Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2018 | May 10, 2018 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Mar. 31, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q1 | |
Trading Symbol | REXX | |
Entity Registrant Name | REX ENERGY CORP | |
Entity Central Index Key | 1,397,516 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Smaller Reporting Company | |
Entity Common Stock, Shares Outstanding | 10,708,287 |
Consolidated Balance Sheets (Un
Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
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 |
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 |
Noncurrent Liabilities | ||
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 | 1 | 1 |
Common Stock | 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 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) (Unaudited) - $ / shares | Mar. 31, 2018 | Dec. 31, 2017 |
Statement Of Financial Position [Abstract] | ||
Preferred Stock, par value | $ 0.001 | $ 0.001 |
Preferred Stock, shares authorized | 100,000 | 100,000 |
Preferred Stock, shares issued | 3,987 | 3,987 |
Preferred Stock, shares outstanding | 3,987 | 3,987 |
Common Stock, par value | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common Stock, shares issued | 10,708,287 | 10,244,394 |
Common Stock, shares outstanding | 10,708,287 | 10,244,394 |
Consolidated Statements of Oper
Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
OPERATING REVENUE | ||
Natural Gas, NGL and Condensate Sales | $ 65,025 | $ 52,065 |
Other Operating Revenue | 4 | 6 |
TOTAL OPERATING REVENUE | 65,029 | 52,071 |
OPERATING EXPENSES | ||
Production and Lease Operating Expense | 33,846 | 28,934 |
General and Administrative Expense | 6,525 | 4,534 |
Loss (Gain) on Disposal of Assets | 647 | (1,834) |
Impairment Expense | 8,168 | 1,546 |
Exploration Expense | 228 | 220 |
Depreciation, Depletion, Amortization and Accretion | 15,128 | 15,468 |
Other Operating (Income) Expense | 203 | (21) |
TOTAL OPERATING EXPENSES | 64,745 | 48,847 |
INCOME FROM OPERATIONS | 284 | 3,224 |
OTHER INCOME (EXPENSE) | ||
Interest Expense | (22,647) | (9,143) |
(Loss) Gain on Derivatives, Net | (46,426) | 8,381 |
Other Expense | (1,004) | (28) |
Gain on Extinguishments of Debt | 249 | |
TOTAL OTHER EXPENSE | (70,077) | (541) |
INCOME (LOSS) BEFORE INCOME TAX | (69,793) | 2,683 |
Income Tax Benefit | 0 | 0 |
NET (LOSS) INCOME | (69,793) | 2,683 |
Preferred Stock Dividends | (598) | (598) |
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ (70,391) | $ 2,085 |
Earnings per common share: | ||
Basic - Net (Loss) Income Attributable to Rex Energy Common Shareholders | $ (6.73) | $ 0.21 |
Basic - Weighted Average Shares of Common Stock Outstanding | 10,464 | 9,769 |
Diluted - Net Income (Loss) Attributable to Rex Energy Common Shareholders | $ (6.73) | $ 0.21 |
Diluted - Weighted Average Shares of Common Stock Outstanding | 10,464 | 9,769 |
Consolidated Statement of Chang
Consolidated Statement of Changes in Stockholders' Equity (Unaudited) - 3 months ended Mar. 31, 2018 - USD ($) shares in Thousands, $ in Thousands | Total | Common Stock | Preferred Stock | Additional Paid-in Capital | Accumulated Deficit |
Balance at Dec. 31, 2017 | $ (53,562) | $ 10 | $ 1 | $ 652,917 | $ (706,490) |
Balance (in shares) at Dec. 31, 2017 | 10,244 | 4 | |||
Equity Based Compensation | 1,019 | 1,019 | |||
Issuance of Restricted Stock, Net of Forfeitures (in shares) | (27) | ||||
Preferred Dividends in Arrears Paid in Common Shares | 1 | $ 1 | 598 | (598) | |
Preferred Dividends in Arrears Paid in Common Shares (in shares) | 491 | ||||
Net Loss | (69,793) | (69,793) | |||
Balance at Mar. 31, 2018 | $ (122,335) | $ 11 | $ 1 | $ 654,534 | $ (776,881) |
Balance (in shares) at Mar. 31, 2018 | 10,708 | 4 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 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 | ||
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 | |
Illinois Basin Operations | ||
NON-CASH ACTIVITIES | ||
Change in fair value of contingent consideration receivable - sale of Illinois Basin | $ (1,417) |
Basis of Presentation and Princ
Basis of Presentation and Principles of Consolidation | 3 Months Ended |
Mar. 31, 2018 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Basis of Presentation and Principles of Consolidation | 1. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION 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 Long-Term Debt 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. 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. Reverse Stock Split 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 Cost
Future Abandonment Cost | 3 Months Ended |
Mar. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Future Abandonment Cost | 2. FUTURE ABANDONMENT COST Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the 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 $0.6 million for the three months ended March 31, 2018 and 2017, respectively. These amounts are recorded as depreciation, depletion, amortization and accretion (“DD&A”) expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells. ($ 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 Cost 1 $ 9,318 1 |
Revenue Recognition
Revenue Recognition | 3 Months Ended |
Mar. 31, 2018 | |
Revenue From Contract With Customer [Abstract] | |
Revenue Recognition | 3. REVENUE RECOGNITION 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. Revenues Sources and Sales Cycle 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. Revenue Recognition – Contracts with Customers 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. Pricing of Commodity Sales 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. Production Imbalances 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. Contract Balances 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. Performance Obligations 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 $21.7 million, respectively. The following table summarizes our disaggregated revenues recognized from contracts with customers in our Consolidated Statements of Operations for the three month periods ended March 31, 2018 and 2017. Three Months Ended March 31, ($ 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 |
Business and Oil and Gas Proper
Business and Oil and Gas Property Acquisitions and Dispositions | 3 Months Ended |
Mar. 31, 2018 | |
Business Combinations [Abstract] | |
Business and Oil and Gas Property Dispositions | 4. BUSINESS AND OIL AND GAS PROPERTY DISPOSITIONS Benefit Street Partners, LLC On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP 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. Sale of Warrior South Assets 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. Sale of Westmoreland Assets 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. |
Recently Issued Accounting Pron
Recently Issued Accounting Pronouncements | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Recently Issued Accounting Pronouncements | 5. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In May 2014, the Financial Accounting Standards Board (the “FASB”) issued ASU 2014-09, Revenue from Contracts with Customers Revenue Recognition 1) Identify the contract(s) with a customer. 2) Identify the performance obligations in the contract. 3) Determine the transaction price. 4) Allocate the transaction price to the performance obligations in the contract. 5) Recognize revenue when (or as) the entity satisfies a performance obligation. 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 • A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and • A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. 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 • debt prepayment or debt extinguishment costs; • settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing; • contingent consideration payments made after a business combination; • proceeds from the settlement of insurance claims; • proceeds from the settlement of corporate-owned life insurance policies; • distributions received from equity method investees; • beneficial interest in securitization transactions; and • separately identifiable cash flows and application of the Predominance Principle. 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 |
Concentrations of Credit Risk
Concentrations of Credit Risk | 3 Months Ended |
Mar. 31, 2018 | |
Risks And Uncertainties [Abstract] | |
Concentrations of Credit Risk | 6. CONCENTRATIONS OF CREDIT RISK By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparties to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions (see Note 7, Long-Term Debt Derivative Instruments and Fair Value Measurements 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. |
Long-Term Debt
Long-Term Debt | 3 Months Ended |
Mar. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | 7. LONG-TERM DEBT Term Loan 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. 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 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 Subsequent Events 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. Senior Notes On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our new 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 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 Subsequent Events 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 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. 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 March 31, 2018 Principal Deferred Gain on Debt Restructurings, Net Net Carrying Value Term Loans, Net Term Loan Draw - due April 2020 $ 221,000 $ — $ 221,000 Senior Notes, Net 8.875% Senior Notes due 2020 $ 7,333 $ — $ 7,333 6.25% Senior Notes due 2022 5,363 — $ 5,363 1% / 8% Second Lien Senior Notes due 2020 587,606 45,813 $ 633,419 $ 600,302 $ 45,813 $ 646,115 Other Long-Term Debt Long-Term Capital Leases - Equipment Financing Due March, 2021 $ 596 Due June, 2021 1,337 Due September, 2021 1,505 Due May, 2022 6,616 Total Capital Lease Obligations $ 10,054 Less: Current Portion of Capital Leases (2,082 ) $ 7,972 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: 2018(a) $ 822,833 2019 2,341 2020 2,739 2021 2,582 2022 861 Thereafter — Total (b) $ 831,356 (a) Due to existing and anticipated covenant violations, the Company’s Term Loan and Senior Notes were classified as current as December 31, 2017. (b) Excludes $45.8 million of Deferred Gain on Debt Restructurings, Net. |
Derivative Instruments And Fair
Derivative Instruments And Fair Value Measurements | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Of Financial Instruments And Derivative Instruments [Abstract] | |
Derivative Instruments And Fair Value Measurements | 8. DERIVATIVE INSTRUMENTS AND FAIR VALUE MEASUREMENTS Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of March 31, 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, 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 Embedded Derivatives – Yield Maintenance and Call Protection 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. Contingent Consideration – Sale of Illinois Basin Operations 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 $0.8 million is included in Accounts Receivable on our Consolidated Balance Sheets as of March 31, 2018. Derivative Instruments The following table summarizes the location and amounts of gains and losses on our derivative instruments, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three months ended March 31, 2018: For the Three Months Ended March 31, ($ in Thousands) 2018 2017 Oil $ (1,735 ) $ 1,137 Natural Gas 3,392 (59 ) NGLs 3,669 8,720 Contingent Consideration 1,214 (1,417 ) Embedded Derivatives (52,965 ) — (Loss) Gain on Derivatives, Net $ (46,426 ) $ 8,381 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: 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 ) $ — 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. Future Abandonment Cost We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Future Abandonment Costs, Financial Instruments Not Recorded at Fair Value The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: March 31, 2018 December 31, 2017 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 646,115 $ 214,080 $ 650,371 $ 264,438 Term Loan 221,000 208,790 182,028 182,028 Capital Leases and Other Obligations 10,054 7,271 10,082 7,138 Total $ 877,169 $ 430,141 $ 842,481 $ 453,604 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. Other Fair Value Measurements During the three months ended March 31, 2018 and 2017, we recorded other than temporary impairments of $8.2 million and $1.5 million, respectively, related to proven and unproved properties. We primarily use proved reserve reports in our determination of impairment of proved properties. These proved reserve reports are generated with inputs that are primarily established internally with the use of internally developed engineering estimates and methodologies. The inputs used in determining fair value as a part of the impairment expense calculation are considered to be Level 3 within the fair value hierarchy. Impairment considerations for unproved properties include future development plans for the leases, remaining months on the lease’s primary term, and market value for similar acreage in the area. For additional information on our impairment expense, see Note 15, Impairment Expense |
