	63.25
6/30/2019	$	63.75

(in thousands, except per share amounts)	Three Months Ended March 31,
Numerator:	2018			2017
Net Income (Loss)	$	(69,793	)	$	2,683
Less: Preferred Stock Dividends		(598	)		(598	)
Net Income (Loss) Attributable to Common Shareholders	$	(70,391	)	$	2,085
Denominator:
Weighted Average Common Shares Outstanding - Basic		10,464			9,769
Effect of Dilutive Securities:
Employee Stock Options		—			—
Employee Performance-Based Restricted Stock Awards		—			—
Effect of Assumed Conversions of Preferred Stock		—			—
Weighted Average Common Shares Outstanding - Diluted		10,464			9,769
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Net Income (Loss) Attributable to Common Shareholders	$	(6.73	)	$	0.21
Diluted — Net Income (Loss) Attributable to Common Shareholders	$	(6.73	)	$	0.21

	Production and Revenue by Product
	For the Three Months Ended March 31,
	2018		2017
Revenue – Natural Gas(a)	$	29,681,765	$	31,344,632
Volumes (Mcf)		11,015,233		9,911,742
Average Price	$	2.69	$	3.16
Revenue – Condensate (a)	$	6,624,660	$	3,420,173
Volumes (Bbl)		115,883		74,240
Average Price	$	57.17	$	46.07
Revenue – C3+ NGLs(a)	$	20,502,363	$	13,007,428
Volumes (Bbl)		547,508		421,705
Average Price	$	37.45	$	30.84
Revenue – Ethane(a)	$	8,216,291	$	4,293,001
Volumes (Bbl)		812,694		452,687
Average Price	$	10.11	$	9.48
Average Production Cost per Mcfe(b)	$	1.61	$	1.85

	For the Three Months Ended March 31,
($ in Thousands, except total Mcfe production and price per Mcfe)	2018			2017			Change			%
Gas sales revenue	$	29,682		$	31,345		$	(1,663	)		(5.3	)%
Gas derivatives realized(a)	$	730		$	(1,172	)	$	1,902			(162.3	)%
Total gas revenue and derivatives realized	$	30,412		$	30,173		$	239			0.8	%
Condensate sales revenue	$	6,625		$	3,420		$	3,205			93.7	%
Oil and condensate derivatives realized(a)	$	(463	)	$	5		$	(468	)		(9,360.0	)%
Total condensate revenue and derivatives realized	$	6,162		$	3,425		$	2,737			79.9	%
C3+ NGL revenue	$	20,502		$	13,007		$	7,495			57.6	%
C3+ NGL derivatives realized(a)	$	(2,934	)	$	(2,384	)	$	(550	)		23.1	%
Total C3+ NGL revenue	$	17,568		$	10,623		$	6,945			65.4	%
Ethane revenue	$	8,216		$	4,293		$	3,923			91.4	%
Ethane derivatives realized(a)	$	658		$	108		$	550			509.3	%
Total Ethane revenue	$	8,874		$	4,401		$	4,473			101.6	%
Consolidated sales	$	65,025		$	52,065		$	12,960			24.9	%
Consolidated derivatives realized(a)	$	(2,009	)	$	(3,443	)	$	1,434			(41.6	)%
Total NGL, condensate and gas revenue and derivatives realized	$	63,016		$	48,622		$	14,394			29.6	%
Total Mcfe Production		19,871,743			15,603,534			4,268,209			27.4	%
Average Realized Price per Mcfe	$	3.17		$	3.12		$	0.05			1.6	%

	Other Performance Measurements
	For the Three Months Ended March 31,
	2018		2017
EBITDAX from Continuing Operations ($ in Thousands) (a)	$	24,524	$	15,577
LOE per Mcfe	$	1.70	$	1.85
G&A per Mcfe	$	0.33	$	0.29

	REX ENERGY CORPORATION (Registrant)
Date: May 15, 2018	By:	/s/ Thomas C. Stabley
		Thomas C. Stabley
		Chief Executive Officer (Principal Executive Officer)