Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2016 | Nov. 20, 2016 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Sep. 30, 2016 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q3 | |
Entity Registrant Name | Titan Energy, LLC | |
Entity Central Index Key | 1,532,750 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Accelerated Filer | |
Trading Symbol | ARP | |
Entity Common Stock, Shares Outstanding | 5,416,667 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 19,309 | |
Accounts receivable | 29,177 | |
Advances to affiliates | 5,637 | |
Prepaid expenses and other | 18,513 | |
Total current assets | 72,636 | |
Property, plant and equipment, net | 760,850 | |
Other assets, net | 11,145 | $ 28,989 |
Total assets | 844,631 | |
Current liabilities: | ||
Accounts payable | 26,527 | |
Current portion of derivative liability | 5,299 | |
Derivative payable to Drilling Partnerships | 458 | |
Accrued well drilling and completion costs | 15,491 | |
Accrued interest | 1,838 | |
Accrued liabilities | 17,765 | |
Current portion of long-term debt | 30,000 | |
Total current liabilities | 97,378 | |
Long-term debt, less current portion, net | 658,222 | 1,503,427 |
Long-term derivative liability | 3,659 | |
Asset retirement obligations | 59,190 | |
Other long-term liabilities | 7,629 | |
Commitments and contingencies (Note 9) | ||
Members’ Equity/Partners’ Capital (Deficit): | ||
General partner’s interest | (31,156) | |
Common limited partners’ interests | (262,762) | |
Common shareholders’ interest | 18,183 | |
Total members’ equity/partners’ deficit | 18,553 | |
Total liabilities and members’ equity/partners’ deficit | 844,631 | |
Predecessor | ||
Current assets: | ||
Cash and cash equivalents | 1,353 | |
Accounts receivable | 63,367 | |
Current portion of derivative asset | 159,460 | |
Subscriptions receivable | 19,877 | |
Prepaid expenses and other | 22,935 | |
Total current assets | 266,992 | |
Property, plant and equipment, net | 1,191,611 | |
Goodwill and intangible assets, net | 14,095 | |
Long-term derivative asset | 198,262 | |
Other assets, net | 28,989 | |
Total assets | 1,699,949 | |
Current liabilities: | ||
Accounts payable | 49,249 | |
Advances from affiliates | 9,924 | |
Liabilities associated with drilling contracts | 21,483 | |
Derivative payable to Drilling Partnerships | 2,574 | |
Accrued well drilling and completion costs | 26,914 | |
Accrued interest | 25,436 | |
Distribution payable | 4,334 | |
Accrued liabilities | 22,086 | |
Total current liabilities | 162,000 | |
Long-term debt, less current portion, net | 1,503,427 | |
Asset retirement obligations | 113,740 | |
Other long-term liabilities | 5,410 | |
Commitments and contingencies (Note 9) | ||
Members’ Equity/Partners’ Capital (Deficit): | ||
General partner’s interest | (31,156) | |
Preferred limited partners’ interests | 188,739 | |
Common limited partners’ interests | (262,762) | |
Accumulated other comprehensive income | 19,375 | |
Total members’ equity/partners’ deficit | (84,628) | |
Total liabilities and members’ equity/partners’ deficit | 1,699,949 | |
Common Class C | Predecessor | ||
Members’ Equity/Partners’ Capital (Deficit): | ||
Class C common limited partner warrants | $ 1,176 | |
Preferred Series A | ||
Members’ Equity/Partners’ Capital (Deficit): | ||
Series A Preferred members’ interest | $ 370 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended | |
Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2015 | ||
Revenues: | ||||||
Gas and oil production | $ 18,458,000 | |||||
Well construction and completion | 1,304,000 | |||||
Gathering and processing | 418,000 | |||||
Administration and oversight | 147,000 | |||||
Well services | 1,246,000 | |||||
Gain (loss) on mark-to-market derivatives | (1,330,000) | |||||
Other, net | 192,000 | |||||
Total revenues | 20,435,000 | |||||
Costs and expenses: | ||||||
Gas and oil production | 10,522,000 | |||||
Well construction and completion | 1,134,000 | |||||
Gathering and processing | 690,000 | |||||
Well services | 515,000 | |||||
General and administrative | [1] | 4,931,000 | ||||
Depreciation, depletion and amortization | 6,021,000 | |||||
Total costs and expenses | 23,813,000 | |||||
Operating loss | (3,378,000) | |||||
Interest expense | [1] | (3,810,000) | ||||
Gain (loss) on asset sales and disposal | [1] | 10,000 | ||||
Reorganization items, net | [1] | (353,000) | ||||
Loss before income taxes | (7,531,000) | |||||
Income tax provision (benefit) - See Note 10 | 0 | |||||
Net loss | (7,531,000) | |||||
Net loss attributable to common shareholders and preferred members | (7,531,000) | |||||
Net loss attributable to common limited partners and the general partner | (7,380,000) | |||||
Allocation of net loss attributable to: | ||||||
Preferred member | (151,000) | |||||
Net loss attributable to common limited partners and the general partner | $ (7,380,000) | |||||
Common limited partners’ interest | $ (524,113,000) | |||||
General partner’s interest | $ (8,159,000) | |||||
Net loss attributable to common shareholders per share / common limited partners per unit (Note 2): | ||||||
Basic | $ (1.36) | $ (5.76) | ||||
Diluted | $ (1.36) | $ (5.76) | ||||
Weighted average shares / common limited partner units outstanding (Note 2): | ||||||
Basic | 5,417 | |||||
Diluted | 5,417 | |||||
Predecessor | ||||||
Revenues: | ||||||
Gas and oil production | $ 39,205,000 | $ 90,734,000 | $ 139,094,000 | $ 292,243,000 | ||
Well construction and completion | 18,383,000 | 23,054,000 | 19,157,000 | 63,665,000 | ||
Gathering and processing | 834,000 | 1,685,000 | 3,929,000 | 6,046,000 | ||
Administration and oversight | 313,000 | 5,495,000 | 1,263,000 | 7,301,000 | ||
Well services | 2,604,000 | 5,842,000 | 11,226,000 | 18,568,000 | ||
Gain (loss) on mark-to-market derivatives | 3,228,000 | 131,065,000 | (23,916,000) | 209,706,000 | ||
Other, net | 119,000 | 20,000 | 317,000 | 80,000 | ||
Total revenues | 64,686,000 | 257,895,000 | 151,070,000 | 597,609,000 | ||
Costs and expenses: | ||||||
Gas and oil production | 19,872,000 | 41,591,000 | 86,566,000 | 130,224,000 | ||
Well construction and completion | 15,985,000 | 20,046,000 | 16,658,000 | 55,361,000 | ||
Gathering and processing | 1,423,000 | 2,473,000 | 5,893,000 | 7,406,000 | ||
Well services | 1,025,000 | 2,398,000 | 4,677,000 | 6,735,000 | ||
General and administrative | [1] | 17,166,000 | 13,978,000 | 58,004,000 | 44,400,000 | |
Depreciation, depletion and amortization | 23,278,000 | 40,463,000 | 82,331,000 | 125,948,000 | ||
Asset impairment | 672,246,000 | 672,246,000 | ||||
Total costs and expenses | 78,749,000 | 793,195,000 | 254,129,000 | 1,042,320,000 | ||
Operating loss | (14,063,000) | (535,300,000) | (103,059,000) | (444,711,000) | ||
Interest expense | [1] | (14,928,000) | (25,192,000) | (74,587,000) | (75,105,000) | |
Gain (loss) on asset sales and disposal | [1] | 14,000 | (362,000) | (479,000) | (276,000) | |
Gain on early extinguishment of debt | [1] | 26,498,000 | ||||
Reorganization items, net | [1] | (16,614,000) | (16,614,000) | |||
Other loss | [1] | (3,033,000) | (9,189,000) | |||
Loss before income taxes | (48,624,000) | (560,854,000) | (177,430,000) | (520,092,000) | ||
Net loss | (48,624,000) | (560,854,000) | (177,430,000) | (520,092,000) | ||
Preferred member / limited partner dividends | (4,293,000) | (4,013,000) | (12,180,000) | |||
Net loss attributable to common limited partners and the general partner | (48,624,000) | (565,147,000) | (181,443,000) | (532,272,000) | ||
Allocation of net loss attributable to: | ||||||
Net loss attributable to common limited partners and the general partner | (48,624,000) | (565,147,000) | (181,443,000) | (532,272,000) | ||
Common limited partners’ interest | (47,651,000) | (553,844,000) | (177,814,000) | (524,113,000) | ||
General partner’s interest | $ (973,000) | $ (11,303,000) | $ (3,629,000) | $ (8,159,000) | ||
Net loss attributable to common shareholders per share / common limited partners per unit (Note 2): | ||||||
Basic | $ (0.46) | $ (5.73) | $ (1.72) | $ (5.76) | ||
Diluted | $ (0.46) | $ (5.73) | $ (1.72) | $ (5.76) | ||
Weighted average shares / common limited partner units outstanding (Note 2): | ||||||
Basic | 104,366 | 96,660 | 102,912 | 90,943 | ||
Diluted | 104,366 | 96,660 | 102,912 | 90,943 | ||
[1] | Gain (loss) on asset sales and disposal, general and administrative expenses, reorganization items, net, gain on early extinguishment of debt, interest expense and income tax expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented. |
CONDENSED CONSOLIDATED STATEME4
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (Unaudited) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended |
Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2015 | |
Net loss | $ (7,531) | ||||
Other comprehensive loss: | |||||
Comprehensive loss attributable to common and preferred limited partners and the general partner | $ (7,531) | ||||
Predecessor | |||||
Net loss | $ (48,624) | $ (560,854) | $ (177,430) | $ (520,092) | |
Other comprehensive loss: | |||||
Reclassification adjustment for unrealized gains used to offset impairment expense | (68,021) | (68,021) | |||
Reclassification to net loss of mark-to-market gains | (1,688) | (23,927) | (10,758) | (77,048) | |
Reclassification adjustment for net reorganization gain included in net loss | (8,617) | (8,617) | |||
Total other comprehensive loss | (10,305) | (91,948) | (19,375) | (145,069) | |
Comprehensive loss attributable to common and preferred limited partners and the general partner | $ (58,929) | $ (652,802) | $ (196,805) | $ (665,161) |
CONDENSED CONSOLIDATED STATEME5
CONDENSED CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (DEFICIT) (Unaudited) - USD ($) $ in Thousands | Total | Accumulated Other Comprehensive Income | General Partners' InterestGeneral Class A | Preferred Limited Partners InterestsPreferred Class C | Preferred Limited Partners InterestsPreferred Class D | Preferred Limited Partners InterestsPreferred Class E | Common Limited Partners' Interests | Class C Common Limited Partner Warrants |
Balance (Predecessor) at Dec. 31, 2015 | $ (84,628) | $ 19,375 | $ (31,156) | $ 85,402 | $ 97,518 | $ 5,819 | $ (262,762) | $ 1,176 |
Balance (units) (Predecessor) at Dec. 31, 2015 | 2,161,445 | 3,749,986 | 4,090,328 | 256,083 | 102,160,866 | 562,497 | ||
Issuance of units | Predecessor | 204 | $ 204 | ||||||
Issuance of units (units) | Predecessor | 5,508 | 245,175 | ||||||
Net issued and unissued units under incentive plans | Predecessor | 1,160 | $ 1,160 | ||||||
Net issued and unissued units under incentive plans (units) | Predecessor | 24,679 | |||||||
Distributions payable | Predecessor | 4,330 | $ 39 | $ 637 | $ 2,205 | $ 172 | $ 1,277 | ||
Distributions paid to common and preferred limited partners and the general partner | Predecessor | (12,578) | (156) | (2,550) | (4,410) | (344) | (5,118) | ||
Distribution equivalent rights paid on unissued units under incentive plan | Predecessor | (11) | (11) | ||||||
Net income (loss) | Predecessor | (177,430) | (3,629) | 1,275 | 2,540 | 198 | (177,814) | ||
Conversion of Class C units and expiration of warrants | Predecessor | $ (84,764) | $ 85,940 | $ (1,176) | |||||
Conversion of Class C units and expiration of warrants (units) | Predecessor | (3,749,986) | 3,749,986 | (562,497) | |||||
Other comprehensive loss | Predecessor | (10,758) | (10,758) | ||||||
Cancellation of Predecessor capital (deficit) | Predecessor | 279,711 | (8,617) | $ 34,902 | $ (97,853) | $ (5,845) | $ 357,124 | ||
Cancellation of Predecessor capital (deficit) (units) | Predecessor | (2,166,953) | (4,090,328) | (256,083) | (106,743,203) | ||||
Balance (Predecessor) at Aug. 31, 2016 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 |
Balance (units) (Predecessor) at Aug. 31, 2016 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
Net income (loss) | $ (7,531) | |||||||
Balance at Sep. 30, 2016 | $ 18,553 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENT OF MEMBERS' EQUITY (Unaudited) - 1 months ended Sep. 30, 2016 - USD ($) $ in Thousands | Total | Common Stockholders' Equity | Series A Preferred Members' Equity |
Balance at Aug. 31, 2016 | $ 26,016 | $ 25,495 | $ 521 |
Balance (shares) at Aug. 31, 2016 | 5,416,667 | 1 | |
Net issued and unissued shares under incentive plans | 68 | $ 68 | |
Net loss | (7,531) | (7,380) | $ (151) |
Balance at Sep. 30, 2016 | $ 18,553 | $ 18,183 | $ 370 |
Balance (shares) at Sep. 30, 2016 | 5,416,667 | 1 |
CONDENSED CONSOLIDATED STATEME7
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 1 Months Ended | 8 Months Ended | 9 Months Ended | |
Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2015 | ||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||
Net income (loss) | $ (7,531) | |||
Adjustments to reconcile net income loss to net cash provided by operating activities: | ||||
Depreciation, depletion and amortization | 6,021 | |||
(Gain) loss on derivatives | 1,308 | |||
(Gain) loss on asset sales and disposal | (10) | |||
Non-cash compensation expense | 68 | |||
Non-cash interest expense | 2,034 | |||
Amortization of deferred financing costs and discount and premium on long-term debt | 125 | |||
Changes in operating assets and liabilities: | ||||
Accounts receivable, prepaid expenses and other | 7,888 | |||
Accounts payable and accrued liabilities | (505) | |||
Net cash provided by operating activities | 9,398 | |||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||
Capital expenditures | (5,367) | |||
Net cash used in investing activities | (5,367) | |||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||
Deferred financing costs, distribution equivalent rights and other | (150) | |||
Net cash provided by (used in) financing activities | (150) | |||
Net change in cash and cash equivalents | 3,881 | |||
Cash and cash equivalents, beginning of period | 15,428 | |||
Cash and cash equivalents, end of period | 19,309 | $ 15,428 | ||
Predecessor | ||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||
Net income (loss) | (177,430) | $ (520,092) | ||
Adjustments to reconcile net income loss to net cash provided by operating activities: | ||||
Depreciation, depletion and amortization | 82,331 | 125,948 | ||
Asset impairment | 672,246 | |||
Non-cash reorganization items | (10,312) | |||
(Gain) loss on derivatives | 7,346 | (192,447) | ||
(Gain) loss on asset sales and disposal | 479 | (190) | ||
Gain on extinguishment of debt | [1] | (26,498) | ||
Other (income) loss | 9,189 | |||
Non-cash compensation expense | 1,167 | 4,497 | ||
Provision for losses on Drilling Partnership receivables | 10,906 | |||
Valuation allowance on deferred tax asset | 1,596 | |||
Amortization of deferred financing costs and discount and premium on long-term debt | 15,385 | 13,151 | ||
Changes in operating assets and liabilities: | ||||
Monetization of derivatives | 243,552 | |||
Accounts receivable, prepaid expenses and other | 97,791 | 148,879 | ||
Accounts payable and accrued liabilities | (34,396) | (150,684) | ||
Net cash provided by operating activities | 221,106 | 101,308 | ||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||
Capital expenditures | (24,894) | (102,290) | ||
Net cash paid for acquisitions | (36,967) | |||
Other | 394 | |||
Net cash used in investing activities | (24,894) | (138,863) | ||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||
Borrowings under revolving credit facility | 135,000 | 317,841 | ||
Repayments under revolving credit facility | (291,191) | (449,754) | ||
Borrowings under second lien term loan facility | 242,500 | |||
Senior note repurchases | (5,528) | |||
Distributions paid to shareholders/unitholders | (12,578) | (119,703) | ||
Net proceeds from issuance of common limited partner units | 204 | 89,409 | ||
Net proceeds from issuance of preferred units | 6,927 | |||
Arkoma transaction adjustment | (44,893) | |||
Deferred financing costs, distribution equivalent rights and other | (8,044) | (17,601) | ||
Net cash provided by (used in) financing activities | (182,137) | 24,726 | ||
Net change in cash and cash equivalents | 14,075 | (12,829) | ||
Cash and cash equivalents, beginning of period | $ 15,428 | 1,353 | 15,247 | |
Cash and cash equivalents, end of period | $ 15,428 | $ 2,418 | ||
[1] | Gain (loss) on asset sales and disposal, general and administrative expenses, reorganization items, net, gain on early extinguishment of debt, interest expense and income tax expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented. |
Organization
Organization | 9 Months Ended |