Income Taxes
Income Taxes | 3 Months Ended |
Mar. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 9. INCOME TAXES We recognize deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. Income tax included in continuing operations was as follows: Three Months Ended March 31, ($ in Thousands) 2018 2017 Income Tax Benefit (Expense) $ — $ — Effective Tax Rate 0.0 % 0.0 % 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. |
Capital Stock
Capital Stock | 3 Months Ended |
Mar. 31, 2018 | |
Equity [Abstract] | |
Capital Stock | 10. CAPITAL STOCK Reverse Stock Split 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. Common Stock 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 Preferred Stock 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. |
Employee Benefit and Equity Pla
Employee Benefit and Equity Plans | 3 Months Ended |
Mar. 31, 2018 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Employee Benefit and Equity Plans | 11. EMPLOYEE BENEFIT AND EQUITY PLANS Equity Plans We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals one vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as cash flows from financing activities, rather than as cash flows from operating activities. Stock Options During the three 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: 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 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. Restricted Stock Awards 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: 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 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: 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 |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2018 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 12. COMMITMENTS AND CONTINGENCIES Legal Reserves We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations. The accrual of reserves for legal matters is included in Accrued Liabilities on our Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred. 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. Environmental Due to the nature of the oil and natural gas business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews of our policies and properties to identify changes in the environmental risk profile. In these reviews we evaluate whether there is a probable liability, its amount and the likelihood that the liability will be incurred. The amount of any potential 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. Letters of Credit As of March 31, 2018, we have posted $32.0 million in various letters of credit to secure our drilling and related operations. Lease Commitments 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 $0.2 million, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2018 $ 740 2019 899 2020 796 2021 475 2022 485 Thereafter — Total $ 3,395 Capacity Reservation We have a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest in Butler County, Pennsylvania to process our produced natural gas. In the event that we do not 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. Water Supply Commitments 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. Operational Commitments 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. Natural Gas Gathering, Processing and Sales Agreements During the normal course of business, we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our 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 $0.7 million, respectively. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) 2018 $ 37,992 2019 50,875 2020 49,522 2021 46,551 2022 46,090 Thereafter 461,109 Total $ 692,139 Illinois Basin Oil Contingency 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 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 Pennsylvania Impact Fee 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. |
Earnings Per Common Share
Earnings Per Common Share | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
Earnings Per Common Share | 13. EARNINGS PER COMMON SHARE 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 (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 |
Equity Method Investments
Equity Method Investments | 3 Months Ended |
Mar. 31, 2018 | |
Equity Method Investments And Joint Ventures [Abstract] | |
Equity Method Investments | 14. EQUITY METHOD INVESTMENTS RW Gathering, LLC 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”). Fo r additional information regarding the Westmoreland Sale, see Note 4, Business and Oil and Gas Property Dispositions 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. |
Impairment Expense
Impairment Expense | 3 Months Ended |
Mar. 31, 2018 | |
Impairment Of Oil And Gas Properties [Abstract] | |
Impairment Expense | 15. IMPAIRMENT EXPENSE 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 |
Exploration Expense
Exploration Expense | 3 Months Ended |
Mar. 31, 2018 | |
Extractive Industries [Abstract] | |
Exploration Expense | 16. EXPLORATION EXPENSE 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. |
Condensed Consolidating Financi
Condensed Consolidating Financial Information | 3 Months Ended |
Mar. 31, 2018 | |
Condensed Financial Information Of Parent Company Only Disclosure [Abstract] | |
Condensed Consolidating Financial Information | 17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION As of March 31, 2018, we had $600.3 million aggregate principal amount of outstanding Senior Notes, as shown in Note 7, Long-Term Debt • Rex Energy I, LLC; • Rex Energy Operating Corporation; • Rex Energy IV, LLC; • PennTex Resources Illinois, Inc.; and • R.E. Gas Development, LLC. The non-guarantor subsidiaries include certain consolidated subsidiaries, including R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of March 31, 2018, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries. The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of March 31, 2018 and December 31, 2017, the condensed consolidating statements of operations for the three months ended March 31, 2018 and 2017, and the condensed consolidating statements of cash flows for the three months ended March 31, 2018 and 2017. REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF MARCH 31, 2018 ($ in Thousands) 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 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2018 ($ in Thousands) 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 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2018 ($ in Thousands) 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 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF DECEMBER 31, 2017 ($ in Thousands) 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 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2017 ($ in Thousands) 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 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2017 ($ in Thousands) 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 |
Subsequent Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | 18. SUBSEQUENT EVENTS Forbearance Agreements 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. Second Lien Notes Interest Payment 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. Nasdaq Delisting 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. |
Recently Issued Accounting Pr25
Recently Issued Accounting Pronouncements (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Recently Issued Accounting Pronouncements | In May 2014, the Financial Accounting Standards Board (the “FASB”) issued ASU 2014-09, Revenue from Contracts with Customers Revenue Recognition 1) Identify the contract(s) with a customer. 2) Identify the performance obligations in the contract. 3) Determine the transaction price. 4) Allocate the transaction price to the performance obligations in the contract. 5) Recognize revenue when (or as) the entity satisfies a performance obligation. 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 • A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and • A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. 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 • debt prepayment or debt extinguishment costs; • settlement of zero-coupon debt instruments or other instruments with coupon rates that are insignificant in relation to the effective interest rate of borrowing; • contingent consideration payments made after a business combination; • proceeds from the settlement of insurance claims; • proceeds from the settlement of corporate-owned life insurance policies; • distributions received from equity method investees; • beneficial interest in securitization transactions; and • separately identifiable cash flows and application of the Predominance Principle. 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 |
Future Abandonment Cost (Tables
Future Abandonment Cost (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Future Abandonment Costs | We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells. ($ 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 Cost 1 $ 9,318 1 |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Revenue From Contract With Customer [Abstract] | |
Summary of Disaggregated Revenues Recognized from Contracts with Customers in Consolidated Statements of Operations | 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. 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 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Debt Disclosure [Abstract] | |
Components of Long-Term Debt and Lines of Credit | March 31, 2018 Principal Deferred Gain on Debt Restructurings, Net Net Carrying Value Term Loans, Net Term Loan Draw - due April 2020 $ 221,000 $ — $ 221,000 Senior Notes, Net 8.875% Senior Notes due 2020 $ 7,333 $ — $ 7,333 6.25% Senior Notes due 2022 5,363 — $ 5,363 1% / 8% Second Lien Senior Notes due 2020 587,606 45,813 $ 633,419 $ 600,302 $ 45,813 $ 646,115 Other Long-Term Debt Long-Term Capital Leases - Equipment Financing Due March, 2021 $ 596 Due June, 2021 1,337 Due September, 2021 1,505 Due May, 2022 6,616 Total Capital Lease Obligations $ 10,054 Less: Current Portion of Capital Leases (2,082 ) $ 7,972 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 |
Principal Maturity Schedule for Debt Outstanding | The following is the principal maturity schedule for debt outstanding as of March 31, 2018: 2018(a) $ 822,833 2019 2,341 2020 2,739 2021 2,582 2022 861 Thereafter — Total (b) $ 831,356 (a) Due to existing and anticipated covenant violations, the Company’s Term Loan and Senior Notes were classified as current as December 31, 2017. (b) Excludes $45.8 million of Deferred Gain on Debt Restructurings, Net. |
Derivative Instruments And Fa29
Derivative Instruments And Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Of Financial Instruments And Derivative Instruments [Abstract] | |
Schedule of Location and Amounts of Gains and Losses on Derivative Instruments | Derivative Instruments The following table summarizes the location and amounts of gains and losses on our derivative instruments, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three months ended March 31, 2018: For the Three Months Ended March 31, ($ in Thousands) 2018 2017 Oil $ (1,735 ) $ 1,137 Natural Gas 3,392 (59 ) NGLs 3,669 8,720 Contingent Consideration 1,214 (1,417 ) Embedded Derivatives (52,965 ) — (Loss) Gain on Derivatives, Net $ (46,426 ) $ 8,381 |
Asset or Liability Financial Commodity Derivative Instrument Positions | 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 ) |
Combined Fair Value of Derivatives | 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 Hierarchy Table for Assets and Liabilities Measured at Fair Value | The following table presents the fair value hierarchy table for assets and liabilities measured at fair value: 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 ) $ — |
Financial Instruments Not Recorded at Fair Value | The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements: March 31, 2018 December 31, 2017 ($ in Thousands) Carrying Amount Fair Value Carrying Amount Fair Value Senior Notes, Net of Issuance Costs $ 646,115 $ 214,080 $ 650,371 $ 264,438 Term Loan 221,000 208,790 182,028 182,028 Capital Leases and Other Obligations 10,054 7,271 10,082 7,138 Total $ 877,169 $ 430,141 $ 842,481 $ 453,604 |
Income Taxes (Tables)
Income Taxes (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of Income Tax Included in Continuing Operations | Income tax included in continuing operations was as follows: Three Months Ended March 31, ($ in Thousands) 2018 2017 Income Tax Benefit (Expense) $ — $ — Effective Tax Rate 0.0 % 0.0 % |
Employee Benefit And Equity P31
Employee Benefit And Equity Plans (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Summary of Issued and Outstanding Stock Options | A summary of the status of our issued and outstanding stock options as of March 31, 2018 is as follows: 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 |
Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock | 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: 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 |
Summary of Nonvested Restricted Stock Activity | A summary of the restricted stock activity for the three months ended March 31, 2018 is as follows: 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 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Commitments And Contingencies Disclosure [Abstract] | |
Lease Commitments for Each of Next Five Years | 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 $0.2 million, respectively. Lease commitments by year for each of the next five years are presented in the table below: ($ in Thousands) 2018 $ 740 2019 899 2020 796 2021 475 2022 485 Thereafter — Total $ 3,395 |
Minimum Net Obligations under Sales, Gathering and Transportation Agreements | Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows: ($ in Thousands) 2018 $ 37,992 2019 50,875 2020 49,522 2021 46,551 2022 46,090 Thereafter 461,109 Total $ 692,139 |
Average Spot Price | 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 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 |
Earnings Per Common Share (Tabl
Earnings Per Common Share (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
Computation of Basic and Diluted Earning Per Common Share | The following table sets forth the computation of basic and diluted earnings per common share: (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 |
Condensed Consolidating Finan34
Condensed Consolidating Financial Information (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Condensed Financial Information Of Parent Company Only Disclosure [Abstract] | |
Condensed Consolidating Balance Sheets | REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF MARCH 31, 2018 ($ in Thousands) 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 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS AS OF DECEMBER 31, 2017 ($ in Thousands) 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 |
Condensed Consolidating Statements of Operations | REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2018 ($ in Thousands) 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 ) REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2017 ($ in Thousands) 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 |
Condensed Consolidating Statements of Cash Flows | REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2018 ($ in Thousands) 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 REX ENERGY CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2017 ($ in Thousands) 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 |
Basis of Presentation and Pri35
Basis of Presentation and Principles of Consolidation - Additional Information (Details) $ in Millions | May 12, 2017shares | Mar. 31, 2018USD ($)shares | Dec. 31, 2017shares | Mar. 31, 2017shares |
Organization Consolidation And Presentation Of Financial Statements [Line Items] | ||||
Gain (loss) on derivative, net | $ (53) | |||
Reverse stock split | 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. | |||
Common Stock, shares issued | shares | 9,900,000 | 10,708,287 | 10,244,394 | 99,000,000 |
Common Stock | ||||
Organization Consolidation And Presentation Of Financial Statements [Line Items] | ||||
Reverse stock split | one-for-ten | |||
Stockholders' equity, reverse stock split ratio | 0.1 | |||
Term Loan | ||||
Organization Consolidation And Presentation Of Financial Statements [Line Items] | ||||
Short-term derivative instruments | $ 53 | |||
Total outstanding balance of term loan inclusive of yield maintenance, call protection, accrued interest and fees | $ 274 | |||
Second Lien Notes | ||||
Organization Consolidation And Presentation Of Financial Statements [Line Items] | ||||
Debt instrument, interest payment due date | Apr. 2, 2018 | |||
Grace period over maturity date | 30 days |
Future Abandonment Cost - Addit
Future Abandonment Cost - Additional Information (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Accretion expense | $ 257 | $ 600 |
Future Abandonment Cost (Detail
Future Abandonment Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2018 | Mar. 31, 2017 | ||
Asset Retirement Obligation Disclosure [Abstract] | |||
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 | $ 600 | |
Total Future Abandonment Cost | [1] | $ 9,318 | |
[1] | Includes approximately $1.0 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet. |
Future Abandonment Cost (Parent
Future Abandonment Cost (Parenthetical) (Details) $ in Millions | Mar. 31, 2018USD ($) |
Accrued Liablities | Remediation Property for Sale, Abandonment or Disposal | |
Asset Retirement Obligations [Line Items] | |
Short-term future abandonment costs | $ 1 |
Revenue Recognition - Additiona
Revenue Recognition - Additional Information (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Revenue From Contract With Customer [Abstract] | ||
Payment term | 30 to 60 days of control transfer | |
Trade receivable related revenue from contract with customers | $ 19.6 | $ 21.7 |
Revenue Recognition - Summary o
Revenue Recognition - Summary of Disaggregated Revenues Recognized from Contracts with Customers in Consolidated Statements of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Disaggregation Of Revenue [Line Items] | ||
Total Revenue | $ 63,892 | $ 50,803 |
Natural Gas | ||
Disaggregation Of Revenue [Line Items] | ||
Total Revenue | 28,576 | 29,633 |
NGL | ||
Disaggregation Of Revenue [Line Items] | ||
Total Revenue | 28,704 | 17,761 |
Condensate | ||
Disaggregation Of Revenue [Line Items] | ||
Total Revenue | $ 6,612 | $ 3,409 |
Business and Oil and Gas Prop41
Business and Oil and Gas Property Dispositions - Additional Information (Details) | Mar. 23, 2018USD ($) | Jan. 11, 2017USD ($)aMMcfeWell | Mar. 01, 2016Well | Jan. 31, 2017USD ($) | Mar. 31, 2018USD ($)Well | Mar. 31, 2017USD ($) | Mar. 21, 2018USD ($) | Mar. 13, 2018Well | Jan. 01, 2018 |
Business Acquisition And Dispositions [Line Items] | |||||||||
Proceeds held in Escrow - non-cash component of Gain on Sale of Assets | $ 150,000 | $ 5,000,000 | |||||||
Westmoreland, Centre and Clearfield Counties, PA | |||||||||
Business Acquisition And Dispositions [Line Items] | |||||||||
Number of non-operated oil and gas wells sold | Well | 61 | ||||||||
R W Gathering | |||||||||
Business Acquisition And Dispositions [Line Items] | |||||||||
Membership interest sold | 40.00% | ||||||||
Westmoreland Centre and Clearfield Counties, PA and RW Gathering | |||||||||
Business Acquisition And Dispositions [Line Items] | |||||||||
Total consideration for the transaction | $ 17,200,000 | ||||||||
Gain on disposal of assets | (600,000) | ||||||||
Proceeds received from the transactions | $ 16,400,000 | ||||||||
Proceeds held in Escrow - non-cash component of Gain on Sale of Assets | $ 200,000 | ||||||||
Sale of Warrior South Assets | |||||||||
Business Acquisition And Dispositions [Line Items] | |||||||||
Total consideration for the transaction | $ 29,100,000 | ||||||||
Net proceeds from sale of property | 24,100,000 | ||||||||
Amount held in escrow | $ 5,000,000 | ||||||||
Gain on disposal of assets | $ 1,800,000 | ||||||||
Number of gross wells | Well | 14 | ||||||||
Production unit of natural gas | MMcfe | 9 | ||||||||
Net acres sold | a | 4,100 | ||||||||
Sale of Warrior South Assets | Rex, MFC Drilling, Inc., and ABARTA Oil & Gas Co., Inc. | |||||||||
Business Acquisition And Dispositions [Line Items] | |||||||||
Total consideration for the transaction | $ 50,000,000 | ||||||||
Production unit of natural gas | MMcfe | 15 | ||||||||
Net acres sold | a | 6,200 | ||||||||
Benefit Street Partners Limited Liability Corporation | |||||||||
Business Acquisition And Dispositions [Line Items] | |||||||||
Amount received for working interest in wells by partners | $ 134,000,000 | ||||||||
Number of wells in which BSP Options to Participate in development | Well | 36 | ||||||||
Percentage of working interest | 65.00% | ||||||||
Number of wells in which BSP Options exercised to Participate in development | Well | 23 | ||||||||
Number of wells committed for line and producing | Well | 45 | ||||||||
Payments for interest in wells that have been drilled or in process of being drilled | $ 0 | ||||||||
Benefit Street Partners Limited Liability Corporation | Maximum | |||||||||
Business Acquisition And Dispositions [Line Items] | |||||||||
Total consideration for the transaction | $ 175,000,000 | ||||||||
Percentage of working interest earned in acreage | 20.00% | ||||||||
Benefit Street Partners Limited Liability Corporation | Minimum | |||||||||
Business Acquisition And Dispositions [Line Items] | |||||||||
Percentage of working interest earned in acreage | 15.00% | ||||||||
Benefit Street Partners Limited Liability Corporation | Moraine East and Warrior North | |||||||||
Business Acquisition And Dispositions [Line Items] | |||||||||
Number of specifically designated wells for development | Well | 58 | ||||||||
Benefit Street Partners Limited Liability Corporation | Butler County, Pennsylvania | |||||||||
Business Acquisition And Dispositions [Line Items] | |||||||||
Number of specifically designated wells for development | Well | 16 | ||||||||
Percentage of estimated well costs | 15.00% | ||||||||
Number of drilled and completed wells to be placed into service | Well | 16 | ||||||||
Benefit Street Partners Limited Liability Corporation | Warrior North Ohio | |||||||||
Business Acquisition And Dispositions [Line Items] | |||||||||
Number of specifically designated wells for development | Well | 6 | ||||||||
Percentage of estimated well costs | 65.00% | ||||||||
Number of drilled and completed wells to be placed into service | Well | 6 |
Concentrations of Credit Risk -
Concentrations of Credit Risk - Additional Information (Details) - Sales - Customer Concentration Risk | 3 Months Ended |