Sep. 30, 2016 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Organization | NOTE 1 – ORGANIZATION We are an independent developer and producer of natural gas, crude oil and NGLs with operations in basins across the United States. We sponsor and manage tax-advantaged investment partnerships (the “Drilling Partnerships”), in which we coinvest, to finance a portion of our natural gas, crude oil and NGL production activities. As discussed further below, we are the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”). Unless the context otherwise requires, references to “Titan Energy, LLC,” “Titan,” “the Company,” “we,” “us,” and “our,” refer to Titan Energy, LLC and our consolidated subsidiaries (and its predecessor, where applicable). Titan Energy Management, LLC (“Titan Management”) manages us and holds our Series A Preferred Share, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity, subject to dilution as discussed below) and to appoint four of our seven directors. Titan Management is a wholly owned subsidiary of Atlas Energy Group, LLC (“Atlas Energy Group” or “ATLS”; OTC: ATLS), which is a publicly traded company. In addition to its preferred member interest in us, ATLS also holds general and limited partner interests in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, oil and NGLs, with operations primarily focused in the Eagle Ford Shale, and in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs. At September 30, 2016, we had 5,416,667 common shares representing limited liability company interests issued and outstanding. ARP Restructuring and Emergence from Chapter 11 Proceedings On July 25, 2016, ARP and certain of its subsidiaries and ATLS, solely with respect to certain sections thereof, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) lenders holding 100% of ARP’s senior secured revolving credit facility (the “First Lien Lenders”), (ii) lenders holding 100% of ARP’s second lien term loan (the “Second Lien Lenders”) and (iii) holders (the “Consenting Noteholders” and, collectively with the First Lien Lenders and the Second Lien Lenders, and their respective successors or permitted assigns that become party to the Restructuring Support Agreement, the “Restructuring Support Parties”) of approximately 80% of the aggregate principal amount outstanding of the 7.75% Senior Notes due 2021 (the “7.75% Senior Notes”) and the 9.25% Senior Notes due 2021 (the “9.25% Senior Notes” and, together with the 7.75% Senior Notes, the “Notes”) of ARP’s subsidiaries, Atlas Resource Partners Holdings, LLC and Atlas Resource Finance Corporation (together, the “Issuers”). Under the Restructuring Support Agreement, the Restructuring Support Parties agreed, subject to certain terms and conditions, to support ARP’s restructuring (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”). On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11 Filings”). The cases commenced thereby were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.” ARP operated its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords were unimpaired by the Plan and were satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms were maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business. On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred: • the First Lien Lenders received cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and became lenders under our first lien exit facility credit agreement, composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche (Refer to Note 5 – Debt for further information regarding terms and provisions). • the Second Lien Lenders received a pro rata share of our second lien exit facility credit agreement with an aggregate principal amount of $252.5 million (Refer to Note 5 – Debt for further information regarding terms and provisions). In addition, the Second Lien Lenders received a pro rata share of 10% of our common shares, subject to dilution by a management incentive plan. • holders of the Notes, in exchange for 100% of the $668 million aggregate principal amount of Notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of our common shares, subject to dilution by a management incentive plan. • all of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery. • ARP transferred all of its assets and operations to us as a new holding company and ARP dissolved. As a result, we became the successor issuer to ARP for purposes of and pursuant to Rule 12g-3 of the Securities Exchange Act of 1934, as amended • Titan Management, a wholly owned subsidiary of ATLS, received a Series A Preferred Share, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity, subject to dilution if catch-up contributions are not made with respect to future equity issuances, other than pursuant to the management incentive plan) and certain other rights as provided for in the Restructuring Support Agreement. Four of the seven initial members of the board of directors were designated by Titan Management (the “Titan Class A Directors”). For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. We have a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in our limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of us unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share. |
Basis of Presentation and Summa
Basis of Presentation and Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2016 | |
Accounting Policies [Abstract] | |
Basis of Presentation and Summary of Significant Accounting Policies | NOTE 2 – BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation The accompanying condensed consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2015 was derived from ARP’s audited financial statements, have been prepared pursuant to the rules and regulations of the SEC and are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. It is suggested that these interim condensed consolidated financial statements be read in conjunction with the financial statements and the notes thereto included in ARP’s latest Annual Report on Form 10-K though, as described below, such prior financial statements may not be comparable to our interim financial statements due to the adoption of fresh-start accounting. In management’s opinion, all adjustments necessary for a fair presentation of our and ARP’s financial position, results of operations and cash flows for the periods disclosed have been made. Certain amounts in the prior year’s financial statements have been reclassified to conform to the current year presentation due to the adoption of certain accounting standards (see Notes 2 and 5). The results of operations for the interim periods presented may not necessarily be indicative of the results of operations for the full year. In connection with ARP’s Chapter 11 filings, we were subject to the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852 Reorganizations Upon emergence from bankruptcy on the Plan Effective Date, we adopted fresh-start accounting in accordance with ASC 852, which resulted in Titan becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Plan Effective Date, which differed materially from the recorded values of ARP’s assets and liabilities as reflected in ARP’s historical consolidated balance sheets. The effects of the Plan and the application of fresh-start accounting were reflected in our consolidated financial statements as of September 1, 2016 and the related adjustments thereto were recorded in our condensed consolidated statements of operations as reorganization items for the predecessor period January 1 to August 31, 2016. As a result, our condensed consolidated balance sheet and condensed consolidated statement of operations subsequent to the Plan Effective Date will not be comparable to ARP’s condensed consolidated balance sheet and condensed consolidated statements of operations prior to the Plan Effective Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on or after September 1, 2016 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material. References to “Successor” relate to the Company on and subsequent to the Plan Effective Date. References to “Predecessor” refer to the Company prior to the Plan Effective Date. The consolidated financial statements of the Successor have been prepared assuming that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Principles of Consolidation Our condensed consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS managed operations have been identified in the condensed consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated. In accordance with established practice in the oil and gas industry, our condensed consolidated financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which we have an interest. Such interests generally approximate 30%. Our condensed consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, we calculate these items specific to our own economics. Liquidity and Capital Resources Our primary sources of liquidity are cash generated from operations, capital raised through our Drilling Partnerships, and borrowings under our credit facilities. Our primary cash requirements are operating expenses, debt service including interest, and capital expenditures. We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under our credit facilities and equity and debt offerings. Our future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on our liquidity position. In addition, challenges with our ability to raise capital through our Drilling Partnerships, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, could negatively impact our ability to remain in compliance with the covenants under our credit facilities. If we are unable to remain in compliance with the covenants under our credit facilities (as described in Note 5), absent relief from our lenders, as applicable, we may be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under our credit facilities, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit. If an event of default occurs (including if our borrowing base is redetermined below our current outstanding borrowings and we are unable to repay the deficiency or deposit additional collateral to eliminate such deficiency), or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern. We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet, meeting our debt service obligations and/or achieving cost efficiency. For example, we could pursue options such as refinancing, restructuring or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. We also continue to implement various cost saving measures to reduce our capital, operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. We will continue to be opportunistic and aggressive in managing our cost structure and, in turn, our liquidity to meet our capital and operating needs. We cannot provide any assurances that any of these efforts will be successful or will result in cost reductions or cash flows or the timing of any such cost reductions or additional cash flows. It is also possible additional adjustments to our plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets, seeking additional partners to develop our assets, and/or reducing our planned capital program. In addition, to the extent commodity prices remain low or decline further, or we experience disruptions in our longer-term access to or cost of capital, our ability to fund future capital expenditures or growth projects may be further impacted. Arkoma Acquisition On June 5, 2015, ARP acquired coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma from ATLS (the “Arkoma Acquisition”) for $31.5 million, net of purchase price adjustments, which was funded through the issuance of 6,500,000 of our Predecessor’s common limited partner units. We determined that the Arkoma Acquisition constituted a transaction between entities under common control and, accordingly, retroactively adjusted ARP’s prior period condensed consolidated financial statements assuming our Predecessor’s common limited partners participated in the net income (loss) of the Arkoma operations before the date of the transaction. In April 2015, the FASB updated the accounting guidance for earnings per unit (“EPU”) of master limited partnerships (“MLP”) applying the two-class method. The updated accounting guidance specifies that for general partner transfers (or “drop downs”) to an MLP accounted for as a transaction between entities under common control, the earnings (losses) of the transferred business before the date of the transaction should be allocated entirely to the general partner’s interest, and previously reported EPU of the limited partners should not change. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs are also required. ARP adopted this accounting guidance upon its effective date of January 1, 2016, which resulted in the following retrospective restatement to allocate the net income (loss) of the Arkoma operations before the date of the transaction entirely to our Predecessor’s general partner’s interest: Predecessor C ondensed Consolidated Statement of Operations Previously Filed Adjustment Restated Nine Months Ended September 30, 2015: Common limited partners' interest $ (521,627 ) $ (2,486 ) $ (524,113 ) General partner's interest $ (10,645 ) $ 2,486 $ (8,159 ) Net loss attributable to common limited partners per unit – basic $ (5.74 ) $ (0.02 ) $ (5.76 ) Net loss attributable to common limited partners per unit – diluted $ (5.74 ) $ (0.02 ) $ (5.76 ) Predecessor Condensed Consolidated Balance Sheet December 31, 2015: Common limited partners’ interest $ (260,276 ) $ (2,486 ) $ (262,762 ) General partners’ interest $ (33,642 ) $ 2,486 $ (31,156 ) Prior to the Arkoma Acquisition, our Predecessor’s common limited partners did not participate in the net income (loss) of the Arkoma operations. Subsequent to the Arkoma Acquisition, our Predecessor’s common limited partners participated in the net income (loss) of the Arkoma operations, which was determined after the deduction of our Predecessor’s general partner’s and preferred unitholders’ interests. Use of Estimates The preparation of our condensed consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of our condensed consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, fair value of derivative instruments, fair value of certain gas and oil properties and asset retirement obligations, and fair value of assets and liabilities in connection with the application of fresh-start accounting. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates. Predecessor’s Net Income Per Common Unit Basic net income attributable to our Predecessor’s common limited partners per unit was computed by dividing net income attributable to our Predecessor’s common limited partners, which was determined after the deduction of our Predecessor’s general partner’s and preferred unitholders’ interests, by the weighted average number of our Predecessor’s common limited partner units outstanding during the period. Net income attributable to our Predecessor’s common limited partners was determined by deducting net income attributable to participating securities, if applicable, income attributable to our Predecessor’s preferred limited partners and net income attributable to our Predecessor’s general partner’s Class A units. Our Predecessor’s general partner’s interest in net income was calculated on a quarterly basis based upon its Class A units and incentive distributions to be distributed for the quarter (see Note 10), with a priority allocation of net income to our Predecessor’s general partner’s incentive distributions, if any, in accordance with our Predecessor’s partnership agreement, and the remaining net income allocated with respect to our Predecessor’s general partner’s and limited partners’ ownership interests. Our Predecessor presented net income per unit under the two-class method for MLPs, which considers whether the incentive distributions of a MLP represent a participating security. The two-class method considers whether our Predecessor’s partnership agreement contained any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under our Predecessor’s partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management believed our Predecessor’s partnership agreement contractually limited cash distributions to available cash; therefore, undistributed earnings were not allocated to the incentive distribution rights. Unvested unit-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. Phantom unit awards, which consist of common units issuable under the terms of our long-term incentive plan, contain non-forfeitable rights to distribution equivalents. The participation rights would result in a non-contingent transfer of value each time we declare a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income per unit must be after the allocation of only net income to the phantom units on a pro-rata basis. The following is a reconciliation of net income allocated to our Predecessor’s common limited partners for purposes of calculating net income attributable to our Predecessor’s common limited partners per unit (in thousands, except unit data): Predecessor Period from July 1 – August 31, 2016 Three Months Ended September 30, 2015 Net loss $ (48,624 ) $ (560,854 ) Preferred limited partner dividends — (4,293 ) Net income (loss) attributable to common limited partners and the general partner (48,624 ) (565,147 ) Less: General partner’s interest (973 ) (11,303 ) Net loss attributable to common limited partners (47,651 ) (553,844 ) Less: Net loss attributable to participating securities – phantom units — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Basic (47,651 ) (553,844 ) Plus: Convertible preferred limited partner dividends (1) — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Diluted $ (47,651 ) $ (553,844 ) Predecessor Period from January 1 – August 31, 2016 Nine Months Ended September 30, 2015 Net loss $ (177,430 ) $ (520,092 ) Preferred limited partner dividends (4,013 ) (12,180 ) Net loss attributable to common limited partners and the general partner (181,443 ) (532,272 ) Less: General partner’s interest (3,629 ) (8,159 ) Net loss attributable to common limited partners (177,814 ) (524,113 ) Less: Net loss attributable to participating securities – phantom units — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Basic (177,814 ) (524,113 ) Plus: Convertible preferred limited partner dividends (1) — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Diluted $ (177,814 ) $ (524,113 ) (1) F Diluted net income attributable to our Predecessor’s common limited partners per unit was calculated by dividing net income attributable to our Predecessor’s common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, convertible preferred units and warrants, as calculated by the treasury stock or if converted methods, as applicable. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of our long-term incentive plan. The following table sets forth the reconciliation of our Predecessor’s weighted average number of common limited partner units used to compute basic net income attributable to our Predecessor’s common limited partners per unit with those used to compute diluted net income attributable to our Predecessor’s common limited partners per unit (in thousands): Predecessor Period from July 1, 2016 through August 31, 2016 Three Months Ended September 30, 2015 Period from January 1, 2016 through August 31, 2016 Nine Months Ended September 30, 2015 Weighted average number of common limited partner units—basic 104,366 96,660 102,912 90,943 Add effect of dilutive incentive awards (1) — — — — Add effect of dilutive convertible preferred limited partner units (2) — — — — Weighted average number of common limited partner units—diluted 104,366 96,660 102,912 90,943 (1) For the period from July 1, 2016 through August 31, 2016, the period January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015, 247,000, 274,000, 346,000 and 501,000 phantom units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. (2) For the three and nine months ended September 30, 2015, potential common limited partner units issuable upon (a) conversion of our Class C preferred units and (b) exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. As the Class D and Class E preferred units are convertible only upon a change of control event, they were not considered dilutive securities for earnings per unit purposes. Recently Issued Accounting Standards In February 2016, the FASB updated the accounting guidance related to leases. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases), initially measured at the present value of the lease payments. The updated guidance is effective for us as of January 1, 2019 and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest period presented. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed consolidated financial statements. In August 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs specific to line of credit arrangements. The updated accounting guidance allows the option of presenting deferred debt issuance costs related to line-of-credit arrangements as an asset, and subsequently amortizing over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. We adopted the updated accounting guidance effective January 1, 2016, and it did not have a material impact on our condensed consolidated financial statements. In February 2015, the FASB updated the accounting guidance related to consolidation under the variable interest entity and voting interest entity models. The updated accounting guidance modifies the consolidation guidance for variable interest entities, limited partnerships and similar legal entities. We adopted this accounting guidance upon its effective date of January 1, 2016, and it did not have a material impact on our condensed consolidated financial statements. In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. We adopted this accounting guidance on January 1, 2016, and provided enhanced disclosures, as applicable, within our condensed consolidated financial statements. In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed consolidated financial statements and our method of adoption. |
Fresh Start Accounting
Fresh Start Accounting | 9 Months Ended |
Sep. 30, 2016 | |
Reorganizations [Abstract] | |
Fresh Start Accounting | NOTE 3 – FRESH START ACCOUNTING Upon our emergence from bankruptcy, we adopted fresh-start accounting in accordance with ASC 852. We qualified for fresh-start accounting because (i) the reorganization value of our assets immediately prior to the confirmation of the Plan was less than the post-petition liabilities and allowed claims, and (ii) the holders of existing voting shares of our Predecessor received less than 50% of the voting shares of the post-emergence Successor entity. Reorganization Value : Reorganization value represents the fair value of the Successor’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after restructuring. Under fresh-start accounting, we allocated the reorganization value to our individual assets based on their estimated fair values. Our reorganization value was derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long term debt and shareholders’ equity. The estimated enterprise value of the Successor of approximately $714.3 million represents management’s best estimate of fair value on the Plan Effective Date and is within the range of value contemplated by the Bankruptcy Court in confirmation of the Plan after extensive negotiations among the Company and its creditors. We estimated the enterprise value of the Successor utilizing the discounted cash flow method. To estimate fair value utilizing the discounted cash flow method, we established an estimate of future cash flows for both our gas and oil production business and our partnership management business based on the financial projections in our disclosure statement. The financial projections for our gas and oil production business were based on our forecast, which includes a number of assumptions regarding future anticipated performance of reserves including decline curves for existing proved developed producing wells, as well as new wells brought online, commodity pricing and average realized pricing, and reductions for operating costs and general and administrative expenses. The financial projections for our partnership management business were based on our forecast, which includes a number of assumptions regarding future anticipated performance including existing fee revenue streams and future annual partnership capital fund raises, based on historical averages. A terminal value was included for the partnership management business, and was calculated using a long-term growth rate of 1% on the projected cash flows of the final year of the forecast period. The discount rates of 10% for our gas and oil production business and 12% for our partnership management business were estimated based on an after-tax weighted average cost of capital (“WACC”) derived from a comparable set of publicly-held companies reflecting the rate of return that would be expected by a market participant within each respective business. The WACC also takes into consideration a company-specific risk premium, reflecting the risk associated with the overall uncertainty of the financial projections used to estimate future cash flows. A reconciliation of the reorganization value was provided in the table below: Enterprise value $ 714,325 Plus: Cash and cash equivalents 15,428 Plus: Working capital surplus 63,222 Plus: Other liabilities 70,183 Reorganization value of Successor assets $ 863,158 Consolidated Balance Sheet The adjustments set forth in the following condensed consolidated balance sheet reflect the effect of the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh-start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions or inputs. Predecessor August 31, 2016 Reorganization Adjustments Fresh Start Adjustments Successor September 1, 2016 ASSETS Current assets: Cash and cash equivalents $ 35,688 $ (20,260 )(a) $ — $ 15,428 Accounts receivable 56,621 — (56 )(a) 56,565 Advances to affiliates 5,592 — — 5,592 Prepaid expenses and other 18,635 — — 18,635 Total current assets 116,536 (20,260 ) (56 ) 96,220 Property, plant and equipment, net 1,154,866 — (396,661 )(b) 758,205 Goodwill 13,639 — (13,639 )(c) — Other assets, net 15,773 (7,040 )(b) — 8,733 Total assets $ 1,300,814 $ (27,300 ) $ (410,356 ) $ 863,158 LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT) / MEMBERS’ EQUITY Current liabilities: Accounts payable $ 49,324 $ — $ — $ 49,324 Derivative payable to Drilling Partnerships 534 — — 534 Current portion of derivative liability 3,087 — — 3,087 Accrued well drilling and completion costs 12,322 — — 12,322 Accrued interest 3,210 (3,210 )(c) — — Accrued liabilities 18,311 — (2,774 )(d) 15,537 Current portion of long-term debt 30,000 — — 30,000 Total current liabilities 116,788 (3,210 ) (2,774 ) 110,804 Long-term debt, less current portion, net 405,809 250,346 (d) — 656,155 Long-term derivative liability 4,259 — — 4,259 Asset retirement obligations 130,935 — (72,067 )(e) 58,868 Other long-term liabilities 7,108 — (52 )(f) 7,056 Liabilities subject to compromise 915,626 (915,626 )(e) — — Commitments and contingencies (Note 9) Partners’ Capital (Deficit) / Members’ Equity: General partner’s interest $ (34,902 ) $ 34,902 (f) — — Preferred limited partners’ interests 103,698 (103,698 )(f) — — Common limited partners’ interests (357,124 ) 357,124 (f) — — Accumulated other comprehensive income 8,617 (8,617 )(f) — — Series A Preferred member’s interest — 7,230 (g) (6,709 )(g) 521 Common shareholders’ interests — 354,249 (g) (328,754 )(g) 25,495 Total partners’ deficit / members’ equity (279,711 ) 641,190 (335,463 ) 26,016 Total liabilities and partners’ deficit / members’ equity $ 1,300,814 $ (27,300 ) $ (410,356 ) $ 863,158 Reorganization Adjustments: (a) Reflects the use of cash on the Plan Effective Date from implementation of the Plan: First Lien Credit Facility deferred financing costs $ (2,525) Second Lien Credit Facility deferred financing costs (1,838) Accrued interest on old first lien credit facility (3,210) Accrued interest on old second lien credit facility (2,375) Professional fees (10,312) Total uses $ (20,260) (b) Reflects the adjustment made to record the elimination of $9.6 million of the old first lien credit facility deferred financing costs offset by the recognition of $2.5 million in additional deferred financing costs related to the new First Lien Credit Facility. (c) Reflects the payment of $3.2 million of accrued interest related to the old first lien credit facility pursuant to the Plan. (d) Reflects the incurrence of indebtedness under the Second Lien Credit Facility, which has an aggregate principal amount of $252.5 million pursuant to the Plan, and is net of deferred financing costs of $2.2 million. (e) Liabilities subject to compromise were settled as follows in accordance with the Plan: Liabilities subject to compromise (“LSTC”): 7.75% and 9.25% Senior Notes, net of debt discount and deferred financing costs $ 648,612 Old second lien credit facility, net of debt discount and deferred financing costs 234,451 Accrued interest related to the Senior Notes and old second lien credit facility 32,563 LSTC of Predecessor 915,626 Issuance of Second Lien Credit Facility (252,500) Payment of accrued interest related to the old second lien credit facility (2,375) Second Lien Credit Facility deferred financing costs reinstated 316 Gain on the settlement of LSTC $661,067 (f) Reflects the cancellation of our Predecessor’s general partner’s interest, preferred limited partners’ interests, common limited partner interests and accumulated other comprehensive income pursuant to the Plan. (g) Reflects the establishment of member’s equity following the consummation of the transactions pursuant to the Plan. Pursuant to our amended and restated limited liability company agreement, the holder of the Series A Preferred Share is entitled to 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity), subject to dilution if certain catch-up contributions are not made with respect to future equity issuances. Reflects the cumulative impact of reorganization adjustments as discussed above: Gain on liabilities subject to compromise $ 661,067 Cancellation of Predecessor's capital interests (279,711) Net cash, deferring financing costs, and other adjustments (19,877) Total impact of reorganization adjustments $361,479 Allocation of total impact of reorganization adjustments to establish members’ equity: Series A Preferred member's interest $ 7,230 Common shareholders’ interests $ 354,249 Fresh Start Accounting Adjustments: (a) Reflects the adjustment of certain accounts receivable to their estimated fair value. (b) Reflects the following adjustments made to record property, plant and equipment, net at its estimated fair value. The fair values of proved natural gas and oil properties and support equipment and other were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair value of unproved properties was the result of the excess reorganization value over the fair value of identified tangible and intangible assets and represents the value of our probable and possible drilling locations within our various acreage positions. Predecessor Fresh Start Adjustments Successor Natural gas and oil properties: Proved properties $ 3,620,371 $ (2,946,257) $ 674,114 Unproved properties 213,047 (142,783) 70,264 Support equipment and other 131,587 (117,760) 13,827 Total natural gas and oil properties 3,965,005 (3,206,800) 758,205 Accumulated depreciation, depletion and amortization (2,810,139) 2,810,139 — Property, plant and equipment, net $ 1,154,866 $ (396,661) $ 758,205 (c) Reflects the adjustment made to record the elimination of the Predecessor’s goodwill. (d) Reflects the adjustment of certain accrued liabilities to their estimated fair value. (e) Reflects the adjustment made to record asset retirement obligations at fair value. The fair value of asset retirement obligations was measured using a discounted cash flow model based on management’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. We used the discount rate consistent with the rate used for our gas and oil production business. (f) Reflects the adjustment of certain other long-term liabilities to their estimated fair value (g) Reflects the adjustment to members’ equity following the fresh start accounting adjustments. Pursuant to our LLC Agreement, the holder of the Series A Preferred Share is entitled to 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity), subject to dilution if certain catch-up contributions are not made with respect to future equity issuances. Reflects the cumulative impact of fresh start adjustments as discussed above: Property, plant, and equipment, net fair value adjustment $ (396,661) Elimination of Predecessor’s goodwill (13,639) Accounts receivable fair value adjustment (56) Other liabilities fair value adjustment 52 Accrued liabilities fair value adjustment 2,774 Asset retirement fair value adjustment 72,067 Total impact of fresh start adjustments $ (335,463) Allocation of total impact of fresh start adjustments to members’ equity: Series A Preferred member's interest $ (6,709) Common shareholders’ interest $ (328,754) Reorganization Items, net: Incremental costs incurred as a result of the Chapter 11 Filings, net gain on settlement of liabilities subject to compromise and reorganization adjustments, and net impact of fresh start adjustments are classified as “Reorganization items, net” in the Predecessor’s condensed consolidated statement of operations. The following table summarizes the reorganization items: Professional fees and other $ (33,065) Accelerated amortization of deferred financing costs (9,565) Net gain on reorganization adjustments 361,479 Net loss on fresh start adjustments (335,463) Total reorganization items, net $ (16,614) |
Property, Plant and Equipment
Property, Plant and Equipment | 9 Months Ended |
Sep. 30, 2016 | |
Property Plant And Equipment [Abstract] | |
Property, Plant and Equipment | NOTE 4 – PROPERTY, PLANT AND EQUIPMENT The following is a summary of property, plant and equipment at the dates indicated (in thousands): Successor Predecessor September 30, December 31, 2016 2015 Natural gas and oil properties: Proved properties 678,208 3,585,839 Unproved properties 74,434 213,047 Support equipment and other 13,080 130,691 Total natural gas and oil properties 765,722 3,929,577 Less – accumulated depreciation, depletion and amortization (4,872 ) (2,737,966 ) $ 760,850 $ 1,191,611 During the Successor period from September 1, 2016 through September 30, 2016, the Predecessor periods from January 1, 2016 through August 31, 2016 and the nine months ended September 30, 2015, we recognized $0.4 million, $18.7 million and $5.2 million, respectively, of non-cash property, plant and equipment additions, which was included within the changes in accounts payable and accrued liabilities on our condensed consolidated statements of cash flows. We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rate used to capitalize interest on borrowed funds during the Successor period September 1, 2016 through September 30, 2016, the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015 was 7.6%, 6.0%, 6.5%, 6.5%, and 6.4%, respectively. The aggregate amount of interest capitalized during the Successor period September 1, 2016 through September 30, 2016, the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015 was $0.7 million, $1.7 million, $6.5 million, $4.0 million, and $12.0 million, respectively. During the Successor period September 1, 2016 through September 30, 2016, the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015, $0.5 million, $1.3 million, $4.6 million, $1.6 million and $4.7 million, respectively, of accretion expense was recorded related to our asset retirement obligations within depreciation, depletion and amortization in our condensed consolidated statements of operations. For the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor recorded additional asset retirement obligation liabilities of $12.9 million in our condensed consolidated balance sheets due to the liquidation of some of our Predecessor’s Drilling Partnerships. |