Mar. 31, 2018Customer | |
Purchaser | |
Concentration Risk [Line Items] | |
Percentage of revenue from major customers | 97.80% |
Number of major customers | 5 |
Largest single purchaser | |
Concentration Risk [Line Items] | |
Percentage of revenue from major customers | 60.10% |
Long-Term Debt - Term Loan - Ad
Long-Term Debt - Term Loan - Additional Information (Details) - USD ($) | Apr. 28, 2017 | Mar. 31, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | |||
Deferred debt issuance costs | $ 3,500,000 | ||
Original issue discount costs | 4,300,000 | ||
Amortization of debt issuance costs | 300,000 | ||
Amortization of original issue discount costs | $ 500,000 | ||
Term loan yield maintenance ending period post effective date | 30 months | ||
Term loan yield maintenance effective date ending period | 30 months | ||
Term loan yield maintenance effective date after day one | 30 months | ||
Term loan yield maintenance ending period post effective date after day one | 36 months | ||
Gain (loss) on derivative, net | $ (53,000,000) | ||
Level 2 Inputs | |||
Debt Instrument [Line Items] | |||
Short-term derivative instruments | 53,000,000 | ||
Term Loans, Net | |||
Debt Instrument [Line Items] | |||
Line of credit facility, maximum borrowing capacity | $ 300,000,000 | ||
Deferred financing fees | 7,700,000 | ||
Debt instrument, interest rate event of default | 4.00% | ||
Commitment fee | 3.50% | ||
EBITDAX to cash interest expense ratio | 100.00% | ||
Short-term derivative instruments | $ 53,000,000 | ||
Criteria PDP coverage ratio | 234.00% | ||
Criteria debt to EBITDAX ratio | 292.00% | ||
Criteria EBITDAX to cash interest expense ratio | 251.00% | ||
Term Loans, Net | Until No More Than $287,950,000 | |||
Debt Instrument [Line Items] | |||
Percentage of prepayment on excess cash flow | 50.00% | ||
Term Loans, Net | 30 Months After Effective Date | |||
Debt Instrument [Line Items] | |||
Percentage of prepayments, terminations, refinancing, reductions and accretions | 3.00% | ||
Term Loans, Net | 36 Months After Effective Date | |||
Debt Instrument [Line Items] | |||
Percentage of prepayments, terminations, refinancing, reductions and accretions | 1.00% | ||
Term Loans, Net | Maximum | |||
Debt Instrument [Line Items] | |||
Net senior secured debt to EBITDAX | 325.00% | ||
Term Loans, Net | Minimum | |||
Debt Instrument [Line Items] | |||
Criteria PDP coverage ratio | 165.00% | ||
EBITDAX to cash interest expense ratio | 100.00% | ||
EBITDAX to cash interest expense ratio thereafter | 130.00% | ||
Term Loans, Net | Adjusted LIBO Rate | |||
Debt Instrument [Line Items] | |||
Debt instrument, floor rate | 1.00% | ||
Debt instrument, margin rate | 8.75% | ||
8.00% Senior Secured Second Lien Notes due 2020 | |||
Debt Instrument [Line Items] | |||
Debt instrument, interest rate | 8.00% | ||
Debt instrument, outstanding amount | $ 25,000,000 | ||
1.00% Senior Secured Second Lien Notes due 2020 | |||
Debt Instrument [Line Items] | |||
Debt instrument, interest rate | 1.00% | ||
Second Lien Notes | Term Loans, Net | |||
Debt Instrument [Line Items] | |||
Percentage of prepayment on excess cash flow | 75.00% | ||
Second Lien Notes | Term Loans, Net | Maximum | |||
Debt Instrument [Line Items] | |||
Second lien notes outstanding | $ 287,950,000 | ||
Term Facility | |||
Debt Instrument [Line Items] | |||
Line of credit facility, current borrowing capacity | 143,500,000 | ||
Line of credit facility, amount outstanding | $ 221,000,000 | ||
Secured Delayed Draw Term Loan Facility | |||
Debt Instrument [Line Items] | |||
Line of credit facility, remaining borrowing capacity | $ 156,500,000 | ||
Line of credit facility, maturity date | Apr. 28, 2021 | ||
Line of credit facility, expiration date | Apr. 28, 2018 | ||
Line of credit facility expiration date potential extension period | 1 year | ||
Original issue discount costs | 2,300,000 | ||
Letter Of Credit | |||
Debt Instrument [Line Items] | |||
Line of credit facility, remaining borrowing capacity | $ 32,000,000 |
Long-Term Debt - Senior Notes -
Long-Term Debt - Senior Notes - Additional Information (Details) - USD ($) shares in Millions | Mar. 31, 2016 | Mar. 31, 2018 | Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Apr. 28, 2017 |
Debt Instrument [Line Items] | |||||||
Share of common stock | 10.1 | ||||||
Shares issued | 8.4 | ||||||
Fair value of stock issued | $ 6,500,000 | $ 6,500,000 | |||||
Accrued and unpaid interest | 12,800,000 | 12,800,000 | |||||
Third-party debt issuance costs | $ 567,000 | ||||||
Issuance of unrestricted common stock shares | 0.3 | 0.1 | 2.4 | ||||
Gain on Extinguishments of Debt | $ 249,000 | ||||||
Interest Payments One Through Three | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Frequency of Periodic Payment | semi-annual | ||||||
Maximum | |||||||
Debt Instrument [Line Items] | |||||||
Senior notes offered for exchange | 675,000,000 | ||||||
Senior Notes, Net | |||||||
Debt Instrument [Line Items] | |||||||
Gain on Extinguishments of Debt | 400,000 | ||||||
Discount/Premium on Senior Notes, Net | $ 12,800,000 | $ 14,000,000 | |||||
Amortization of net premium/discounts | 1,200,000 | (3,800,000) | |||||
Capitalized interest | (1,200,000) | ||||||
Unamortized net Premium / Discount | (12,800,000) | (14,000,000) | |||||
Senior Notes, Net | Interest Expense | |||||||
Debt Instrument [Line Items] | |||||||
Amortization of net premium/discounts | 4,400,000 | 6,300,000 | |||||
Cash interest payments | 6,800,000 | 1,300,000 | |||||
Increase (decrease) in accrued interest | $ 12,600,000 | $ 1,500,000 | |||||
Term Loans, Net | |||||||
Debt Instrument [Line Items] | |||||||
Average interest rate | 10.50% | ||||||
Capital Leases | |||||||
Debt Instrument [Line Items] | |||||||
Average interest rate | 16.80% | 11.00% | |||||
Senior Credit Facility | |||||||
Debt Instrument [Line Items] | |||||||
Average interest rate | 3.70% | ||||||
Debt Restructurings | |||||||
Debt Instrument [Line Items] | |||||||
Discount/Premium on Senior Notes, Net | $ (12,800,000) | (14,000,000) | |||||
Unamortized net Premium / Discount | 12,800,000 | 14,000,000 | |||||
Unamortized Debt Issuance Costs | 30,800,000 | 33,600,000 | |||||
Unamortized deferred gain on debt restructurings | $ 27,700,000 | 30,400,000 | |||||
8.00% Senior Secured Second Lien Notes due 2020 | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate | 8.00% | ||||||
8.00% Senior Secured Second Lien Notes due 2020 | Senior Notes, Net | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate | 8.875% | ||||||
Second Lien Notes | |||||||
Debt Instrument [Line Items] | |||||||
Gain recognized due to troubled debt exchanges | 0 | ||||||
Aggregate principal amount | 633,200,000 | $ 633,200,000 | |||||
Additional issuance of debt | $ 500,000 | ||||||
Debt instrument initial interest payment date | Oct. 1, 2016 | ||||||
Debt instrument maturity date | Oct. 1, 2020 | ||||||
Third-party debt issuance costs | $ 9,100,000 | ||||||
Expiration grace period | 30 days | ||||||
Debt amount for conversion | 45,700,000 | ||||||
Debt instrument redemption date | Apr. 1, 2018 | ||||||
Latest date for equity proceeds to be applied to optional Note redemption | Apr. 1, 2018 | ||||||
Percentage of notes that can be redeemed | 35.00% | ||||||
Second Lien Notes | Interest Payments One Through Three | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate | 1.00% | 1.00% | |||||
Second Lien Notes | Interest Payments Four And Thereafter | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate | 8.00% | 8.00% | |||||
Second Lien Notes | Senior Notes, Net | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate | 6.25% | ||||||
2020 Senior Notes | |||||||
Debt Instrument [Line Items] | |||||||
Aggregate principal amount | $ 324,000,000 | $ 324,000,000 | |||||
Percentage of senior notes exchanged for new notes | 92.60% | ||||||
Retirement of notes | $ 900,000 | $ 27,700,000 | |||||
2022 Senior Notes | |||||||
Debt Instrument [Line Items] | |||||||
Aggregate principal amount | $ 309,100,000 | $ 309,100,000 | |||||
Percentage of senior notes exchanged for new notes | 95.10% | ||||||
8.875% Senior Notes | Senior Notes, Net | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate | 8.875% | 8.875% | |||||
6.25% Senior Notes | Senior Notes, Net | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate | 6.25% | 6.25% |
Components of Long-Term Debt an
Components of Long-Term Debt and Lines of Credit (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Term Loans, Net | Term Loan Draw - due April 2020 | ||
Debt Instrument [Line Items] | ||
Principal | $ 221,000 | $ 189,500 |
Net Carrying Value | 221,000 | 182,028 |
Unamortized net Premium / Discount | (4,711) | |
Unamortized Debt Issuance Costs | (2,761) | |
Senior Notes, Net | ||
Debt Instrument [Line Items] | ||
Principal | 600,302 | 600,302 |
Deferred Gain on Debt Restructurings, Net | 45,813 | 50,069 |
Net Carrying Value | 646,115 | 650,371 |
Unamortized net Premium / Discount | (12,800) | (14,000) |
Senior Notes, Net | 8.875% Senior Notes due 2020 | ||
Debt Instrument [Line Items] | ||
Principal | 7,333 | 7,333 |
Deferred Gain on Debt Restructurings, Net | (60) | |
Net Carrying Value | 7,333 | 7,273 |
Senior Notes, Net | 6.25% Senior Notes due 2022 | ||
Debt Instrument [Line Items] | ||
Principal | 5,363 | 5,363 |
Deferred Gain on Debt Restructurings, Net | (67) | |
Net Carrying Value | 5,363 | 5,296 |
Senior Notes, Net | 1% / 8% Second Lien Senior Notes due 2020 | ||
Debt Instrument [Line Items] | ||
Principal | 587,606 | 587,606 |
Deferred Gain on Debt Restructurings, Net | 45,813 | 50,196 |
Net Carrying Value | 633,419 | 637,802 |
Other Long-Term Debt | ||
Debt Instrument [Line Items] | ||
Long-Term Capital Leases - Equipment Financing | 7,972 | |
Total Capital Lease Obligations | 10,054 | 10,082 |
Less: Current Portion of Capital Leases | (2,082) | |
Less: Current Portion of Capital Leases and Other Notes Payable | (1,926) | |
Non-Current Portion of Capital Leases and Other Notes Payable | 8,156 | |
Other Long-Term Debt | Due March, 2021 | ||
Debt Instrument [Line Items] | ||
Total Capital Lease Obligations | 596 | 632 |
Other Long-Term Debt | Due June, 2021 | ||
Debt Instrument [Line Items] | ||
Total Capital Lease Obligations | 1,337 | 1,418 |
Other Long-Term Debt | Due September, 2021 | ||
Debt Instrument [Line Items] | ||
Total Capital Lease Obligations | 1,505 | 1,578 |
Other Long-Term Debt | Due May, 2022 | ||
Debt Instrument [Line Items] | ||
Total Capital Lease Obligations | $ 6,616 | $ 6,454 |
Components of Long-Term Debt 46
Components of Long-Term Debt and Lines of Credit (Parenthetical) (Details) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018 | Dec. 31, 2017 | |
Term Loans, Net | ||
Debt Instrument [Line Items] | ||
Debt instrument, maturity date, month and year | 2020-04 | |
8.875% Senior Notes due 2020 | Senior Notes, Net | ||
Debt Instrument [Line Items] | ||
Debt instrument, interest rate | 8.875% | 8.875% |
Debt instrument, maturity year | 2,020 | 2,020 |
6.25% Senior Notes due 2022 | Senior Notes, Net | ||
Debt Instrument [Line Items] | ||
Debt instrument, interest rate | 6.25% | 6.25% |
Debt instrument, maturity year | 2,022 | 2,022 |
1% / 8% Second Lien Senior Notes due 2020 | Senior Notes, Net | ||
Debt Instrument [Line Items] | ||
Debt instrument, interest rate | 0.125% | 0.125% |
Debt instrument, maturity year | 2,020 | 2,020 |
Due March, 2021 | Other Long-Term Debt | ||
Debt Instrument [Line Items] | ||
Debt instrument, maturity date, month and year | 2021-03 | 2021-03 |
Due June, 2021 | Other Long-Term Debt | ||
Debt Instrument [Line Items] | ||
Debt instrument, maturity date, month and year | 2021-06 | 2021-06 |
Due September, 2021 | Other Long-Term Debt | ||
Debt Instrument [Line Items] | ||
Debt instrument, maturity date, month and year | 2021-09 | 2021-09 |
Due May, 2022 | Other Long-Term Debt | ||
Debt Instrument [Line Items] | ||
Debt instrument, maturity date, month and year | 2022-05 | 2022-05 |
Principal Maturity Schedule for
Principal Maturity Schedule for Debt Outstanding (Details) $ in Thousands | Mar. 31, 2018USD ($) | |
Debt Disclosure [Abstract] | ||
2,018 | $ 822,833 | [1] |
2,019 | 2,341 | |
2,020 | 2,739 | |
2,021 | 2,582 | |
2,022 | 861 | |
Total | $ 831,356 | [2] |
[1] | Due to existing and anticipated covenant violations, the Company’s Term Loan and Senior Notes were classified as current as December 31, 2017. | |
[2] | Excludes $45.8 million of Deferred Gain on Debt Restructurings, Net. |
Principal Maturity Schedule f48
Principal Maturity Schedule for Debt Outstanding (Parenthetical) (Details) $ in Millions | Mar. 31, 2018USD ($) |
Debt Restructurings | |
Debt Instrument [Line Items] | |
Deferred Gain on Debt Restructurings, Net | $ 45.8 |
Derivative Instruments and Fa49
Derivative Instruments and Fair Value Measurements - Additional Information (Details) $ in Thousands | Apr. 15, 2019USD ($) | Apr. 28, 2017 | Mar. 31, 2018USD ($)Entity | Mar. 31, 2017USD ($) | Dec. 31, 2017USD ($) |
Derivatives Fair Value [Line Items] | |||||
Number of counterparties entered into an arrangements | Entity | 2 | ||||
Cash Settlements of Derivatives Paid | $ 2,009 | $ 3,443 | |||
Term loan yield maintenance ending period post effective date | 30 months | ||||
Term loan yield maintenance effective date ending period | 30 months | ||||
Term loan yield maintenance effective date after day one | 30 months | ||||
Term loan yield maintenance ending period post effective date after day one | 36 months | ||||
Gain (loss) on derivative, net | $ (53,000) | ||||
Derivatives asset (liability) | 64,600 | $ 19,400 | |||
Impairment Expense | 8,168 | 1,546 | |||
Discontinued Operations Assets Held For Sale | Illinois Basin Operations | |||||
Derivatives Fair Value [Line Items] | |||||
Fair value of contingent consideration derivative asset | 1,200 | ||||
Fair value of contingent consideration | 2,100 | $ 1,700 | |||
Discounted fair value of additional consideration earned income | 800 | ||||
Discounted fair value of accounts receivable | 800 | ||||
Discontinued Operations Assets Held For Sale | Illinois Basin Operations | Scenario Forecast | |||||
Derivatives Fair Value [Line Items] | |||||
Remitted amount | $ 900 | ||||
Level 2 Inputs | |||||
Derivatives Fair Value [Line Items] | |||||
Short-term derivative instruments | 53,000 | ||||
Term Loans, Net | |||||
Derivatives Fair Value [Line Items] | |||||
Short-term derivative instruments | 53,000 | ||||
Term Loans, Net | 30 Months After Effective Date | |||||
Derivatives Fair Value [Line Items] | |||||
Percentage of prepayments, terminations, refinancing, reductions and accretions | 3.00% | ||||
Term Loans, Net | 36 Months After Effective Date | |||||
Derivatives Fair Value [Line Items] | |||||
Percentage of prepayments, terminations, refinancing, reductions and accretions | 1.00% | ||||
Commodity derivatives | |||||
Derivatives Fair Value [Line Items] | |||||
Cash Settlements of Derivatives Paid | $ (2,000) | $ (3,400) |
Schedule of Location and Amount
Schedule of Location and Amounts of Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Derivative Instruments Gain Loss [Line Items] | ||
(Loss) Gain on Derivatives, Net | $ (46,426) | $ 8,381 |
Embedded Derivatives | ||
Derivative Instruments Gain Loss [Line Items] | ||
(Loss) Gain on Derivatives, Net | (52,965) | |
Crude Oil | ||
Derivative Instruments Gain Loss [Line Items] | ||
(Loss) Gain on Derivatives, Net | (1,735) | 1,137 |
Natural Gas | ||
Derivative Instruments Gain Loss [Line Items] | ||
(Loss) Gain on Derivatives, Net | 3,392 | (59) |
Natural Gas Liquids | ||
Derivative Instruments Gain Loss [Line Items] | ||
(Loss) Gain on Derivatives, Net | 3,669 | 8,720 |
Contingent Consideration | ||
Derivative Instruments Gain Loss [Line Items] | ||
(Loss) Gain on Derivatives, Net | $ 1,214 | $ (1,417) |
Asset or Liability Financial Co
Asset or Liability Financial Commodity Derivative Instrument Positions (Details) $ in Thousands | 3 Months Ended |
Mar. 31, 2018USD ($)$ / bbl$ / McfbblMcf | |
Crude Oil 2018 | Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 9,000 |
Floor | $ / bbl | 53 |
Ceiling | $ / bbl | 60 |
Derivatives asset (liability) | $ (47) |
Crude Oil 2018 | Three Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 57,000 |
Put Option | $ / bbl | 42.11 |
Floor | $ / bbl | 51.32 |
Ceiling | $ / bbl | 61.14 |
Derivatives asset (liability) | $ (222) |
Crude Oil 2018 | Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 139,250 |
Swap | $ / bbl | 57.55 |
Derivatives asset (liability) | $ (811) |
Crude Oil 2019 | Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 60,250 |
Floor | $ / bbl | 45 |
Ceiling | $ / bbl | 55.07 |
Derivatives asset (liability) | $ (161) |
Crude Oil 2019 | Three Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 51,000 |
Put Option | $ / bbl | 38.82 |
Floor | $ / bbl | 48.82 |
Ceiling | $ / bbl | 58.31 |
Derivatives asset (liability) | $ (201) |
Crude Oil 2019 | Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 53,500 |
Swap | $ / bbl | 49.04 |
Derivatives asset (liability) | $ (425) |
Crude Oil 2020 | Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 71,750 |
Floor | $ / bbl | 45 |
Ceiling | $ / bbl | 55.10 |
Derivatives asset (liability) | $ (215) |
Crude Oil 2020 | Three Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 33,725 |
Put Option | $ / bbl | 39.39 |
Floor | $ / bbl | 49.39 |
Ceiling | $ / bbl | 57.04 |
Derivatives asset (liability) | $ (116) |
Crude Oil 2020 | Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 24,000 |
Swap | $ / bbl | 50.63 |
Derivatives asset (liability) | $ (146) |
Crude Oil 2021 | Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 63,750 |
Floor | $ / bbl | 45 |
Ceiling | $ / bbl | 55.02 |
Derivatives asset (liability) | $ (197) |
Crude Oil 2021 | Three Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 13,250 |
Put Option | $ / bbl | 39.10 |
Floor | $ / bbl | 49.10 |
Ceiling | $ / bbl | 60.41 |
Derivatives asset (liability) | $ (45) |
Crude Oil 2021 | Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 15,000 |
Swap | $ / bbl | 50.40 |
Derivatives asset (liability) | $ (36) |
Crude Oil 2022 | Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 36,000 |
Floor | $ / bbl | 45 |
Ceiling | $ / bbl | 54.75 |
Derivatives asset (liability) | $ (107) |
Crude Oil 2022 | Three Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 5,500 |
Put Option | $ / bbl | 40 |
Floor | $ / bbl | 50 |
Ceiling | $ / bbl | 60.50 |
Derivatives asset (liability) | $ (11) |
Crude Oil 2022 | Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 6,750 |
Swap | $ / bbl | 50 |
Crude Oil | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 639,725 |
Derivatives asset (liability) | $ (2,740) |
Natural Gas 2018 | Collars | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 3,965,000 |
Floor | $ / Mcf | 2.60 |
Ceiling | $ / Mcf | 3.04 |
Derivatives asset (liability) | $ (153) |
Natural Gas 2018 | Three Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 7,600,000 |
Put Option | $ / Mcf | 2.33 |
Floor | $ / Mcf | 2.89 |
Ceiling | $ / Mcf | 3.49 |
Derivatives asset (liability) | $ 1,124 |
Natural Gas 2018 | Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 18,342,500 |
Swap | $ / Mcf | 2.98 |
Derivatives asset (liability) | $ 2,400 |
Natural Gas 2018 | Basis Swaps - Dominion South | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 10,625,000 |
Swap | $ / Mcf | (0.82) |
Derivatives asset (liability) | $ (2,056) |
Natural Gas 2018 | Basis Swaps - Texas Gas | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 11,000,000 |
Swap | $ / Mcf | (0.13) |
Derivatives asset (liability) | $ 448 |
Natural Gas 2018 | Calls | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 4,370,000 |
Ceiling | $ / Mcf | 3.97 |
Derivatives asset (liability) | $ (38) |
Natural Gas 2019 | Collars | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 9,051,750 |
Floor | $ / Mcf | 2.56 |
Ceiling | $ / Mcf | 3.04 |
Derivatives asset (liability) | $ (270) |
Natural Gas 2019 | Three Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 11,250,000 |
Put Option | $ / Mcf | 2.29 |
Floor | $ / Mcf | 2.76 |
Ceiling | $ / Mcf | 3.34 |
Derivatives asset (liability) | $ 282 |
Natural Gas 2019 | Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 11,620,000 |
Swap | $ / Mcf | 2.84 |
Derivatives asset (liability) | $ 255 |
Natural Gas 2019 | Basis Swaps - Dominion South | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 12,775,000 |
Swap | $ / Mcf | (0.84) |
Derivatives asset (liability) | $ (2,721) |
Natural Gas 2020 | Collars | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 6,760,000 |
Floor | $ / Mcf | 2.56 |
Ceiling | $ / Mcf | 3.04 |
Derivatives asset (liability) | $ (153) |
Natural Gas 2020 | Three Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 7,680,000 |
Put Option | $ / Mcf | 2.27 |
Floor | $ / Mcf | 2.73 |
Ceiling | $ / Mcf | 3.24 |
Derivatives asset (liability) | $ 279 |
Natural Gas 2020 | Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 5,542,500 |
Swap | $ / Mcf | 2.88 |
Derivatives asset (liability) | $ 135 |
Natural Gas 2020 | Basis Swaps - Dominion South | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 7,320,000 |
Swap | $ / Mcf | (0.84) |
Derivatives asset (liability) | $ (1,519) |
Natural Gas 2021 | Collars | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 3,530,000 |
Floor | $ / Mcf | 2.53 |
Ceiling | $ / Mcf | 3.05 |
Derivatives asset (liability) | $ (77) |
Natural Gas 2021 | Three Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 4,083,750 |
Put Option | $ / Mcf | 2.21 |
Floor | $ / Mcf | 2.68 |
Ceiling | $ / Mcf | 3.13 |
Derivatives asset (liability) | $ 66 |
Natural Gas 2021 | Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 3,875,000 |
Swap | $ / Mcf | 2.77 |
Derivatives asset (liability) | $ (5) |
Natural Gas 2021 | Basis Swaps - Dominion South | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 3,650,000 |
Swap | $ / Mcf | (0.72) |
Derivatives asset (liability) | $ (273) |
Natural Gas 2022 | Collars | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 2,195,000 |
Floor | $ / Mcf | 2.51 |
Ceiling | $ / Mcf | 3.05 |
Derivatives asset (liability) | $ (52) |
Natural Gas 2022 | Three Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 2,047,500 |
Put Option | $ / Mcf | 2.15 |
Floor | $ / Mcf | 2.65 |
Ceiling | $ / Mcf | 3.10 |
Derivatives asset (liability) | $ 21 |
Natural Gas 2022 | Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 2,730,000 |
Swap | $ / Mcf | 2.73 |
Derivatives asset (liability) | $ (42) |
Natural Gas 2022 | Basis Swaps - Dominion South | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 3,650,000 |
Swap | $ / Mcf | (0.72) |
Derivatives asset (liability) | $ (273) |
Natural Gas 2023 | Basis Swaps - Dominion South | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 3,650,000 |
Swap | $ / Mcf | (0.72) |
Derivatives asset (liability) | $ (273) |
Natural Gas 2024 | Basis Swaps - Dominion South | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 3,650,000 |
Swap | $ / Mcf | (0.72) |
Derivatives asset (liability) | $ (273) |
Natural Gas | |
Derivatives Fair Value [Line Items] | |
Volume | Mcf | 160,963,000 |
Derivatives asset (liability) | $ (3,168) |
Natural Gas Liquids Reserves 2018 | C3+ NGL Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 1,137,405 |
Swap | $ / bbl | 34.05 |
Derivatives asset (liability) | $ (5,540) |
Natural Gas Liquids Reserves 2018 | Ethane Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 1,302,000 |
Swap | $ / bbl | 12.22 |
Derivatives asset (liability) | $ 750 |
Natural Gas Liquids Reserves 2019 | C3+ NGL Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 957,943 |
Swap | $ / bbl | 29.98 |
Derivatives asset (liability) | $ (1,883) |
Natural Gas Liquids Reserves 2019 | Ethane Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 1,317,750 |
Swap | $ / bbl | 12.61 |
Derivatives asset (liability) | $ 805 |
Natural Gas Liquids Reserves 2019 | C5 Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 113,040 |
Floor | $ / bbl | 45 |
Ceiling | $ / bbl | 54.83 |
Derivatives asset (liability) | $ (495) |