Debt
Debt | 9 Months Ended |
Sep. 30, 2016 | |
Debt Disclosure [Abstract] | |
Debt | NOTE 5 – DEBT Total debt consists of the following at the dates indicated (in thousands): Successor Predecessor September 30, December 31, 2016 2015 First Lien Credit Facility $ 435,809 $ — Second Lien Credit Facility 254,534 — Old First Lien Credit Facility — 592,000 Old Second Lien Term Loan — 243,783 7.75 % Senior Notes – due 2021 — 374,619 9.25 % Senior Notes – due 2021 — 324,080 Deferred financing costs (2,121 ) (31,055 ) Total debt, net 688,222 1,503,427 Less current maturities (30,000 ) — Total long-term debt, net $ 658,222 $ 1,503,427 In April 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs. The updated accounting guidance requires that debt issuance costs be presented as a direct deduction from the associated debt obligation. We adopted this accounting guidance upon its effective date of January 1, 2016. The retrospective effect of the reclassification resulted in the following changes to our Predecessor’s balance sheet: Predecessor’s Condensed Consolidated Balance Sheet Previously Filed Adjustment Restated December 31, 2015: Other assets, net $ 60,044 $ (31,055 ) $ 28,989 Long-term debt, net $ 1,534,482 $ (31,055 ) $ 1,503,427 Cash Interest . Total cash payments for interest by us for the Successor period September 1, 2016 through September 30, 2016, the predecessor period from January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015, were $0.5 million, $53.7 million, $40.4 million and $87.7 million, respectively. There were no cash payments for interest for the predecessor period from July 1, 2016 through August 31, 2016. First Lien Credit Facility On September 1, 2016, we entered into a $440 million third amended and restated first lien credit agreement with Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent, and the lenders party thereto (the “First Lien Credit Facility”). A summary of the key provisions of the First Lien Credit Facility is as follows: • Borrowing base of a $410 million conforming reserve based tranche plus a $30 million non-conforming tranche. • Provides for the issuance of letters of credit, which reduce borrowing capacity. • The non-conforming tranche matures on May 1, 2017 and the conforming reserve-based tranche matures on August 23, 2019. • Borrowing base will be redetermined semi-annually, with additional interim re-determinations permitted under certain circumstances. The first scheduled borrowing base redetermination shall occur on May 1, 2017; provided, that a super majority of the lenders may elect, in certain circumstances, to seek an interim redetermination of the borrowing base prior to May 1, 2017. • Obligations are secured by mortgages on substantially all of our oil and gas properties and first priority security interests in substantially all of our assets and are guaranteed by certain of our material subsidiaries, and any non-guarantor subsidiaries of ours are minor. • Borrowings bear interest at our election at either LIBOR plus an applicable margin between 3.00% and 4.00% per annum or the “alternate base rate” plus an applicable margin between 2.00% and 3.00% per annum, which fluctuates based on utilization. We are also required to pay a fee of 0.50% per annum on the unused portion of the borrowing base. At September 30, 2016, the weighted average interest rate on outstanding borrowings under the First Lien Credit Facility was 5.1%. • Contains covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of our assets. • Requires us to enter into commodity hedges covering at least 80% of our expected 2019 production prior to December 31, 2017. • Requires us to maintain certain financial ratios (which will first be tested for the period ending December 31, 2016 and will use an annualized EBITDA measurement for periods prior to June 30, 2017): o Total Debt to EBITDA (each as defined in the First Lien Credit Facility) of not more than 5.00 to 1.00; o Current assets to current liabilities (each as defined in the First Lien Credit Facility) of not less than 1.00 to 1.00; o First Lien Debt to EBITDA (each as defined in the First Lien Credit Facility) of not more than 3.50 to 1.00; and o EBITDA to Interest Expense (each as defined in the First Lien Credit Facility) of not less than 2.50 to 1.00. Second Lien Credit Facility On September 1, 2016, we entered into an amended and restated second lien credit agreement with Wilmington Trust, National Association, as administrative agent, and the lenders party thereto (the “Second Lien Credit Facility”) for an aggregate principal amount of $252.5 million maturing on February 23, 2020. A summary of the key provisions of the Second Lien Credit Facility is as follows: • Until May 1, 2017, interest will be payable at a rate of 2% in cash plus paid-in-kind interest at a rate equal to the Adjusted LIBO Rate (as defined in the Second Lien Credit Facility) plus 9% per annum. During the subsequent 15-month period, cash and paid-in-kind interest will vary based on a pricing grid tied to our leverage ratio under the First Lien Credit Facility. After such 15-month period, interest will accrue at a rate equal to the Adjusted LIBO Rate plus 9% per annum and will be payable in cash. • All prepayments are subject to the following premiums, plus accrued and unpaid interest: o 4.5% of the principal amount prepaid for prepayments prior to February 23, 2017; o 2.25% of the principal amount prepaid for prepayments on or after February 23, 2017 and prior to February 23, 2018; and o no premium for prepayments on or after February 23, 2018. • Obligations are secured on a second priority basis by security interests in the same collateral securing the First Lien Credit Facility and are guaranteed by certain of our material subsidiaries, and any non-guarantor subsidiaries of ours are minor. • Contains covenants that limits our ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions, engage in other business activities, and other covenants substantially similar to those in the First Lien Credit Facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables. • Requires us to maintain certain financial ratios (the financial ratios will first be tested for the period ending December 31, 2016 and will use an annualized EBITDA measurement for periods prior to June 30, 2017): o EBITDA to Interest Expense (each as defined in the Second Lien Credit Facility) of not less than 2.50 to 1.00; o Total Leverage Ratio (as defined in the Second Lien Credit Facility) of no greater than 5.5 to 1.0 prior to December 31, 2017 and no greater than 5.0 to 1.0 thereafter; and o current assets to current liabilities (each as defined in the Second Lien Credit Facility) of not less than 1.0 to 1.0. Old First Lien Credit Facility Our Predecessor was party to a Second Amended and Restated Credit Agreement, dated as of July 31, 2013 by and among our Predecessor, the lenders from time to time party thereto, and Wells Fargo, as administrative agent, as amended, supplemented or modified from time to time (the “Old First Lien Credit Facility”), which provided for a senior secured revolving credit facility with a maximum borrowing base of $1.5 billion and was scheduled to mature in July 2018. Pursuant to the Restructuring Support Agreement, our Predecessor completed the sale of substantially all our commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the Old First Lien Credit Facility. As of August 31, 2016 under our Predecessor, the weighted average interest rate on outstanding borrowings under the Old First Lien Credit Facility was 5.5%. Pursuant to the Plan, the Old First Lien Credit Facility was replaced by the First Lien Credit Facility (see Note 1). Old Second Lien Term Loan Our Predecessor was party to a Second Lien Credit Agreement, dated as of February 23, 2015 by and among our Predecessor, the lenders from time to time party thereto, and Wilmington Trust, National Association, as administrative agent, as amended, supplemented or modified from time to time (the “Old Second Lien Term Loan”), which provided for a second lien term loan in an original principal amount of $250.0 million. As of August 31, 2016 under our Predecessor, the weighted average interest rate on outstanding borrowings under the Old Second Lien Term Loan was 10.0%. Pursuant to the Plan, the Old Second Lien Term Loan was replaced by the Second Lien Facility (see Note 1). Senior Notes In January and February 2016, our Predecessor executed transactions to repurchase $20.3 million of our 7.75% Senior Notes and $12.1 million of our 9.25% Senior Notes for $5.5 million, which included $0.6 million of interest. As a result of these transactions, our Predecessor recognized $26.5 million as gain on early extinguishment of debt, net of accelerated amortization of deferred financing costs of $0.9 million, in the condensed consolidated statement of operations for the Predecessor period from January 1, 2016 through August 31, 2016. Pursuant to the Plan, Holders of the Notes, in exchange for 100% of the $668 million aggregate principal amount of Notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of the common equity interests of us (see Note 1). |
Derivative Instruments
Derivative Instruments | 9 Months Ended |
Sep. 30, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | NOTE 6 – DERIVATIVE INSTRUMENTS We use a number of different derivative instruments, principally swaps and options, in connection with our commodity price risk management activities. We do not apply hedge accounting to any of our derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings. We enter into commodity future option contracts to achieve more predictable cash flows by hedging our exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Stock Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index, while ethane, propane, butane and iso butane contracts are priced based on the respective Mt. Belvieu price. These contracts were recorded at their fair values. Pursuant to the Restructuring Support Agreement, our Predecessor completed the sale of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the Old First Lien Credit Facility. The following table summarizes the commodity derivative activity and presentation in our condensed consolidated statements of operations for the periods indicated (in thousands): Successor Predecessor Period from September 1, 2016 through September 30, 2016 Period from July 1, 2016 through August 31, 2016 Period from January 1, 2016 through August 31, 2016 Three Months Ended September 30, 2015 Nine Months Ended September 30, 2015 Portion of settlements associated with gains (losses) previously recognized within accumulated other comprehensive income, net of prior year offsets (1)(2) $ — $ 1,688 $ 10,758 $ 23,927 $ 77,048 Portion of settlements attributable to subsequent mark to market gains (2) 283 3,996 89,041 19,555 49,680 Total cash settlements on commodity derivative contracts (2) $ 283 $ 5,684 $ 99,799 $ 43,482 $ 126,728 Gains (losses) recognized on cash settlement (3) $ (22 ) $ 10,574 $ (16,570 ) $ 10,426 $ 17,259 Gains (losses) recognized on open derivative contracts (3) (1,308 ) (7,346 ) (7,346 ) 120,639 192,447 Gains (losses) on mark-to-market derivatives $ (1,330 ) $ 3,228 $ (23,916 ) $ 131,065 $ 209,706 (1) Recognized in gas and oil production revenue. (2) Excludes the effects of the $235.3 million, net of $8.2 million in hedge monetization fees, paid directly to the First Lien Credit Facility lenders upon the sale of substantially all of our Predecessor’s commodity hedge positions on July 25, 2016 and July 26, 2016. (3) Recognized in gain (loss) on mark-to-market derivatives. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities included on our condensed consolidated balance sheets for the periods indicated (in thousands): Successor Offsetting Derivatives as of September 30, 2016 Gross Recognized Gross Net Amount Presented Current portion of derivative assets $ 2,905 $ (2,905 ) $ — Long-term portion of derivative assets 5,419 (5,419 ) — Total derivative assets $ 8,324 $ (8,324 ) $ — Current portion of derivative liabilities $ (8,204 ) $ 2,905 $ (5,299 ) Long-term portion of derivative liabilities (9,078 ) 5,419 (3,659 ) Total derivative liabilities $ (17,282 ) $ 8,324 $ (8,958 ) Predecessor Offsetting Derivatives as of December 31, 2015 Current portion of derivative assets $ 159,460 $ — $ 159,460 Long-term portion of derivative assets 198,262 — 198,262 Total derivative assets $ 357,722 $ — $ 357,722 Current portion of derivative liabilities $ — $ — $ — Long-term portion of derivative liabilities — — — Total derivative liabilities $ — $ — $ — At September 30, 2016, we had the following commodity derivatives: Type Production Volumes (1) Average (1) Fair Value Total Type (in thousands) (2) (in thousands) (2) Natural Gas – Fixed Price Swaps 2016 (3) 13,656,600 $ 2.970 $ (425 ) 2017 48,127,700 $ 3.116 $ 958 2018 47,559,300 $ 2.959 $ 1,415 $ 1,948 Crude Oil – Fixed Price Swaps 2016 (3) 301,900 $ 42.763 $ (1,856 ) 2017 1,057,900 $ 46.150 $ (5,367 ) 2018 893,500 $ 48.938 $ (3,683 ) $ (10,906 ) Total net liabilities $ (8,958 ) (1) Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels. (2) Fair value for natural gas fixed price swaps and natural gas put options are based on forward NYMEX natural gas prices, as applicable. Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable. (3) The production volumes for 2016 include the remaining three months of 2016 beginning October 1, 2016. Secured Hedge Facility At September 30, 2016, we have a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under our revolving credit facility, we are required to utilize this secured hedge facility for future commodity risk management activity for our equity production volumes within the participating Drilling Partnerships. We, as the ultimate general partner of the Drilling Partnerships, administer the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantee their obligations under it. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparties. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets. An event of default occurred under the secured hedging facility agreement upon our filing of voluntary petitions for relief under Chapter 11. The lenders under the secured hedge facility agreed to forbear from exercising remedies in respect of such event of default while the Chapter 11 Filings were pending and, upon occurrence of the effective date of the Plan contemplated by the Restructuring Support Agreement, such event of default is no longer be deemed to exist or to continue under the secured hedge facility. In addition, it will be an event of default under our First Lien Credit Facility if we, as the ultimate general partner of the Drilling Partnerships, breach an obligation governed by the secured hedge facility, and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | NOTE 7 – FAIR VALUE OF FINANCIAL INSTRUMENTS Assets and Liabilities Measured at Fair Value on a Recurring Basis We use a market approach fair value methodology to value our outstanding derivative contracts. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into the three level hierarchy (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of September 30, 2016 and December 31, 2015, all of our derivative financial instruments were classified as Level 2. Information for financial instruments measured at fair value at September 30, 2016 and December 31, 2015 was as follows (in thousands): Successor Derivatives, Fair Value, as of September 30, 2016 Level 1 Level 2 Level 3 Total Assets, gross Commodity swaps $ — $ 8,324 $ — $ 8,324 Total derivative assets, gross — 8,324 — 8,324 Liabilities, gross Commodity swaps — (17,282 ) — (17,282 ) Total derivative liabilities, gross — (17,282 ) — (17,282 ) Total derivatives, fair value, net $ — $ (8,958 ) $ — $ (8,958 ) Predecessor Derivatives, Fair Value, a s of December 31, 2015 Level 1 Level 2 Level 3 Total Assets, gross Commodity swaps $ — $ 355,329 $ — $ 355,329 Commodity puts — 2,393 — 2,393 Total derivatives, fair value, net $ — $ 357,722 $ — $ 357,722 Other Financial Instruments Our other current assets and liabilities on our condensed consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair value of our long-term debt at September 30, 2016, which consists of our First Lien Credit Facility and Second Lien Credit Facility, was $639.4 million compared with a carrying amount of $690.3 million. At September 30, 2016, the carrying value of outstanding borrowings under our First Lien Credit Facility, which bears interest at variable interest rates, approximated estimated fair value. The estimated fair value of our Second Lien Credit Facility was based upon the market approach and calculated using yields of our Second Lien Credit Facility as provided by financial institutions and thus were categorized as Level 3 values. Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis Management estimated the fair values of natural gas and oil properties transferred to our Predecessor upon liquidations of certain Drilling Partnerships (see Note 8) based on discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, our future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves and estimated salvage values using our historical experience and external estimates of recovery values. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs. Management estimated the fair value of asset retirement obligations transferred to our Predecessor upon liquidations of certain Drilling Partnerships (see Note 4) based on discounted cash flow projections using our historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future considering inflation rates, federal and state regulatory requirements, and our assumed credit-adjusted risk-free interest rate. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs. Management estimated the fair value of our enterprise value and reorganizational value of assets and liabilities upon our emergence from bankruptcy through fresh-start accounting (see Note 3) utilizing the discounted cash flow method for both our gas and oil production business and our partnership management business based on the financial projections in our disclosure statement. The resulting fair value of our equity was used to value shares issued under our incentive plan. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs. |