Natural Gas Liquids Reserves 2019 | C5 Three-Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 7,536 |
Floor | $ / bbl | 32.31 |
Ceiling | $ / bbl | 50 |
Swap | $ / bbl | 55.75 |
Derivatives asset (liability) | $ (24) |
Natural Gas Liquids Reserves 2020 | C3+ NGL Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 347,689 |
Swap | $ / bbl | 30.40 |
Derivatives asset (liability) | $ (996) |
Natural Gas Liquids Reserves 2020 | Ethane Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 1,150,750 |
Swap | $ / bbl | 12.37 |
Derivatives asset (liability) | $ 113 |
Natural Gas Liquids Reserves 2020 | C5 Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 28,260 |
Floor | $ / bbl | 45 |
Ceiling | $ / bbl | 54.83 |
Derivatives asset (liability) | $ (124) |
Natural Gas Liquids Reserves 2020 | C5 Three-Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 41,225 |
Floor | $ / bbl | 34.87 |
Ceiling | $ / bbl | 49.94 |
Swap | $ / bbl | 57.36 |
Derivatives asset (liability) | $ (82) |
Natural Gas Liquids Reserves 2021 | C3+ NGL Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 210,206 |
Swap | $ / bbl | 31.62 |
Derivatives asset (liability) | $ (402) |
Natural Gas Liquids Reserves 2021 | Ethane Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 805,000 |
Swap | $ / bbl | 12.32 |
Derivatives asset (liability) | $ 93 |
Natural Gas Liquids Reserves 2021 | C5 Three-Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 63,398 |
Floor | $ / bbl | 38.99 |
Ceiling | $ / bbl | 48.99 |
Swap | $ / bbl | 60.40 |
Derivatives asset (liability) | $ (37) |
Natural Gas Liquids | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 7,946,878 |
Derivatives asset (liability) | $ (7,893) |
Natural Gas Liquids Reserves 2022 | C3+ NGL Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 62,966 |
Swap | $ / bbl | 32.60 |
Derivatives asset (liability) | $ (114) |
Natural Gas Liquids Reserves 2022 | Ethane Swaps | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 379,250 |
Swap | $ / bbl | 12.31 |
Derivatives asset (liability) | $ 52 |
Natural Gas Liquids Reserves 2022 | C5 Three-Way Collars | |
Derivatives Fair Value [Line Items] | |
Volume | bbl | 22,460 |
Floor | $ / bbl | 39.11 |
Ceiling | $ / bbl | 49.11 |
Swap | $ / bbl | 60.41 |
Derivatives asset (liability) | $ (9) |
Combined Fair Value of Derivati
Combined Fair Value of Derivatives (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Short-Term Derivative Assets: | ||
Total Short-Term Derivative Assets | $ 7,732 | $ 8,008 |
Long-Term Derivative Assets: | ||
Total Long-Term Derivative Assets | 2,880 | 1,719 |
Total Derivative Assets | 10,612 | 9,727 |
Short-Term Derivative Liabilities: | ||
Total Short - Term Derivative Liabilities | (64,671) | (14,892) |
Long-Term Derivative Liabilities: | ||
Total Long-Term Derivative Liabilities | (10,576) | (14,249) |
Total Derivative Liabilities | (75,247) | (29,141) |
Embedded Derivatives | ||
Short-Term Derivative Liabilities: | ||
Total Short - Term Derivative Liabilities | (52,965) | |
Contingent Consideration | Sale of Illinois Basin | ||
Short-Term Derivative Assets: | ||
Total Short-Term Derivative Assets | 1,841 | 1,251 |
Contingent Consideration | Sale of Illinois Basin | ||
Long-Term Derivative Assets: | ||
Total Long-Term Derivative Assets | 290 | 470 |
Natural Gas Liquids | Swaps | ||
Short-Term Derivative Assets: | ||
Total Short-Term Derivative Assets | 1,549 | 928 |
Long-Term Derivative Assets: | ||
Total Long-Term Derivative Assets | 1,511 | 409 |
Short-Term Derivative Liabilities: | ||
Total Short - Term Derivative Liabilities | (7,205) | (10,281) |
Long-Term Derivative Liabilities: | ||
Total Long-Term Derivative Liabilities | (2,977) | (4,482) |
Natural Gas Liquids | Collars | ||
Short-Term Derivative Liabilities: | ||
Total Short - Term Derivative Liabilities | (124) | |
Long-Term Derivative Liabilities: | ||
Total Long-Term Derivative Liabilities | (495) | (385) |
Natural Gas Liquids | Three Way Collars | ||
Long-Term Derivative Liabilities: | ||
Total Long-Term Derivative Liabilities | (152) | (66) |
Natural Gas | Swaps | ||
Short-Term Derivative Assets: | ||
Total Short-Term Derivative Assets | 2,672 | 3,734 |
Long-Term Derivative Assets: | ||
Total Long-Term Derivative Assets | 404 | 411 |
Short-Term Derivative Liabilities: | ||
Total Short - Term Derivative Liabilities | (121) | |
Long-Term Derivative Liabilities: | ||
Total Long-Term Derivative Liabilities | (212) | (423) |
Natural Gas | Collars | ||
Short-Term Derivative Assets: | ||
Total Short-Term Derivative Assets | 183 | |
Short-Term Derivative Liabilities: | ||
Total Short - Term Derivative Liabilities | (206) | (146) |
Long-Term Derivative Liabilities: | ||
Total Long-Term Derivative Liabilities | (499) | (713) |
Natural Gas | Basis Swaps | ||
Short-Term Derivative Assets: | ||
Total Short-Term Derivative Assets | 448 | 191 |
Short-Term Derivative Liabilities: | ||
Total Short - Term Derivative Liabilities | (2,738) | (3,621) |
Long-Term Derivative Liabilities: | ||
Total Long-Term Derivative Liabilities | (4,650) | (7,120) |
Natural Gas | Three Way Collars | ||
Short-Term Derivative Assets: | ||
Total Short-Term Derivative Assets | 1,222 | 1,721 |
Long-Term Derivative Assets: | ||
Total Long-Term Derivative Assets | 675 | 429 |
Short-Term Derivative Liabilities: | ||
Total Short - Term Derivative Liabilities | (25) | (49) |
Long-Term Derivative Liabilities: | ||
Total Long-Term Derivative Liabilities | (100) | (272) |
Natural Gas | Calls | ||
Short-Term Derivative Liabilities: | ||
Total Short - Term Derivative Liabilities | (38) | (154) |
Crude Oil | Swaps | ||
Short-Term Derivative Liabilities: | ||
Total Short - Term Derivative Liabilities | (914) | (518) |
Long-Term Derivative Liabilities: | ||
Total Long-Term Derivative Liabilities | (504) | (202) |
Crude Oil | Collars | ||
Short-Term Derivative Liabilities: | ||
Total Short - Term Derivative Liabilities | (46) | (31) |
Long-Term Derivative Liabilities: | ||
Total Long-Term Derivative Liabilities | (681) | (425) |
Crude Oil | Three Way Collars | ||
Short-Term Derivative Liabilities: | ||
Total Short - Term Derivative Liabilities | (289) | (92) |
Long-Term Derivative Liabilities: | ||
Total Long-Term Derivative Liabilities | $ (306) | $ (161) |
Fair Value Hierarchy Table for
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Commodity derivatives | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivatives asset (liability) | $ (11,670) | $ (19,414) |
Embedded Derivatives | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivatives asset (liability) | (52,965) | |
Significant Other Observable Inputs (Level 2) | Commodity derivatives | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivatives asset (liability) | (11,670) | $ (19,414) |
Significant Other Observable Inputs (Level 2) | Embedded Derivatives | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivatives asset (liability) | $ (52,965) |
Financial Instruments Not Recor
Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Carrying Amount | ||
Derivatives Fair Value [Line Items] | ||
Senior Notes, Net of Issuance Costs | $ 646,115 | $ 650,371 |
Term Loan | 221,000 | 182,028 |
Capital Leases and Other Obligations | 10,054 | 10,082 |
Total | 877,169 | 842,481 |
Fair Value | ||
Derivatives Fair Value [Line Items] | ||
Senior Notes, Net of Issuance Costs | 214,080 | 264,438 |
Term Loan | 208,790 | 182,028 |
Capital Leases and Other Obligations | 7,271 | 7,138 |
Total | $ 430,141 | $ 453,604 |
Schedule of Income Tax Included
Schedule of Income Tax Included in Continuing Operations (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Income Tax Disclosure [Abstract] | ||
Income Tax Benefit (Expense) | $ 0 | $ 0 |
Effective Tax Rate | (0.00%) | (0.00%) |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Estimated annual effective tax rate from continue operations | 0.00% | 0.00% | |
Statutory rate | 21.00% | 35.00% | |
Income Tax Benefit (Expense) | $ 0 | $ 0 | |
Estimated annual effective tax rate from continuing operations | (0.00%) | ||
Income tax payments | 0 | $ 0 | |
Income tax refunds | $ 2 |
Capital Stock - Additional Info
Capital Stock - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | May 12, 2017 | May 05, 2017 | May 27, 2016 | |
Schedule Of Capitalization Equity [Line Items] | |||||||
Common stock, shares authorized | 100,000,000 | 100,000,000 | 100,000,000 | 200,000,000 | |||
Preferred Stock, shares authorized | 100,000 | 100,000 | |||||
Common Stock, shares issued | 10,708,287 | 99,000,000 | 10,244,394 | 9,900,000 | |||
Common Stock, shares outstanding | 10,708,287 | 10,244,394 | |||||
Issuance of common stock | 300,000 | 100,000 | 2,400,000 | ||||
Reverse stock split | 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. | ||||||
Preferred Stock, par value | $ 0.001 | $ 0.001 | |||||
Preferred Stock, shares issued | 3,987 | 3,987 | |||||
Preferred Stock, shares outstanding | 3,987 | 3,987 | |||||
Preferred dividend paid in stock | $ 1 | ||||||
6.0% convertible perpetual preferred stock, Series A | |||||||
Schedule Of Capitalization Equity [Line Items] | |||||||
Preferred Stock, par value | $ 0.001 | $ 0.001 | |||||
Preferred Stock, shares issued | 3,987 | 3,987 | |||||
Preferred Stock, shares outstanding | 3,987 | 3,987 | |||||
Dividend per share in amount | $ 600 | ||||||
Dividend per share percentage | 6.00% | ||||||
Dividends declared on Preferred Stock | $ 1,800 | ||||||
Cash dividend paid per share | $ 150 | ||||||
Aggregate amount of cash dividend paid | $ 1,200 | ||||||
Preferred dividend paid per share | $ 150 | $ 150 | |||||
Preferred dividend paid in stock | $ 600 | $ 600 | |||||
Accumulated dividends in arrears | $ 3,000 | ||||||
Depositary shares | |||||||
Schedule Of Capitalization Equity [Line Items] | |||||||
Liquidation preference per share | $ 10,000 |
Employee Benefit and Equity P58
Employee Benefit and Equity Plans - Additional Information (Details) | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2018USD ($)$ / sharesshares | Mar. 31, 2017USD ($)Personshares | Dec. 31, 2015$ / shares | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Number of option issued to purchase common stock | shares | 0 | 0 | |
Stock-based compensation expense | $ 1,018,000 | $ 71,000 | |
Stock options exercised | shares | 0 | ||
Tax benefit related to stock option exercises | $ 0 | 0 | |
Outstanding weighted average remaining term (in years) | 4 years 6 months | ||
Weighted average remaining term of options exercisable (in years) | 4 years 3 months 18 days | ||
Aggregate intrinsic value of options outstanding | $ 0 | ||
Aggregate intrinsic value of options exercisable | 0 | ||
Restricted Stock or Unit Expense | 900,000 | 100,000 | |
Stock Options | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | 100,000 | 100,000 | |
Restricted Stock | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 1,100,000 | $ 900,000 | |
Common stock issued by compensation committee | shares | 0 | 101,237 | |
Number of employees subjected to issuance of common stock | Person | 28 | ||
Unrecognized compensation expense weighted average period, in years | 1 year 3 months 18 days | ||
Unrecognized compensation expense | $ 400,000 | ||
Vested stock | shares | 56,335 | ||
Restricted Stock | TSR | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Fair value of TSR awards of per share estimated on date of grant | $ / shares | $ 0 | $ 2.56 | |
Restricted Stock | Certain Performance Factors Waived | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Vested stock | shares | 29,411 | 179,519 |
Summary of Issued and Outstandi
Summary of Issued and Outstanding Stock Options (Details) | Mar. 31, 2018$ / sharesshares |
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items] | |
Number Outstanding | shares | 75,364 |
Weighted-Average Exercise Price, Outstanding | $ 30.49 |
Number Exercisable | shares | 54,482 |
Weighted-Average Exercise Price, Exercisable | $ 35.95 |
Exercise Price Range 9.70 | |
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items] | |
Exercise Price | $ 9.70 |
Number Outstanding | shares | 2,750 |