Certain Relationships and Relat
Certain Relationships and Related Party Transactions | 9 Months Ended |
Sep. 30, 2016 | |
Related Party Transactions [Abstract] | |
Certain Relationships and Related Party Transactions | NOTE 8 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS Relationship with ATLS . Except for our named executive officers, we do not directly employ any persons to manage or operate our business. These functions are provided by employees of ATLS and/or its affiliates. As of September 30, 2016 and December 31, 2015, we had a $5.5 million receivable and a $1.3 million payable, respectively, from/to ATLS related to the timing of funding cash accounts related to general and administrative expenses, such as payroll and benefits, which was recorded in advances to/from affiliates in the condensed consolidated balance sheets. Relationship with Drilling Partnerships. We conduct certain activities through, and a portion of our revenues are attributable to, sponsorship of the Drilling Partnerships. We serve as general partner and operator of the Drilling Partnerships and assume customary rights and obligations for the Drilling Partnerships. As the general partner, we are liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if we breach our responsibilities with respect to the operations of the Drilling Partnerships. We are entitled to receive management fees, reimbursement for administrative costs incurred and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements. In March 2016, our Predecessor transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred by our Predecessor to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program. In June 2016, our Predecessor transferred $5.2 million of funds to certain of the Drilling Partnerships that were projected to make monthly or quarterly distributions to their limited partners over the next several months and/or quarters to ensure accessible distribution funding coverage in accordance with the respective Drilling Partnerships’ operations and partnership agreements in the event our Predecessor experienced a prolonged restructuring period as we perform all administrative and management functions for the Drilling Partnerships. On July 26, 2016, we adopted certain amendments to the Drilling Partnerships’ partnership agreements, in accordance with our ability to amend the Drilling Partnerships’ partnership agreements to cure an ambiguity in or correct or supplement any provision of the Drilling Partnerships’ partnership agreements as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the Chapter 11 Filings, with respect to the managing general partner will not cause the managing general partner to cease to serve as the managing general partner of the Drilling Partnerships nor cause the termination of the Drilling Partnerships. We intend to continue to fund the Drilling Partnerships’ operations and obligations, as necessary, until they are liquidated. Depending on commodity pricing and each of the Drilling Partnerships’ reserves value, we expect to realize all outstanding receivables from the Drilling Partnerships’ through the receipt of cash flows from their operations and/or the transfer of net assets and liabilities to us upon their liquidation. During the predecessor period from January 1, 2016 to August 31, 2016, our Predecessor recorded $7.2 million and $12.4 million of gas and oil properties and asset retirement obligations, respectively, transferred to our Predecessor as a result of certain Drilling Partnership liquidations. The gas and oil properties and asset retirement obligations were recorded at their fair values on the respective dates of the Drilling Partnerships’ liquidation and transfer to our Predecessor (see Note 7) and resulted in a non-cash loss of $6.1 million, net of liquidation and transfer adjustments, for the predecessor period from January 1, 2016 through August 31, 2016, which was recorded in other income/(loss) in our Predecessor’s condensed consolidated statements of operations. On October 24, 2016, the Board of Directors of our subsidiary, Atlas Resources, LLC, approved our acquisition of properties in exchange for assuming all liabilities in connection with the liquidation of certain of our Drilling Partnerships. These acquisitions have an effective date of October 1, 2016. We estimate we will record approximately $31.0 million and $14.7 million of gas and oil properties and asset retirement obligations, respectively, which will result in an estimated non-cash gain of approximately $16.3 million, before any liquidation and transfer accounting adjustments, that will be recognized in the fourth quarter of 2016. During the Predecessor periods from July 1, 2016 to August 31, 2016 and January 1, 2016 to August 31, 2016, we recognized a $10.9 million provision for losses on Drilling Partnership receivables related to the write down of certain receivables to their estimated net realizable values. As of September 30, 2016 and December 31, 2015, we had trade receivables of $0.6 million and a $6.6 million, respectively, from certain of the Drilling Partnerships’, which were recorded in accounts receivable in the condensed consolidated balance sheets. As of September 30, 2016 and December 31, 2015, we had trade payables of $2.3 million and $3.0 million, respectively, to certain of the Drilling Partnerships’, which were recorded in accounts payable in the condensed consolidated balance sheets. Relationship with AGP. At the direction of ATLS, we charge direct costs, such as salaries and wages, and allocate indirect costs, such as rent and other general and administrative costs, to AGP based on the number of ATLS employees who devoted time to AGP’s activities. In addition, Anthem Securities, Inc. (“Anthem”), our wholly owned subsidiary, acted as dealer manager for AGP’s private placement offering, which was completed in June 2015. As the dealer manager, Anthem received compensation from AGP equal to a maximum of 12% of the gross proceeds of the private placement offering as selling commissions, marketing efforts, and other issuance costs. Anthem is currently acting as the dealer manager for AGP’s issuance and sale in a continuous offering of up to a maximum agreement amount of 100,000,000 common units representing limited partner interests in AGP as further described in AGP’s registration statement on Form S-1 (File No. 333-207537). AGP will pay Anthem (1) compensation equal to 3.00% of the gross proceeds of the offering (Anthem may reallow up to 1.50% of gross offering proceeds it receives as dealer manager fees to participating broker-dealers, but expects to reallow 1.25% of gross offering proceeds to participating broker-dealers); (2) 7.00% and 3.00% of aggregate gross proceeds from the sale of Class A common units and Class T common units, respectively, as sales commissions; (3) with respect to Class T common units, a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit. On November 2, 2016, AGP decided to temporarily suspend its current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. As of September 30, 2016 and December 31, 2015, we had a $0.1 million receivable and $8.7 million payable, respectively, from/to AGP related to AGP’s direct costs, indirect cost allocation and dealer manager costs, which was recorded in advances to/from affiliates in the condensed consolidated balance sheets. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2016 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | NOTE 9 – COMMITMENTS AND CONTINGENCIES General Commitments We are the ultimate managing general partner of the Drilling Partnerships and have agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. We have structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally, for Drilling Partnerships with this structure, we are not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and we may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that we do not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by us to reflect current well performance, commodity prices and production costs, among other items. Based on our historical experience, as of September 30, 2016, our management believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material. While our historical structure has varied, we have generally agreed to subordinate a portion of our share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically from 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. We periodically compare the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, we recognize subordination as an estimated reduction of our pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which we have recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, we will recognize an estimated increase in our portion of historical cumulative gas and oil net production revenue, subject to a limitation of the cumulative subordination previously recognized. For the Successor period September 1, 2016 through September 30, 2016, the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015, $0.2 million, $0.4 million, $1.0 million, $0.4 million and $1.5 million, respectively, of our gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses. As of September 30, 2016, we are committed to expend approximately $4.3 million, principally on drilling and completion expenditures. Legal Proceedings We are party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | NOTE 10 – INCOME TAXES We account for income taxes under the asset and liability method pursuant to prevailing accounting literature. Under such literature, deferred income taxes are recognized 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. We recognize the financial statement benefit of a tax position after determining that the relevant tax authority would more likely than not sustain the position following an audit under guidance contained in FASB ASC 740. For tax positions meeting a more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. Our policy is to reflect interest and penalties related to uncertain tax positions as part of the income tax expense, when and if they become applicable. We have applied this methodology to all tax positions for which the statute of limitations remains open, and there are no additions, reductions or settlements in unrecognized tax benefits during the Successor period from September 1, 2016 to September 30, 2016. We have no material uncertain tax positions as of September 30, 2016. We have evaluated the full impact of the restructuring pursuant to the pre-packaged plan of reorganization and believe the reorganization will be treated as a taxable exchange under the Internal Revenue Code. Accordingly, we will have an initial tax basis in the assets acquired equal to their respective fair market values immediately after the reorganization and no tax attributes will carryover to us as a result of the reorganization. In addition, as part of the reorganization, we have elected to be treated as a corporation for U.S. Federal and state income tax purposes. For the Successor period September 1, 2016 to September 30, 2016, we generated an operating loss but did not recognize any income tax benefit. Management has determined uncertainties exist as to the future utilization of the operating loss carryforward; therefore, has recorded a full valuation allowance against our net deferred tax asset. We are subject to income taxes in the U.S. federal jurisdiction and various states. Tax regulations within each jurisdiction are subject to the interpretations of the related tax laws and regulations and require significant judgment to apply. We are no longer subject to U.S. federal, state, and local, or non-U.S. income tax examinations by tax authorities for the years before 2013. |
Issuances of Units
Issuances of Units | 9 Months Ended |
Sep. 30, 2016 | |
Proceeds From Issuance Or Sale Of Equity [Abstract] | |
Issuances of Units | NOTE 11 – ISSUANCES OF UNITS As of the Plan Effective Date, we had 5,416,667 shares of our common equity outstanding. Titan Management holds our Series A Preferred Share, which entitles Titan Management to 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity, subject to dilution if catch-up contributions are not made with respect to future equity issuances, other than pursuant to the management incentive plan) and certain other rights as provided for in the Restructuring Support Agreement. We have a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in our limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of us unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share. On September 1, 2016, we adopted the Titan Energy, LLC Management Incentive Plan (the “MIP”) for the employees, directors and individual consultants of us and our affiliates. On October 26, 2016 the MIP was amended and restated to increase the number of shares that may be issued. The MIP permits the grant of options, phantom shares and restricted and unrestricted common shares, as well as dividend equivalent rights. Subject to adjustment in accordance with the MIP, a maximum of 655,555 common shares may be issued pursuant to awards under the MIP. Common Shares subject to forfeited awards or withheld to satisfy exercise prices or tax withholding obligations will again be available for delivery pursuant to other awards. The MIP has a term of 10 years and will be administered by the Board of Directors, which may delegate to a committee or the Company’s chief executive officer. On September 1, 2016, 138,750 common shares from the MIP were issued and vested immediately as the service inception date was the date of the Chapter 11 Filings and the service completion date was the Plan Effective Date, resulting in $0.7 million of non-cash compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 to August 31, 2016. Also on September 1, 2016, 277,917 common shares from the MIP were issued and vest 33% on each of the next three anniversaries of the date of grant, resulting in $0.1 million of non-cash compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the Successor period from September 1, 2016 to September 30, 2016. At September 30, 2016, we had $1.5 million in unrecognized compensation expense related to unvested common shares. The fair value of the common shares was determined in connection with our estimate of the equity value of the Successor utilizing the discounted cash flow method (see Notes 3 and 7). On the Plan Effective Date, all of our Predecessor’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any distribution or consideration. Our Predecessor had an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to its equity distribution agreement, our Predecessor sold from time to time through the Agents its common units representing limited partner interests of the Predecessor having an aggregate offering price of up to $100.0 million. Sales of its common units were made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the former trading market for its common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. Our Predecessor paid each of the Agents a commission, which in each case was not more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of its equity distribution agreement, our Predecessor sold common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of its common units to an Agent as principal was pursuant to the terms of a separate terms agreement between the Predecessor and such Agent. During the Predecessor period from July 1, 2016 through August 31, 2016, our Predecessor did not issue any common limited partner units under its equity distribution program. During the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor issued 245,175 common limited partner units under its equity distribution program for net proceeds of $0.2 million, net of $4,000 in commissions and offering expenses paid. During the Predecessor three months ended September 30, 2015, our Predecessor issued 5,519,110 common limited partner units under its equity distribution program for net proceeds of $18.6 million, net of $0.3 million in commissions and offering expenses paid. During the Predecessor nine months ended September 30, 2015, our Predecessor issued 8,404,934 common limited partner units under its equity distribution program for net proceeds of $40.0 million, net of $1.0 million in commissions and offering expenses paid. In August 2015, our Predecessor entered into a distribution agreement with MLV & Co. LLC (“MLV”), which it terminated and replaced in November 2015, when our Predecessor entered into a distribution agreement with MLV and FBR Capital Markets & Co. in which it sold its 8.625% Class D Cumulative Redeemable Perpetual Preferred Units (“Class D Preferred Units”) and Class