Weighted-Average Exercise Price, Outstanding | $ 9.70 |
Number Exercisable | shares | 919 |
Weighted-Average Exercise Price, Exercisable | $ 9.70 |
Exercise Price Range 16.90 | |
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items] | |
Exercise Price | $ 16.90 |
Number Outstanding | shares | 60,327 |
Weighted-Average Exercise Price, Outstanding | $ 16.90 |
Number Exercisable | shares | 41,276 |
Weighted-Average Exercise Price, Exercisable | $ 16.90 |
Exercise Price Range 49.00 | |
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items] | |
Exercise Price | $ 49 |
Number Outstanding | shares | 4,000 |
Weighted-Average Exercise Price, Outstanding | $ 49 |
Number Exercisable | shares | 4,000 |
Weighted-Average Exercise Price, Exercisable | $ 49 |
Exercise Price Range 50.40 | |
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items] | |
Exercise Price | $ 50.40 |
Number Outstanding | shares | 3,070 |
Weighted-Average Exercise Price, Outstanding | $ 50.40 |
Number Exercisable | shares | 3,070 |
Weighted-Average Exercise Price, Exercisable | $ 50.40 |
Exercise Price Range 104.20 | |
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items] | |
Exercise Price | $ 104.20 |
Number Outstanding | shares | 2,217 |
Weighted-Average Exercise Price, Outstanding | $ 104.20 |
Number Exercisable | shares | 2,217 |
Weighted-Average Exercise Price, Exercisable | $ 104.20 |
Exercise Price Range 223.40 | |
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items] | |
Exercise Price | $ 223.40 |
Number Outstanding | shares | 3,000 |
Weighted-Average Exercise Price, Outstanding | $ 223.40 |
Number Exercisable | shares | 3,000 |
Weighted-Average Exercise Price, Exercisable | $ 223.40 |
Monte Carlo Simulation Model As
Monte Carlo Simulation Model Assumptions Used to Estimate Fair Value of Restricted Stock (Details) - Monte Carlo Simulation Model | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018 | Dec. 31, 2017 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Expected Dividend Yield | 0.00% | 0.00% |
Risk-Free Interest Rate | 1.00% | 1.00% |
Expected Volatility | 58.60% | 58.60% |
Market Index | 35.60% | 35.60% |
Expected Life | 3 years | 3 years |
Peer Group | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Expected Volatility Rate Minimum | 29.80% | 29.80% |
Expected Volatility Rate Maximum | 85.00% | 85.00% |
Summary of Nonvested Stock Acti
Summary of Nonvested Stock Activity (Details) - Restricted Stock - $ / shares | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Stock awards, beginning balance, Number of Shares | 200,475 | |
Awards, Number of Shares | 0 | 101,237 |
Forfeitures, Number of Shares | (27,318) | |
Vested, Number of Shares | (56,335) | |
Stock awards, ending balance, Number of Shares | 116,822 | |
Stock awards, beginning balance, Weighted Average Grant Date Fair Value | $ 13.62 | |
Forfeitures, Weighted Average Grant Date Fair Value | 15.24 | |
Vested, Weighted Average Grant Date Fair Value | 24.65 | |
Stock awards, ending balance, Weighted Average Grant Date Fair Value | $ 7.92 |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Details) | Jun. 14, 2016USD ($) | Mar. 31, 2018USD ($)RigsQuarterlyInstallment$ / galgal | Mar. 31, 2017USD ($) |
Loss Contingencies [Line Items] | |||
Significant probable or possible environmental contingent liabilities | $ 0 | ||
Letters of credit | 32,000,000 | ||
Rent expense | 300,000 | $ 200,000 | |
Maximum guarantee of payment of obligations | $ 370,100,000 | ||
Guarantee obligations period | 2,029 | ||
Transportation, processing and marketing expenses of natural gas, condensate and natural gas liquids | $ 31,100,000 | 26,300,000 | |
Fees related to unutilized capacity commitments | 700,000 | 700,000 | |
Production and Lease Operating Expense | 33,846,000 | 28,934,000 | |
Remainder of 2018 | |||
Loss Contingencies [Line Items] | |||
Cost to retain the completion services | $ 2,800,000 | ||
Capacity Reservation | |||
Loss Contingencies [Line Items] | |||
Estimated working interest | 54.00% | ||
Charges incurred for unutilized processing capacity | $ 600,000 | 1,600,000 | |
Capacity Reservation | 2018 | |||
Loss Contingencies [Line Items] | |||
Obligation for the cryogenic gas processing plant if gas is not processed | 12,800,000 | ||
Capacity Reservation | 2019 | |||
Loss Contingencies [Line Items] | |||
Obligation for the cryogenic gas processing plant if gas is not processed | 16,900,000 | ||
Capacity Reservation | 2020 | |||
Loss Contingencies [Line Items] | |||
Obligation for the cryogenic gas processing plant if gas is not processed | 17,000,000 | ||
Capacity Reservation | 2021 | |||
Loss Contingencies [Line Items] | |||
Obligation for the cryogenic gas processing plant if gas is not processed | 16,900,000 | ||
Capacity Reservation | 2022 | |||
Loss Contingencies [Line Items] | |||
Obligation for the cryogenic gas processing plant if gas is not processed | 17,000,000 | ||
Capacity Reservation | Thereafter | |||
Loss Contingencies [Line Items] | |||
Obligation for the cryogenic gas processing plant if gas is not processed | $ 66,500,000 | ||
Ohio Drilling Operations | Water Supply Commitments | |||
Loss Contingencies [Line Items] | |||
Water supply contract, effective date | Jul. 5, 2017 | ||
Water supply contract, maturity date | Jul. 4, 2022 | ||
Water contract purchase obligation | gal | 150,000,000 | ||
Water Fixed price per gallon | $ / gal | 0.0075 | ||
Future commitment for unpurchased volumes of water, amount | $ 600,000 | ||
Drilling Commitments | |||
Loss Contingencies [Line Items] | |||
Number of rigs to support Appalachian Basin operations | Rigs | 1 | ||
Drilling Commitments | Remainder of 2018 | |||
Loss Contingencies [Line Items] | |||
Minimum cost to retain drilling rigs | $ 1,200,000 | ||
Illinois Basin Oil Contingency | Illinois Basin Operations | Discontinued Operations Assets Held For Sale | |||
Loss Contingencies [Line Items] | |||
Proceeds receivable quarterly installments. | $ 900,000 | ||
Proceeds receivable quarterly installments beginning period. | Dec. 31, 2016 | ||
Proceeds receivable quarterly installments ending period. | Jun. 30, 2019 | ||
Expiration of quarterly measurement period number | QuarterlyInstallment | 6 | ||
Expiration of quarterly measurement period number with average spot price | QuarterlyInstallment | 11 | ||
Additional proceeds receivable for first five quarterly installments | $ 0 | ||
Illinois Basin Oil Contingency | Illinois Basin Operations | Discontinued Operations Assets Held For Sale | Average Spot Price of West Texas Intermediate | |||
Loss Contingencies [Line Items] | |||
Expiration of quarterly measurement period number | QuarterlyInstallment | 5 | ||
Illinois Basin Oil Contingency | Illinois Basin Operations | Discontinued Operations Assets Held For Sale | Maximum | |||
Loss Contingencies [Line Items] | |||
Additional proceeds from sale of oil and gas property and equipment | $ 9,900,000 | ||
Additional proceeds receivable for remaining six quarterly installments | $ 4,500,000 | ||
Proceeds Receivable Period for Quarterly Installments | 1 year 15 days | ||
Pennsylvania Impact Fee | |||
Loss Contingencies [Line Items] | |||
Production and Lease Operating Expense | $ 600,000 | $ 800,000 | |
Accrued impact fees | $ 600,000 |
Lease Commitments for Each of N
Lease Commitments for Each of Next Five Years (Details) $ in Thousands | Mar. 31, 2018USD ($) |
Commitments And Contingencies Disclosure [Abstract] | |
2,018 | $ 740 |
2,019 | 899 |
2,020 | 796 |
2,021 | 475 |
2,022 | 485 |
Total | $ 3,395 |
Minimum Net Obligations under S
Minimum Net Obligations under Sales, Gathering and Transportation Agreements (Details) $ in Thousands | Mar. 31, 2018USD ($) |
Commitments And Contingencies Disclosure [Abstract] | |
2,018 | $ 37,992 |
2,019 | 50,875 |
2,020 | 49,522 |
2,021 | 46,551 |
2,022 | 46,090 |
Thereafter | 461,109 |
Total | $ 692,139 |
Average Spot Price (Details)
Average Spot Price (Details) - Illinois Basin Operations - Discontinued Operations Assets Held For Sale - Illinois Basin Oil Contingency | 3 Months Ended |
Mar. 31, 2018$ / bbl | |
6/30/2018 | |
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |
West Texas Intermediate ("WTI") Average Price per Bbl | 61.75 |
9/30/2018 | |
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |
West Texas Intermediate ("WTI") Average Price per Bbl | 62.25 |
12/31/2018 | |
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |
West Texas Intermediate ("WTI") Average Price per Bbl | 62.75 |
3/31/2019 | |
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |
West Texas Intermediate ("WTI") Average Price per Bbl | 63.25 |
6/30/2019 | |
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |
West Texas Intermediate ("WTI") Average Price per Bbl | 63.75 |
Earnings Per Common Share - Add
Earnings Per Common Share - Additional Information (Details) - shares | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
6.0% convertible perpetual preferred stock, Series A | ||
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items] | ||
Dividend per share percentage | 6.00% | |
Conversion of Preferred Stock | ||
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items] | ||
Anti-dilutive securities excluded from computation of earnings per share | 221,502 | 221,502 |
Stock Options | ||
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items] | ||
Anti-dilutive securities excluded from computation of earnings per share | 75,363 | 117,122 |
Performance Based Restricted Stock Awards | ||
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items] | ||
Anti-dilutive securities excluded from computation of earnings per share | 0 | 43,124 |
Earnings Per Share - Computatio
Earnings Per Share - Computation of Basic and Diluted Earning Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Numerator: | ||
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: | ||
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 |
Equity Method Investments - Add
Equity Method Investments - Additional Information (Details) - RW Gathering, LLC | 3 Months Ended | ||
Mar. 31, 2018Well | Mar. 31, 2017USD ($) | Dec. 31, 2017USD ($) | |
Schedule Of Equity Method Investments [Line Items] | |||
Ownership percentage | 40.00% | ||
Ownership interest percentage sold | 40.00% | ||
Number of wells sold | Well | 61 | ||
Production and Lease Operating Expense | $ 200,000 | ||
Due to or from related party | $ 0 |
Impairment Expense - Additional
Impairment Expense - Additional Information (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items] | ||
Impairment Expense | $ 8,168 | $ 1,546 |
Butler County, Pennsylvania, and Warrior County, Ohio | ||
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items] | ||
Impairment Expense | 6,900 | 800 |
Westmoreland, Centre and Clearfield Counties, Pennsylvania | Proved Properties | ||
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items] | ||
Impairment Expense | 1,200 | |
Marcellus and Utica Shale | ||
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items] | ||
Undeveloped properties, cost | $ 179,300 | |
Butler County | Proved Properties | ||
Amortization Expense Per Equivalent Unit Of Production Or Per Dollar Of Gross Revenue [Line Items] | ||
Impairment Expense | $ 700 |
Exploration Expense - Additiona
Exploration Expense - Additional Information (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Exploration Expense [Line Items] | ||
Exploration Expense | $ 228 | $ 220 |
Geological and Geophysical Type Expenditures | ||
Exploration Expense [Line Items] | ||
Exploration Expense | 100 | 100 |
Delay Rentals for Non Operated Properties | ||
Exploration Expense [Line Items] | ||
Exploration Expense | $ 100 | $ 100 |
Condensed Consolidating Finan71
Condensed Consolidating Financial Information - Additional Information (Details) $ in Millions | Mar. 31, 2018USD ($) |
Condensed Financial Information Of Parent Company Only Disclosure [Abstract] | |
Senior Notes, Principal amount | $ 600.3 |
Condensed Consolidating Balance
Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
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 |