E Cumulative Redeemable Perpetual Preferred Units (“Class E Preferred Units”). Under both the August 2015 ATM Agreement and the November 2015 ATM Agreement, our Predecessor did not issue any Class D Preferred units nor Class E Preferred Units under its preferred equity distribution program for the Predecessor period from January 1, 2016 through August 31, 2016. During the three and nine months ended September 30, 2015, our Predecessor issued 90,328 Class D Preferred Units and 1,083 Class E Preferred Units under its preferred equity distribution program for net proceeds of $1.0 million, net of $0.2 million in commissions and offering expenses paid. In May 2015, in connection with the Arkoma Acquisition, our Predecessor issued 6,500,000 of its common limited partner units in a public offering at a price of $7.97 per unit, yielding net proceeds of $49.7 million. Our Predecessor used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under its Old First Lien Credit Facility. In April 2015, our Predecessor issued 255,000 of its Class E Preferred Units at a public offering price of $25.00 per unit for net proceeds of $6.0 million. On March 31, 2015, to partially pay its portion of a quarterly installment related to the Eagle Ford acquisition, our Predecessor issued an additional 800,000 Class D Preferred Units to the seller at a value of $25.00 per unit. On July 31, 2016, our Predecessor’s 3,749,986 Class C Preferred Units that were issued to ATLS on July 31, 2013, were converted into 3,749,986 common units and the associated warrant issued to ATLS to purchase 562,497 of its common units expired. On July 12, 2016, our Predecessor received notification from the New York Stock Exchange (“NYSE”) that the NYSE commenced proceedings to delist its common units as a result of our failure to comply with the continued listed standards set forth in Section 802.01C of the NYSE Listed Company Manual to maintain an average closing price of $1.00 per unit over a consecutive 30 day period. Our Predecessor’s Class D Preferred Units and Class E Preferred Units were also delisted from the NYSE. Our Predecessor’s common units, Class D Preferred Units, and Class E Preferred Units began trading on the OTC market on July 13, 2016 with the ticker symbol “ARPJ” for its common units, “ARPJP” for its Class D Preferred Units, and “ARPJN” for its Class E Preferred Units. On May 12, 2016, due to the income tax ramifications of the potential options our Predecessor was considering, our Predecessor’s Board of Directors delayed the vesting date of approximately 110,000 units granted to employees, directors and officers until March 2017. The phantom units were set to vest between May 15, 2016 and August 31, 2016. The delayed vesting schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the predecessor period from January 1, 2016 through August 31, 2016. As a result of the Chapter 11 Filings, our Predecessor’s 2012 Long-Term Incentive Plan was cancelled. The remaining unrecognized compensation cost of $0.8 million was recognized upon the cancellation and was recorded in general and administrative expenses on the condensed consolidated statement of operations for the predecessor period from July 1, 2016 through August 31, 2016. |
Cash Distributions
Cash Distributions | 9 Months Ended |
Sep. 30, 2016 | |
Distributions Made To Members Or Limited Partners [Abstract] | |
Cash Distributions | NOTE 12 – CASH DISTRIBUTIONS We did not pay any distributions for the period from September 1, 2016 through September 30, 2016. Our Predecessor had a monthly cash distribution program whereby it distributed all of its available cash (as defined in its partnership agreement) for that month to its unitholders within 45 days from the month end. If our Predecessor’s common unit distributions in any quarter exceed specified target levels, ATLS received between 13% and 48% of such distributions in excess of the specified target levels. While outstanding, our Predecessor’s Class B Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 (or $0.1333 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. In July 2015, the remaining 39,654 of our Predecessor’s Class B Preferred Units were converted into common limited partner units. Our Predecessor’s Class C Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.51 (or $0.17 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. On May 5, 2016, our Predecessor’s Board of Directors elected to suspend our Predecessor’s common unit and Class C preferred distributions, beginning with the month of March of 2016, due to the continued lower commodity price environment. Our Predecessor paid quarterly distributions on its Class D Preferred Units at an annual rate of $2.15625 per unit, $0.5390625 per unit paid on a quarterly basis, or 8.625% of the $25.00 liquidation preference. Our Predecessor paid quarterly distributions on its Class E Preferred Units at an annual rate of $2.6875 per unit, or $0.671875 per unit on a quarterly basis, or 10.75% of the $25.00 liquidation preference. On June 16, 2016, our Predecessor’s Board of Directors elected to suspend its quarterly distributions on its Class D Preferred Units and its Class E Preferred Units, beginning with the second quarter 2016 distribution, due to the continued lower commodity price environment. Our Predecessor’s Class D Preferred Units and Class E Preferred Units accrued distributions of $3.4 million and $0.3 million, respectively, from April 15, 2016 through August 31, 2016. However, due to our Predecessor’s distribution suspension and our Predecessor’s recent Chapter 11 Filings, these amounts were not earned as the preferred units were cancelled without receipt of any consideration on the Plan Effective Date. During the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor paid four monthly cash distributions totaling $5.1 million to its common limited partners ($0.0125 per unit per month); $2.5 million to its Preferred Class C limited partners ($0.0125 per unit per month); and $0.2 million to its General Partner Class A holder ($0.0125 per unit per month). During our Predecessor’s nine months ended September 30, 2015, our Predecessor paid nine monthly cash distributions totaling $103.0 million to its common limited partners ($0.1966 per unit in both January and February 2015 and $0.1083 per unit in March through September 2015); $5.9 million to its Preferred Class C limited partners ($0.1966 per unit in both January and February 2015 and $0.17 per unit in March through September 2015); approximately $42,000 to its Preferred Class B limited partners ($0.1966 per unit in both January and February 2015 and $0.1333 per unit in March through July 2015); and $4.3 million to its General Partner Class A holder ($0.1966 per unit in both January and February 2015 and $0.1083 per unit in March through September 2015). During the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor paid two distributions totaling $4.4 million to its Class D Preferred units ($0.5390625 per unit) for the period October 15, 2015 through April 14, 2016. During our Predecessor’s nine months ended September 30, 2015, our Predecessor paid three distributions totaling $6.3 million to its Class D Preferred units ($0.6169270 per unit for the period October 2, 2014 through January 14, 2015 and $0.539063 per unit for the period January 15, 2015 through July 14, 2015). During the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor paid two distributions totaling $0.3 million to its Class E Preferred units ($0.671875 per unit) for the period October 15, 2015 through April 14, 2016. During our Predecessor’s nine months ended September 30, 2015, our Predecessor paid one $0.2 million distribution to its Class E Preferred units ($0.6793 per unit) for the period April 14, 2015 through July 14, 2015. |
Operating Segment Information
Operating Segment Information | 9 Months Ended |
Sep. 30, 2016 | |
Segment Reporting [Abstract] | |
Operating Segment Information | NOTE 13 – OPERATING SEGMENT INFORMATION Our operations include and our predecessor’s operations included three reportable operating segments. These operating segments reflect the way we manage and our predecessor managed our operations and make business decisions. Operating segment data for the periods indicated were as follows (in thousands): Successor Predecessor Period September 1 - 30, 2016 Period July 1 – August 31, 2016 Three Months Ended September 30, 2015 Gas and oil production: Revenues $ 17,128 $ 42,433 $ 221,799 Operating costs and expenses (10,522 ) (19,872 ) (41,591 ) Depreciation, depletion and amortization expense (5,817 ) (16,512 ) (37,079 ) Asset impairment — — (672,246 ) Segment income (loss) $ 789 $ 6,049 $ (529,117 ) Well construction and completion: Revenues $ 1,304 $ 18,383 $ 23,054 Operating costs and expenses (1,134 ) (15,985 ) (20,046 ) Segment income $ 170 $ 2,398 $ 3,008 Other partnership management: ( 1 ) Revenues $ 2,003 $ 3,870 $ 13,042 Operating costs and expenses (1,205 ) (2,448 ) (4,871 ) Depreciation, depletion and amortization expense (204 ) (6,766 ) (3,384 ) Segment income (loss) $ 594 $ (5,344 ) $ 4,787 Reconciliation of segment income (loss) to net loss: Segment income (loss): Gas and oil production $ 789 $ 6,049 $ (529,117 ) Well construction and completion 170 2,398 3,008 Other partnership management (1) 594 (5,344 ) 4,787 Total segment income (loss) 1,553 3,103 (521,322 ) General and administrative expenses ( 2 ) (4,931 ) (17,166 ) (13,978 ) Interest expense ( 2 ) (3,810 ) (14,928 ) (25,192 ) Gain on early extinguishment of debt ( 2 ) — — — Gain (loss) on asset sales and disposal ( 2 ) 10 14 (362 ) Reorganization items, net (2) (353 ) (16,614 ) — Other income (loss) ( 2 ) — (3,033 ) — Income tax expense (2) — — — Net loss $ (7,531 ) $ (48,624 ) $ (560,854 ) Reconciliation of segment revenues to total revenues: Gas and oil production $ 17,128 $ 42,433 $ 221,799 Well construction and completion 1,304 $ 18,383 23,054 Other partnership management 2,003 $ 3,870 13,042 Total revenues $ 20,435 $ 64,686 $ 257,895 Capital expenditures: Gas and oil production $ 5,464 $ 5,529 $ 31,753 Other partnership management (115 ) 496 639 Corporate and other 18 49 407 Total capital expenditures $ 5,367 $ 6,074 $ 32,799 Successor Predecessor Period September1 - September 30, 2016 Period January 1 - August 31, 2016 Nine Months Ended September 30, 2015 Gas and oil production: Revenues $ 17,128 $ 115,178 $ 501,949 Operating costs and expenses (10,522 ) (86,566 ) (130,224 ) Depreciation, depletion and amortization expense (5,817 ) (68,647 ) (116,559 ) Asset impairment — — (672,246 Segment income (loss) $ 789 $ (40,035 ) $ (417,080 ) Well construction and completion: Revenues $ 1,304 $ 19,157 $ 63,665 Operating costs and expenses (1,134 ) (16,658 ) (55,361 ) Segment income $ 170 $ 2,499 $ 8,304 Other partnership management: (1) Revenues $ 2,003 $ 16,735 $ 31,995 Operating costs and expenses (1,205 ) (10,570 ) (14,141 ) Depreciation, depletion and amortization expense (204 ) (13,684 ) (9,389 ) Segment income (loss) $ 594 $ (7,519 ) $ 8,465 Reconciliation of segment income (loss) to net loss: Segment income (loss): Gas and oil production $ 789 $ (40,035 ) $ (417,080 ) Well construction and completion 170 2,499 8,304 Other partnership management (1) 594 (7,519 ) 8,465 Total segment income (loss) 1,553 (45,055 ) (400,311 ) General and administrative expenses (2) (4,931 ) (58,004 ) (44,400 ) Interest expense (2) (3,810 ) (74,587 ) (75,105 ) Gain on early extinguishment of debt (2) — 26,498 — Gain (loss) on asset sales and disposal (2) 10 (479 ) (276) Reorganization items, net (2) (353 ) (16,614 ) — Other income (loss) (2) — (9,189 ) — Income tax expense (2) — — — Net loss $ (7,531 ) $ (177,430 ) $ (520,092 ) Reconciliation of segment revenues to total revenues: Gas and oil production $ 17,128 $ 115,178 $ 501,949 Well construction and completion 1,304 19,157 63,665 Other partnership management 2,003 16,735 31,995 Total revenues $ 20,435 $ 151,070 $ 597,609 Capital expenditures: Gas and oil production $ 5,464 $ 22,684 $ 87,986 Other partnership management (115 ) 2,046 13,433 Corporate and other 18 164 871 Total capital expenditures $ 5,367 $ 24,894 $ 102,290 (1) Includes revenues and expenses from well services, gathering and processing, administration and oversight, and other, net that do not meet the quantitative threshold for reporting segment information. (2) Gain (loss) on asset sales and disposal, general and administrative expenses, reorganization items, net, gain on early extinguishment of debt, interest expense and income tax expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented. Successor Predecessor September 30, 2016 December 31, 2015 Balance sheet: Goodwill: Well construction and completion $ — $ 6,389 Other partnership management — 7,250 Total goodwill $ — $ 13,639 Total assets: Gas and oil production $ 792,241 $ 1,551,450 Well construction and completion 730 27,039 Other partnership management 9,681 66,641 Corporate and other 41,979 54,819 Total assets $ 844,631 $ 1,699,949 |
Subsequent Events
Subsequent Events | 9 Months Ended |
Sep. 30, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | NOTE 14 – SUBSEQUENT EVENTS Partnership Liquidations . On October 24, 2016, the Board of Directors of our subsidiary, Atlas Resources, LLC, approved our acquisition of properties in exchange for assuming all liabilities in connection with the liquidation of certain of our Drilling Partnerships. These acquisitions have an effective date of October 1, 2016 (see Note 8). |
Basis of Presentation and Sum22
Basis of Presentation and Summary of Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2016 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The accompanying condensed consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2015 was derived from ARP’s audited financial statements, have been prepared pursuant to the rules and regulations of the SEC and are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. It is suggested that these interim condensed consolidated financial statements be read in conjunction with the financial statements and the notes thereto included in ARP’s latest Annual Report on Form 10-K though, as described below, such prior financial statements may not be comparable to our interim financial statements due to the adoption of fresh-start accounting. In management’s opinion, all adjustments necessary for a fair presentation of our and ARP’s financial position, results of operations and cash flows for the periods disclosed have been made. Certain amounts in the prior year’s financial statements have been reclassified to conform to the current year presentation due to the adoption of certain accounting standards (see Notes 2 and 5). The results of operations for the interim periods presented may not necessarily be indicative of the results of operations for the full year. In connection with ARP’s Chapter 11 filings, we were subject to the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852 Reorganizations Upon emergence from bankruptcy on the Plan Effective Date, we adopted fresh-start accounting in accordance with ASC 852, which resulted in Titan becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Plan Effective Date, which differed materially from the recorded values of ARP’s assets and liabilities as reflected in ARP’s historical consolidated balance sheets. The effects of the Plan and the application of fresh-start accounting were reflected in our consolidated financial statements as of September 1, 2016 and the related adjustments thereto were recorded in our condensed consolidated statements of operations as reorganization items for the predecessor period January 1 to August 31, 2016. As a result, our condensed consolidated balance sheet and condensed consolidated statement of operations subsequent to the Plan Effective Date will not be comparable to ARP’s condensed consolidated balance sheet and condensed consolidated statements of operations prior to the Plan Effective Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on or after September 1, 2016 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material. References to “Successor” relate to the Company on and subsequent to the Plan Effective Date. References to “Predecessor” refer to the Company prior to the Plan Effective Date. The consolidated financial statements of the Successor have been prepared assuming that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. |
Principles of Consolidation | Principles of Consolidation Our condensed consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS managed operations have been identified in the condensed consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated. In accordance with established practice in the oil and gas industry, our condensed consolidated financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which we have an interest. Such interests generally approximate 30%. Our condensed consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, we calculate these items specific to our own economics. |
Liquidity and Capital Resources | Liquidity and Capital Resources Our primary sources of liquidity are cash generated from operations, capital raised through our Drilling Partnerships, and borrowings under our credit facilities. Our primary cash requirements are operating expenses, debt service including interest, and capital expenditures. We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under our credit facilities and equity and debt offerings. Our future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on our liquidity position. In addition, challenges with our ability to raise capital through our Drilling Partnerships, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, could negatively impact our ability to remain in compliance with the covenants under our credit facilities. If we are unable to remain in compliance with the covenants under our credit facilities (as described in Note 5), absent relief from our lenders, as applicable, we may be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under our credit facilities, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit. If an event of default occurs (including if our borrowing base is redetermined below our current outstanding borrowings and we are unable to repay the deficiency or deposit additional collateral to eliminate such deficiency), or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern. We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet, meeting our debt service obligations and/or achieving cost efficiency. For example, we could pursue options such as refinancing, restructuring or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. We also continue to implement various cost saving measures to reduce our capital, operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. We will continue to be opportunistic and aggressive in managing our cost structure and, in turn, our liquidity to meet our capital and operating needs. We cannot provide any assurances that any of these efforts will be successful or will result in cost reductions or cash flows or the timing of any such cost reductions or additional cash flows. It is also possible additional adjustments to our plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets, seeking additional partners to develop our assets, and/or reducing our planned capital program. In addition, to the extent commodity prices remain low or decline further, or we experience disruptions in our longer-term access to or cost of capital, our ability to fund future capital expenditures or growth projects may be further impacted. |
Arkoma Acquisition | Arkoma Acquisition On June 5, 2015, ARP acquired coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma from ATLS (the “Arkoma Acquisition”) for $31.5 million, net of purchase price adjustments, which was funded through the issuance of 6,500,000 of our Predecessor’s common limited partner units. We determined that the Arkoma Acquisition constituted a transaction between entities under common control and, accordingly, retroactively adjusted ARP’s prior period condensed consolidated financial statements assuming our Predecessor’s common limited partners participated in the net income (loss) of the Arkoma operations before the date of the transaction. In April 2015, the FASB updated the accounting guidance for earnings per unit (“EPU”) of master limited partnerships (“MLP”) applying the two-class method. The updated accounting guidance specifies that for general partner transfers (or “drop downs”) to an MLP accounted for as a transaction between entities under common control, the earnings (losses) of the transferred business before the date of the transaction should be allocated entirely to the general partner’s interest, and previously reported EPU of the limited partners should not change. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs are also required. ARP adopted this accounting guidance upon its effective date of January 1, 2016, which resulted in the following retrospective restatement to allocate the net income (loss) of the Arkoma operations before the date of the transaction entirely to our Predecessor’s general partner’s interest: Predecessor C ondensed Consolidated Statement of Operations Previously Filed Adjustment Restated Nine Months Ended September 30, 2015: Common limited partners' interest $ (521,627 ) $ (2,486 ) $ (524,113 ) General partner's interest $ (10,645 ) $ 2,486 $ (8,159 ) Net loss attributable to common limited partners per unit – basic $ (5.74 ) $ (0.02 ) $ (5.76 ) Net loss attributable to common limited partners per unit – diluted $ (5.74 ) $ (0.02 ) $ (5.76 ) Predecessor Condensed Consolidated Balance Sheet December 31, 2015: Common limited partners’ interest $ (260,276 ) $ (2,486 ) $ (262,762 ) General partners’ interest $ (33,642 ) $ 2,486 $ (31,156 ) Prior to the Arkoma Acquisition, our Predecessor’s common limited partners did not participate in the net income (loss) of the Arkoma operations. Subsequent to the Arkoma Acquisition, our Predecessor’s common limited partners participated in the net income (loss) of the Arkoma operations, which was determined after the deduction of our Predecessor’s general partner’s and preferred unitholders’ interests. |
Use of Estimates | Use of Estimates The preparation of our condensed consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of our condensed consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, fair value of derivative instruments, fair value of certain gas and oil properties and asset retirement obligations, and fair value of assets and liabilities in connection with the application of fresh-start accounting. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates. |
Predecessor's Net Income Per Common Unit | Predecessor’s Net Income Per Common Unit Basic net income attributable to our Predecessor’s common limited partners per unit was computed by dividing net income attributable to our Predecessor’s common limited partners, which was determined after the deduction of our Predecessor’s general partner’s and preferred unitholders’ interests, by the weighted average number of our Predecessor’s common limited partner units outstanding during the period. Net income attributable to our Predecessor’s common limited partners was determined by deducting net income attributable to participating securities, if applicable, income attributable to our Predecessor’s preferred limited partners and net income attributable to our Predecessor’s general partner’s Class A units. Our Predecessor’s general partner’s interest in net income was calculated on a quarterly basis based upon its Class A units and incentive distributions to be distributed for the quarter (see Note 10), with a priority allocation of net income to our Predecessor’s general partner’s incentive distributions, if any, in accordance with our Predecessor’s partnership agreement, and the remaining net income allocated with respect to our Predecessor’s general partner’s and limited partners’ ownership interests. Our Predecessor presented net income per unit under the two-class method for MLPs, which considers whether the incentive distributions of a MLP represent a participating security. The two-class method considers whether our Predecessor’s partnership agreement contained any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under our Predecessor’s partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management believed our Predecessor’s partnership agreement contractually limited cash distributions to available cash; therefore, undistributed earnings were not allocated to the incentive distribution rights. Unvested unit-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. Phantom unit awards, which consist of common units issuable under the terms of our long-term incentive plan, contain non-forfeitable rights to distribution equivalents. The participation rights would result in a non-contingent transfer of value each time we declare a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income per unit must be after the allocation of only net income to the phantom units on a pro-rata basis. The following is a reconciliation of net income allocated to our Predecessor’s common limited partners for purposes of calculating net income attributable to our Predecessor’s common limited partners per unit (in thousands, except unit data): Predecessor Period from July 1 – August 31, 2016 Three Months Ended September 30, 2015 Net loss $ (48,624 ) $ (560,854 ) Preferred limited partner dividends — (4,293 ) Net income (loss) attributable to common limited partners and the general partner (48,624 ) (565,147 ) Less: General partner’s interest (973 ) (11,303 ) Net loss attributable to common limited partners (47,651 ) (553,844 ) Less: Net loss attributable to participating securities – phantom units — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Basic (47,651 ) (553,844 ) Plus: Convertible preferred limited partner dividends (1) — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Diluted $ (47,651 ) $ (553,844 ) Predecessor Period from January 1 – August 31, 2016 Nine Months Ended September 30, 2015 Net loss $ (177,430 ) $ (520,092 ) Preferred limited partner dividends (4,013 ) (12,180 ) Net loss attributable to common limited partners and the general partner (181,443 ) (532,272 ) Less: General partner’s interest (3,629 ) (8,159 ) Net loss attributable to common limited partners (177,814 ) (524,113 ) Less: Net loss attributable to participating securities – phantom units — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Basic (177,814 ) (524,113 ) Plus: Convertible preferred limited partner dividends (1) — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Diluted $ (177,814 ) $ (524,113 ) (1) F Diluted net income attributable to our Predecessor’s common limited partners per unit was calculated by dividing net income attributable to our Predecessor’s common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, convertible preferred units and warrants, as calculated by the treasury stock or if converted methods, as applicable. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of our long-term incentive plan. The following table sets forth the reconciliation of our Predecessor’s weighted average number of common limited partner units used to compute basic net income attributable to our Predecessor’s common limited partners per unit with those used to compute diluted net income attributable to our Predecessor’s common limited partners per unit (in thousands): Predecessor Period from July 1, 2016 through August 31, 2016 Three Months Ended September 30, 2015 Period from January 1, 2016 through August 31, 2016 Nine Months Ended September 30, 2015 Weighted average number of common limited partner units—basic 104,366 96,660 102,912 90,943 Add effect of dilutive incentive awards (1) — — — — Add effect of dilutive convertible preferred limited partner units (2) — — — — Weighted average number of common limited partner units—diluted 104,366 96,660 102,912 90,943 (1) For the period from July 1, 2016 through August 31, 2016, the period January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015, 247,000, 274,000, 346,000 and 501,000 phantom units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. (2) For the three and nine months ended September 30, 2015, potential common limited partner units issuable upon (a) conversion of our Class C preferred units and (b) exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. As the Class D and Class E preferred units are convertible only upon a change of control event, they were not considered dilutive securities for earnings per unit purposes. |
Recently Issued Accounting Standards | Recently Issued Accounting Standards In February 2016, the FASB updated the accounting guidance related to leases. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases), initially measured at the present value of the lease payments. The updated guidance is effective for us as of January 1, 2019 and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest period presented. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed consolidated financial statements. In August 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs specific to line of credit arrangements. The updated accounting guidance allows the option of presenting deferred debt issuance costs related to line-of-credit arrangements as an asset, and subsequently amortizing over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. We adopted the updated accounting guidance effective January 1, 2016, and it did not have a material impact on our condensed consolidated financial statements. In February 2015, the FASB updated the accounting guidance related to consolidation under the variable interest entity and voting interest entity models. The updated accounting guidance modifies the consolidation guidance for variable interest entities, limited partnerships and similar legal entities. We adopted this accounting guidance upon its effective date of January 1, 2016, and it did not have a material impact on our condensed consolidated financial statements. In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. We adopted this accounting guidance on January 1, 2016, and provided enhanced disclosures, as applicable, within our condensed consolidated financial statements. In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed consolidated financial statements and our method of adoption. |
Basis of Presentation and Sum23
Basis of Presentation and Summary of Significant Accounting Policies (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Reconciliation of Net Income | The following is a reconciliation of net income allocated to our Predecessor’s common limited partners for purposes of calculating net income attributable to our Predecessor’s common limited partners per unit (in thousands, except unit data): Predecessor Period from July 1 – August 31, 2016 Three Months Ended September 30, 2015 Net loss $ (48,624 ) $ (560,854 ) Preferred limited partner dividends — (4,293 ) Net income (loss) attributable to common limited partners and the general partner (48,624 ) (565,147 ) Less: General partner’s interest (973 ) (11,303 ) Net loss attributable to common limited partners (47,651 ) (553,844 ) Less: Net loss attributable to participating securities – phantom units — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Basic (47,651 ) (553,844 ) Plus: Convertible preferred limited partner dividends (1) — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Diluted $ (47,651 ) $ (553,844 ) Predecessor Period from January 1 – August 31, 2016 Nine Months Ended September 30, 2015 Net loss $ (177,430 ) $ (520,092 ) Preferred limited partner dividends (4,013 ) (12,180 ) Net loss attributable to common limited partners and the general partner (181,443 ) (532,272 ) Less: General partner’s interest (3,629 ) (8,159 ) Net loss attributable to common limited partners (177,814 ) (524,113 ) Less: Net loss attributable to participating securities – phantom units — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Basic (177,814 ) (524,113 ) Plus: Convertible preferred limited partner dividends (1) — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Diluted $ (177,814 ) $ (524,113 ) (1) F |
Reconciliation of Weighted Average Number of Common Limited Partner Units | The following table sets forth the reconciliation of our Predecessor’s weighted average number of common limited partner units used to compute basic net income attributable to our Predecessor’s common limited partners per unit with those used to compute diluted net income attributable to our Predecessor’s common limited partners per unit (in thousands): Predecessor Period from July 1, 2016 through August 31, 2016 Three Months Ended September 30, 2015 Period from January 1, 2016 through August 31, 2016 Nine Months Ended September 30, 2015 Weighted average number of common limited partner units—basic 104,366 96,660 102,912 90,943 Add effect of dilutive incentive awards (1) — — — — Add effect of dilutive convertible preferred limited partner units (2) — — — — Weighted average number of common limited partner units—diluted 104,366 96,660 102,912 90,943 (1) For the period from July 1, 2016 through August 31, 2016, the period January 1, 2016 through August 31, 2016 and the three and nine months ended September 30, 2015, 247,000, 274,000, 346,000 and 501,000 phantom units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. (2) For the three and nine months ended September 30, 2015, potential common limited partner units issuable upon (a) conversion of our Class C preferred units and (b) exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. As the Class D and Class E preferred units are convertible only upon a change of control event, they were not considered dilutive securities for earnings per unit purposes. |
Accounting Guidance for Earnings Per Unit (“EPU”) of Master Limited Partnerships (“MLP”) | |
Summary of Retrospective Restatement | ARP adopted this accounting guidance upon its effective date of January 1, 2016, which resulted in the following retrospective restatement to allocate the net income (loss) of the Arkoma operations before the date of the transaction entirely to our Predecessor’s general partner’s interest: Predecessor C ondensed Consolidated Statement of Operations Previously Filed Adjustment Restated Nine Months Ended September 30, 2015: Common limited partners' interest $ (521,627 ) $ (2,486 ) $ (524,113 ) General partner's interest $ (10,645 ) $ 2,486 $ (8,159 ) Net loss attributable to common limited partners per unit – basic $ (5.74 ) $ (0.02 ) $ (5.76 ) Net loss attributable to common limited partners per unit – diluted $ (5.74 ) $ (0.02 ) $ (5.76 ) Predecessor Condensed Consolidated Balance Sheet December 31, 2015: Common limited partners’ interest $ (260,276 ) $ (2,486 ) $ (262,762 ) General partners’ interest $ (33,642 ) $ 2,486 $ (31,156 ) |
Fresh Start Accounting (Tables)
Fresh Start Accounting (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Reorganizations [Abstract] | |