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 |
Stockholders’ Equity | ||
Preferred Stock | 1 | 1 |
Common Stock | 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 |
Eliminations | ||
Property and Equipment (Successful Efforts Method) | ||
Intercompany Receivables | (1,096,898) | (1,072,637) |
Investment in Subsidiaries – Net | 290,013 | 274,745 |
Total Assets | (806,885) | (797,892) |
Current Liabilities | ||
Intercompany Payables | (1,096,898) | (1,072,637) |
Total Liabilities | (1,096,898) | (1,072,637) |
Stockholders’ Equity | ||
Additional Paid-In Capital | (177,143) | (177,144) |
Accumulated Deficit | 467,156 | 451,889 |
Total Stockholders’ Equity | 290,013 | 274,745 |
Total Liabilities and Stockholders’ Equity | (806,885) | (797,892) |
Guarantor Subsidiaries | ||
Current Assets | ||
Cash and Cash Equivalents | 25,087 | 15,244 |
Accounts Receivable | 26,345 | 25,974 |
Short-Term Derivative Instruments | 5,891 | 8,008 |
Inventory, Prepaid Expenses and Other | 3,245 | 2,106 |
Total Current Assets | 60,568 | 51,332 |
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 |
Investment in Subsidiaries – Net | (2,805) | (2,484) |
Long-Term Derivative Instruments | 2,589 | (2) |
Total Assets | 952,267 | 933,242 |
Current Liabilities | ||
Accounts Payable | 70,394 | 62,354 |
Current Maturities of Long-Term Debt | 2,082 | 1,926 |
Accrued Liabilities | 22,478 | 32,214 |
Short-Term Derivative Instruments | 11,706 | 14,892 |
Total Current Liabilities | 106,660 | 111,386 |
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 |
Intercompany Payables | 1,092,492 | 1,068,231 |
Total Liabilities | 1,232,921 | 1,218,527 |
Stockholders’ Equity | ||
Additional Paid-In Capital | 177,143 | 177,144 |
Accumulated Deficit | (457,797) | (462,429) |
Total Stockholders’ Equity | (280,654) | (285,285) |
Total Liabilities and Stockholders’ Equity | 952,267 | 933,242 |
Non-Guarantor Subsidiaries | ||
Current Liabilities | ||
Intercompany Payables | 4,406 | 4,406 |
Total Liabilities | 4,406 | 4,406 |
Stockholders’ Equity | ||
Accumulated Deficit | (4,406) | (4,406) |
Total Stockholders’ Equity | (4,406) | (4,406) |
Parent Company | ||
Current Assets | ||
Cash and Cash Equivalents | 3 | 3 |
Accounts Receivable | 802 | |
Taxes Receivable | 48 | 2,049 |
Short-Term Derivative Instruments | 1,841 | |
Inventory, Prepaid Expenses and Other | 6,752 | 2,508 |
Total Current Assets | 9,446 | 4,560 |
Property and Equipment (Successful Efforts Method) | ||
Intercompany Receivables | 1,096,898 | 1,072,637 |
Investment in Subsidiaries – Net | (287,208) | (272,261) |
Long-Term Derivative Instruments | 291 | 1,721 |
Deferred Tax Assets - Long Term | 130 | 130 |
Total Assets | 819,557 | 806,787 |
Current Liabilities | ||
Current Maturities of Long-Term Debt | 867,115 | 832,399 |
Accrued Liabilities | 26,765 | 13,004 |
Short-Term Derivative Instruments | 52,965 | |
Total Current Liabilities | 946,845 | 845,403 |
Total Liabilities | 946,845 | 845,403 |
Stockholders’ Equity | ||
Preferred Stock | 1 | 1 |
Common Stock | 11 | 10 |
Additional Paid-In Capital | 654,534 | 652,917 |
Accumulated Deficit | (781,834) | (691,544) |
Total Stockholders’ Equity | (127,288) | (38,616) |
Total Liabilities and Stockholders’ Equity | $ 819,557 | $ 806,787 |
Condensed Consolidating Stateme
Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
OPERATING REVENUE | ||
Natural Gas, NGL and Condensate Sales | $ 65,025 | $ 52,065 |
Other Operating Revenue (Expense) | 4 | 6 |
TOTAL OPERATING REVENUE | 65,029 | 52,071 |
OPERATING EXPENSES | ||
Production and Lease Operating Expense | 33,846 | 28,934 |
General and Administrative Expense | 6,525 | 4,534 |
Loss (Gain) on Disposal of Assets | 647 | (1,834) |
Impairment Expense | 8,168 | 1,546 |
Exploration Expense | 228 | 220 |
Depreciation, Depletion, Amortization and Accretion | 15,128 | 15,468 |
Other Operating (Income) Expense | 203 | (21) |
TOTAL OPERATING EXPENSES | 64,745 | 48,847 |
INCOME FROM OPERATIONS | 284 | 3,224 |
OTHER INCOME (EXPENSE) | ||
Interest Expense | (22,647) | (9,143) |
(Loss) Gain on Derivatives, Net | (46,426) | 8,381 |
Other Expense | (1,004) | (28) |
TOTAL OTHER EXPENSE | (70,077) | (541) |
Gain on Extinguishments of Debt | 249 | |
INCOME (LOSS) BEFORE INCOME TAX | (69,793) | 2,683 |
Income Tax Benefit | 0 | 0 |
Net Income (Loss) | (69,793) | 2,683 |
NET INCOME (LOSS) | (69,793) | 2,683 |
Preferred Stock Dividends | (598) | (598) |
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | (70,391) | 2,085 |
Eliminations | ||
OTHER INCOME (EXPENSE) | ||
(Loss) Income From Equity in Consolidated Subsidiaries | (4,954) | (12,702) |
TOTAL OTHER EXPENSE | (4,954) | (12,702) |
INCOME (LOSS) BEFORE INCOME TAX | (4,954) | (12,702) |
NET INCOME (LOSS) | (4,954) | (12,702) |
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | (4,954) | (12,702) |
Guarantor Subsidiaries | ||
OPERATING REVENUE | ||
Natural Gas, NGL and Condensate Sales | 65,025 | 52,065 |
Other Operating Revenue (Expense) | 4 | 6 |
TOTAL OPERATING REVENUE | 65,029 | 52,071 |
OPERATING EXPENSES | ||
Production and Lease Operating Expense | 33,846 | 28,934 |
General and Administrative Expense | 5,506 | 4,461 |
Loss (Gain) on Disposal of Assets | 647 | (1,834) |
Impairment Expense | 8,168 | 1,546 |
Exploration Expense | 228 | 220 |
Depreciation, Depletion, Amortization and Accretion | 15,128 | 15,468 |
Other Operating (Income) Expense | 203 | (21) |
TOTAL OPERATING EXPENSES | 63,726 | 48,774 |
INCOME FROM OPERATIONS | 1,303 | 3,297 |
OTHER INCOME (EXPENSE) | ||
Interest Expense | (670) | (365) |
(Loss) Gain on Derivatives, Net | 5,325 | 9,798 |
Other Expense | (1,004) | (28) |
TOTAL OTHER EXPENSE | 3,651 | 9,405 |
INCOME (LOSS) BEFORE INCOME TAX | 4,954 | 12,702 |
NET INCOME (LOSS) | 4,954 | 12,702 |
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | 4,954 | 12,702 |
Parent Company | ||
OPERATING EXPENSES | ||
General and Administrative Expense | 1,019 | 73 |
TOTAL OPERATING EXPENSES | 1,019 | 73 |
INCOME FROM OPERATIONS | (1,019) | (73) |
OTHER INCOME (EXPENSE) | ||
Interest Expense | (21,977) | (8,778) |
(Loss) Gain on Derivatives, Net | (51,751) | (1,417) |
(Loss) Income From Equity in Consolidated Subsidiaries | 4,954 | 12,702 |
TOTAL OTHER EXPENSE | (68,774) | 2,756 |
Gain on Extinguishments of Debt | 249 | |
INCOME (LOSS) BEFORE INCOME TAX | (69,793) | 2,683 |
NET INCOME (LOSS) | (69,793) | 2,683 |
Preferred Stock Dividends | (598) | (598) |
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ (70,391) | $ 2,085 |
Condensed Consolidating State74
Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net Income (Loss) | $ (69,793) | $ 2,683 |
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) 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 |
Impairment Expense | 8,168 | 1,546 |
Non-cash Interest Expense | 4,161 | |
Loss (Gain) on Disposal of Assets | 647 | (1,834) |
Non-cash Interest Expense | 4,161 | 6,081 |
Other Non-Cash (Income) Expense | 380 | |
Non-cash Exploration Expenses | 11 | |
Gain on Extinguishments of Debt | (249) | |
Non-cash Interest Expense | 6,081 | |
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 Loans and Other Notes Payable | (460) | (131) |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES | 30,095 | (7,698) |
Repayments of Long-Term Debt and Line of Credit | (28,500) | |
Debt Issuance Costs | (567) | |
NET INCREASE IN CASH | 9,843 | 1,378 |
CASH – BEGINNING | 15,247 | 3,697 |
CASH – ENDING | 25,090 | 5,075 |
Eliminations | ||
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net Income (Loss) | (4,954) | (12,702) |
Changes in operating assets and liabilities | ||
NET CASH PROVIDED BY OPERATING ACTIVITIES | (4,954) | (12,702) |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Intercompany loans to subsidiaries | 4,954 | 12,702 |
NET CASH USED IN INVESTING ACTIVITIES | 4,954 | 12,702 |
Guarantor Subsidiaries | ||
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net Income (Loss) | 4,954 | 12,702 |
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities | ||
Depreciation, Depletion, Amortization and Accretion | 15,128 | 15,468 |
Loss (Gain) on Derivatives | (5,325) | (9,798) |
Cash Settlements of Derivatives | (2,009) | (3,443) |
Equity-based Compensation Expense | (1) | 11 |
Impairment Expense | 8,168 | 1,546 |
Loss (Gain) on Disposal of Assets | 647 | (1,834) |
Other Non-Cash (Income) Expense | 380 | |
Non-cash Exploration Expenses | 11 | |
Other Non-cash (Income) Expense | (66) | |
Changes in operating assets and liabilities | ||
Accounts Receivable | 96 | 5,174 |
Inventory, Prepaid Expenses and Other Assets | (1,610) | 410 |
Accounts Payable and Accrued Liabilities | 12,992 | (8,298) |
Other Assets and Liabilities | (89) | (139) |
NET CASH PROVIDED BY OPERATING ACTIVITIES | 33,331 | 11,744 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Intercompany loans to subsidiaries | 23,143 | (8,789) |
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 | (23,027) | (10,235) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Repayments of Loans and Other Notes Payable | (460) | (131) |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES | (460) | (131) |
NET INCREASE IN CASH | 9,843 | 1,378 |
CASH – BEGINNING | 15,244 | 3,694 |
CASH – ENDING | 25,087 | 5,072 |
Parent Company | ||
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net Income (Loss) | (69,793) | 2,683 |
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities | ||
Loss (Gain) on Derivatives | 51,751 | 1,417 |
Equity-based Compensation Expense | 1,019 | 60 |
Non-cash Interest Expense | 4,161 | |
Gain on Extinguishments of Debt | (249) | |
Non-cash Interest Expense | 6,081 | |
Changes in operating assets and liabilities | ||
Accounts Receivable | 167 | |
Taxes Receivable | 2,001 | |
Inventory, Prepaid Expenses and Other Assets | (4,243) | 12 |
Accounts Payable and Accrued Liabilities | 12,645 | 1,309 |
NET CASH PROVIDED BY OPERATING ACTIVITIES | (2,459) | 11,480 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Intercompany loans to subsidiaries | (28,097) | (3,913) |
NET CASH USED IN INVESTING ACTIVITIES | (28,097) | (3,913) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Proceeds from Long-Term Debt and Line of Credit, net of Discounts | 30,555 | 21,500 |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES | 30,555 | (7,567) |
Repayments of Long-Term Debt and Line of Credit | (28,500) | |
Debt Issuance Costs | (567) | |
CASH – BEGINNING | 3 | 3 |
CASH – ENDING | $ 3 | $ 3 |
Subsequent Events - Additional
Subsequent Events - Additional Information (Details) - USD ($) | Apr. 03, 2018 | Apr. 02, 2018 | May 10, 2018 | Apr. 27, 2018 | Apr. 16, 2018 | Sep. 30, 2017 | Apr. 28, 2017 |
Nasdaq Delisting | |||||||
Subsequent Event [Line Items] | |||||||
Minimum stockholders' equity required to be continued to listing with Nasdaq | $ 2,500,000 | ||||||
Secured Delayed Draw Term Loan Facility | |||||||
Subsequent Event [Line Items] | |||||||
Line of credit facility, remaining borrowing capacity | $ 156,500,000 | ||||||
Subsequent Events | |||||||
Subsequent Event [Line Items] | |||||||
Aggregate amount due under credit agreement as result of notice of acceleration | $ 255,000,000 | ||||||
Subsequent Events | Nasdaq Delisting | |||||||
Subsequent Event [Line Items] | |||||||
Reasons for Delisting from Nasdaq | 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. | ||||||
Subsequent Events | Second Lien Notes | |||||||
Subsequent Event [Line Items] | |||||||
Semiannual payment of interest | $ 0 | ||||||
Subsequent Events | Forbearance Agreements | |||||||
Subsequent Event [Line Items] | |||||||
Line of credit facility agreement date | Apr. 3, 2018 | ||||||
Subsequent Events | Second Forbearance Agreement | Secured Delayed Draw Term Loan Facility | |||||||
Subsequent Event [Line Items] | |||||||
Line of credit facility, remaining borrowing capacity | $ 34,129,754.54 | ||||||
Subsequent Events | Fourth Forbearance Agreement | Maximum | Secured Delayed Draw Term Loan Facility | |||||||
Subsequent Event [Line Items] | |||||||
Line of credit facility, additional borrowing capacity | $ 6,200,000 |