Schedule of Reconciliation of Reorganization Value | A reconciliation of the reorganization value was provided in the table below: Enterprise value $ 714,325 Plus: Cash and cash equivalents 15,428 Plus: Working capital surplus 63,222 Plus: Other liabilities 70,183 Reorganization value of Successor assets $ 863,158 |
Schedule of Adjustments on Consolidated Balance Sheet | The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions or inputs. Predecessor August 31, 2016 Reorganization Adjustments Fresh Start Adjustments Successor September 1, 2016 ASSETS Current assets: Cash and cash equivalents $ 35,688 $ (20,260 )(a) $ — $ 15,428 Accounts receivable 56,621 — (56 )(a) 56,565 Advances to affiliates 5,592 — — 5,592 Prepaid expenses and other 18,635 — — 18,635 Total current assets 116,536 (20,260 ) (56 ) 96,220 Property, plant and equipment, net 1,154,866 — (396,661 )(b) 758,205 Goodwill 13,639 — (13,639 )(c) — Other assets, net 15,773 (7,040 )(b) — 8,733 Total assets $ 1,300,814 $ (27,300 ) $ (410,356 ) $ 863,158 LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT) / MEMBERS’ EQUITY Current liabilities: Accounts payable $ 49,324 $ — $ — $ 49,324 Derivative payable to Drilling Partnerships 534 — — 534 Current portion of derivative liability 3,087 — — 3,087 Accrued well drilling and completion costs 12,322 — — 12,322 Accrued interest 3,210 (3,210 )(c) — — Accrued liabilities 18,311 — (2,774 )(d) 15,537 Current portion of long-term debt 30,000 — — 30,000 Total current liabilities 116,788 (3,210 ) (2,774 ) 110,804 Long-term debt, less current portion, net 405,809 250,346 (d) — 656,155 Long-term derivative liability 4,259 — — 4,259 Asset retirement obligations 130,935 — (72,067 )(e) 58,868 Other long-term liabilities 7,108 — (52 )(f) 7,056 Liabilities subject to compromise 915,626 (915,626 )(e) — — Commitments and contingencies (Note 9) Partners’ Capital (Deficit) / Members’ Equity: General partner’s interest $ (34,902 ) $ 34,902 (f) — — Preferred limited partners’ interests 103,698 (103,698 )(f) — — Common limited partners’ interests (357,124 ) 357,124 (f) — — Accumulated other comprehensive income 8,617 (8,617 )(f) — — Series A Preferred member’s interest — 7,230 (g) (6,709 )(g) 521 Common shareholders’ interests — 354,249 (g) (328,754 )(g) 25,495 Total partners’ deficit / members’ equity (279,711 ) 641,190 (335,463 ) 26,016 Total liabilities and partners’ deficit / members’ equity $ 1,300,814 $ (27,300 ) $ (410,356 ) $ 863,158 Reorganization Adjustments: (a) Reflects the use of cash on the Plan Effective Date from implementation of the Plan: First Lien Credit Facility deferred financing costs $ (2,525) Second Lien Credit Facility deferred financing costs (1,838) Accrued interest on old first lien credit facility (3,210) Accrued interest on old second lien credit facility (2,375) Professional fees (10,312) Total uses $ (20,260) (b) Reflects the adjustment made to record the elimination of $9.6 million of the old first lien credit facility deferred financing costs offset by the recognition of $2.5 million in additional deferred financing costs related to the new First Lien Credit Facility. (c) Reflects the payment of $3.2 million of accrued interest related to the old first lien credit facility pursuant to the Plan. (d) Reflects the incurrence of indebtedness under the Second Lien Credit Facility, which has an aggregate principal amount of $252.5 million pursuant to the Plan, and is net of deferred financing costs of $2.2 million. (e) Liabilities subject to compromise were settled as follows in accordance with the Plan: Liabilities subject to compromise (“LSTC”): 7.75% and 9.25% Senior Notes, net of debt discount and deferred financing costs $ 648,612 Old second lien credit facility, net of debt discount and deferred financing costs 234,451 Accrued interest related to the Senior Notes and old second lien credit facility 32,563 LSTC of Predecessor 915,626 Issuance of Second Lien Credit Facility (252,500) Payment of accrued interest related to the old second lien credit facility (2,375) Second Lien Credit Facility deferred financing costs reinstated 316 Gain on the settlement of LSTC $661,067 (f) Reflects the cancellation of our Predecessor’s general partner’s interest, preferred limited partners’ interests, common limited partner interests and accumulated other comprehensive income pursuant to the Plan. (g) Reflects the establishment of member’s equity following the consummation of the transactions pursuant to the Plan. Pursuant to our amended and restated limited liability company agreement, the holder of the Series A Preferred Share is entitled to 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity), subject to dilution if certain catch-up contributions are not made with respect to future equity issuances. Reflects the cumulative impact of reorganization adjustments as discussed above: Gain on liabilities subject to compromise $ 661,067 Cancellation of Predecessor's capital interests (279,711) Net cash, deferring financing costs, and other adjustments (19,877) Total impact of reorganization adjustments $361,479 Allocation of total impact of reorganization adjustments to establish members’ equity: Series A Preferred member's interest $ 7,230 Common shareholders’ interests $ 354,249 Fresh Start Accounting Adjustments: (a) Reflects the adjustment of certain accounts receivable to their estimated fair value. (b) Reflects the following adjustments made to record property, plant and equipment, net at its estimated fair value. The fair values of proved natural gas and oil properties and support equipment and other were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair value of unproved properties was the result of the excess reorganization value over the fair value of identified tangible and intangible assets and represents the value of our probable and possible drilling locations within our various acreage positions. Predecessor Fresh Start Adjustments Successor Natural gas and oil properties: Proved properties $ 3,620,371 $ (2,946,257) $ 674,114 Unproved properties 213,047 (142,783) 70,264 Support equipment and other 131,587 (117,760) 13,827 Total natural gas and oil properties 3,965,005 (3,206,800) 758,205 Accumulated depreciation, depletion and amortization (2,810,139) 2,810,139 — Property, plant and equipment, net $ 1,154,866 $ (396,661) $ 758,205 (c) Reflects the adjustment made to record the elimination of the Predecessor’s goodwill. (d) Reflects the adjustment of certain accrued liabilities to their estimated fair value. (e) Reflects the adjustment made to record asset retirement obligations at fair value. The fair value of asset retirement obligations was measured using a discounted cash flow model based on management’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. We used the discount rate consistent with the rate used for our gas and oil production business. (f) Reflects the adjustment of certain other long-term liabilities to their estimated fair value (g) Reflects the adjustment to members’ equity following the fresh start accounting adjustments. Pursuant to our LLC Agreement, the holder of the Series A Preferred Share is entitled to 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity), subject to dilution if certain catch-up contributions are not made with respect to future equity issuances. Reflects the cumulative impact of fresh start adjustments as discussed above: Property, plant, and equipment, net fair value adjustment $ (396,661) Elimination of Predecessor’s goodwill (13,639) Accounts receivable fair value adjustment (56) Other liabilities fair value adjustment 52 Accrued liabilities fair value adjustment 2,774 Asset retirement fair value adjustment 72,067 Total impact of fresh start adjustments $ (335,463) Allocation of total impact of fresh start adjustments to members’ equity: Series A Preferred member's interest $ (6,709) Common shareholders’ interest $ (328,754) Reorganization Items, net: Incremental costs incurred as a result of the Chapter 11 Filings, net gain on settlement of liabilities subject to compromise and reorganization adjustments, and net impact of fresh start adjustments are classified as “Reorganization items, net” in the Predecessor’s condensed consolidated statement of operations. The following table summarizes the reorganization items: Professional fees and other $ (33,065) Accelerated amortization of deferred financing costs (9,565) Net gain on reorganization adjustments 361,479 Net loss on fresh start adjustments (335,463) Total reorganization items, net $ (16,614) |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Property Plant And Equipment [Abstract] | |
Property, Plant and Equipment | The following is a summary of property, plant and equipment at the dates indicated (in thousands): Successor Predecessor September 30, December 31, 2016 2015 Natural gas and oil properties: Proved properties 678,208 3,585,839 Unproved properties 74,434 213,047 Support equipment and other 13,080 130,691 Total natural gas and oil properties 765,722 3,929,577 Less – accumulated depreciation, depletion and amortization (4,872 ) (2,737,966 ) $ 760,850 $ 1,191,611 |
Debt (Tables)
Debt (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Schedule of Long-term Debt Instruments | Total debt consists of the following at the dates indicated (in thousands): Successor Predecessor September 30, December 31, 2016 2015 First Lien Credit Facility $ 435,809 $ — Second Lien Credit Facility 254,534 — Old First Lien Credit Facility — 592,000 Old Second Lien Term Loan — 243,783 7.75 % Senior Notes – due 2021 — 374,619 9.25 % Senior Notes – due 2021 — 324,080 Deferred financing costs (2,121 ) (31,055 ) Total debt, net 688,222 1,503,427 Less current maturities (30,000 ) — Total long-term debt, net $ 658,222 $ 1,503,427 |
Accounting Guidance Related to Balance Sheet Presentation of Debt Issuance costs | Predecessor | |
Summary of Retrospective Restatement | The retrospective effect of the reclassification resulted in the following changes to our Predecessor’s balance sheet: Predecessor’s Condensed Consolidated Balance Sheet Previously Filed Adjustment Restated December 31, 2015: Other assets, net $ 60,044 $ (31,055 ) $ 28,989 Long-term debt, net $ 1,534,482 $ (31,055 ) $ 1,503,427 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Summary of Cash Settlement on Commodity Derivatives and Presentation in Partnership's Consolidated Statements of Operations | The following table summarizes the commodity derivative activity and presentation in our condensed consolidated statements of operations for the periods indicated (in thousands): Successor Predecessor Period from September 1, 2016 through September 30, 2016 Period from July 1, 2016 through August 31, 2016 Period from January 1, 2016 through August 31, 2016 Three Months Ended September 30, 2015 Nine Months Ended September 30, 2015 Portion of settlements associated with gains (losses) previously recognized within accumulated other comprehensive income, net of prior year offsets (1)(2) $ — $ 1,688 $ 10,758 $ 23,927 $ 77,048 Portion of settlements attributable to subsequent mark to market gains (2) 283 3,996 89,041 19,555 49,680 Total cash settlements on commodity derivative contracts (2) $ 283 $ 5,684 $ 99,799 $ 43,482 $ 126,728 Gains (losses) recognized on cash settlement (3) $ (22 ) $ 10,574 $ (16,570 ) $ 10,426 $ 17,259 Gains (losses) recognized on open derivative contracts (3) (1,308 ) (7,346 ) (7,346 ) 120,639 192,447 Gains (losses) on mark-to-market derivatives $ (1,330 ) $ 3,228 $ (23,916 ) $ 131,065 $ 209,706 (1) Recognized in gas and oil production revenue. (2) Excludes the effects of the $235.3 million, net of $8.2 million in hedge monetization fees, paid directly to the First Lien Credit Facility lenders upon the sale of substantially all of our Predecessor’s commodity hedge positions on July 25, 2016 and July 26, 2016. (3) Recognized in gain (loss) on mark-to-market derivatives. |
Fair Values of the Partnership's Derivative Instruments Table | The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities included on our condensed consolidated balance sheets for the periods indicated (in thousands): Successor Offsetting Derivatives as of September 30, 2016 Gross Recognized Gross Net Amount Presented Current portion of derivative assets $ 2,905 $ (2,905 ) $ — Long-term portion of derivative assets 5,419 (5,419 ) — Total derivative assets $ 8,324 $ (8,324 ) $ — Current portion of derivative liabilities $ (8,204 ) $ 2,905 $ (5,299 ) Long-term portion of derivative liabilities (9,078 ) 5,419 (3,659 ) Total derivative liabilities $ (17,282 ) $ 8,324 $ (8,958 ) Predecessor Offsetting Derivatives as of December 31, 2015 Current portion of derivative assets $ 159,460 $ — $ 159,460 Long-term portion of derivative assets 198,262 — 198,262 Total derivative assets $ 357,722 $ — $ 357,722 Current portion of derivative liabilities $ — $ — $ — Long-term portion of derivative liabilities — — — Total derivative liabilities $ — $ — $ — |
Commodity Derivative Instruments by Type Table | At September 30, 2016, we had the following commodity derivatives: Type Production Volumes (1) Average (1) Fair Value Total Type (in thousands) (2) (in thousands) (2) Natural Gas – Fixed Price Swaps 2016 (3) 13,656,600 $ 2.970 $ (425 ) 2017 48,127,700 $ 3.116 $ 958 2018 47,559,300 $ 2.959 $ 1,415 $ 1,948 Crude Oil – Fixed Price Swaps 2016 (3) 301,900 $ 42.763 $ (1,856 ) 2017 1,057,900 $ 46.150 $ (5,367 ) 2018 893,500 $ 48.938 $ (3,683 ) $ (10,906 ) Total net liabilities $ (8,958 ) (1) Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels. (2) Fair value for natural gas fixed price swaps and natural gas put options are based on forward NYMEX natural gas prices, as applicable. Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable. (3) The production volumes for 2016 include the remaining three months of 2016 beginning October 1, 2016. |
Fair Value of Financial Instr28
Fair Value of Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of Financial Instruments at Fair Value | Information for financial instruments measured at fair value at September 30, 2016 and December 31, 2015 was as follows (in thousands): Successor Derivatives, Fair Value, as of September 30, 2016 Level 1 Level 2 Level 3 Total Assets, gross Commodity swaps $ — $ 8,324 $ — $ 8,324 Total derivative assets, gross — 8,324 — 8,324 Liabilities, gross Commodity swaps — (17,282 ) — (17,282 ) Total derivative liabilities, gross — (17,282 ) — (17,282 ) Total derivatives, fair value, net $ — $ (8,958 ) $ — $ (8,958 ) Predecessor Derivatives, Fair Value, a s of December 31, 2015 Level 1 Level 2 Level 3 Total Assets, gross Commodity swaps $ — $ 355,329 $ — $ 355,329 Commodity puts — 2,393 — 2,393 Total derivatives, fair value, net $ — $ 357,722 $ — $ 357,722 |
Operating Segment Information (
Operating Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Segment Reporting [Abstract] | |
Operating Segment Data | Our operations include and our predecessor’s operations included three reportable operating segments. These operating segments reflect the way we manage and our predecessor managed our operations and make business decisions. Operating segment data for the periods indicated were as follows (in thousands): Successor Predecessor Period September 1 - 30, 2016 Period July 1 – August 31, 2016 Three Months Ended September 30, 2015 Gas and oil production: Revenues $ 17,128 $ 42,433 $ 221,799 Operating costs and expenses (10,522 ) (19,872 ) (41,591 ) Depreciation, depletion and amortization expense (5,817 ) (16,512 ) (37,079 ) Asset impairment — — (672,246 ) Segment income (loss) $ 789 $ 6,049 $ (529,117 ) Well construction and completion: Revenues $ 1,304 $ 18,383 $ 23,054 Operating costs and expenses (1,134 ) (15,985 ) (20,046 ) Segment income $ 170 $ 2,398 $ 3,008 Other partnership management: ( 1 ) Revenues $ 2,003 $ 3,870 $ 13,042 Operating costs and expenses (1,205 ) (2,448 ) (4,871 ) Depreciation, depletion and amortization expense (204 ) (6,766 ) (3,384 ) Segment income (loss) $ 594 $ (5,344 ) $ 4,787 Reconciliation of segment income (loss) to net loss: Segment income (loss): Gas and oil production $ 789 $ 6,049 $ (529,117 ) Well construction and completion 170 2,398 3,008 Other partnership management (1) 594 (5,344 ) 4,787 Total segment income (loss) 1,553 3,103 (521,322 ) General and administrative expenses ( 2 ) (4,931 ) (17,166 ) (13,978 ) Interest expense ( 2 ) (3,810 ) (14,928 ) (25,192 ) Gain on early extinguishment of debt ( 2 ) — — — Gain (loss) on asset sales and disposal ( 2 ) 10 14 (362 ) Reorganization items, net (2) (353 ) (16,614 ) — Other income (loss) ( 2 ) — (3,033 ) — Income tax expense (2) — — — Net loss $ (7,531 ) $ (48,624 ) $ (560,854 ) Reconciliation of segment revenues to total revenues: Gas and oil production $ 17,128 $ 42,433 $ 221,799 Well construction and completion 1,304 $ 18,383 23,054 Other partnership management 2,003 $ 3,870 13,042 Total revenues $ 20,435 $ 64,686 $ 257,895 Capital expenditures: Gas and oil production $ 5,464 $ 5,529 $ 31,753 Other partnership management (115 ) 496 639 Corporate and other 18 49 407 Total capital expenditures $ 5,367 $ 6,074 $ 32,799 Successor Predecessor Period September1 - September 30, 2016 Period January 1 - August 31, 2016 Nine Months Ended September 30, 2015 Gas and oil production: Revenues $ 17,128 $ 115,178 $ 501,949 Operating costs and expenses (10,522 ) (86,566 ) (130,224 ) Depreciation, depletion and amortization expense (5,817 ) (68,647 ) (116,559 ) Asset impairment — — (672,246 Segment income (loss) $ 789 $ (40,035 ) $ (417,080 ) Well construction and completion: Revenues $ 1,304 $ 19,157 $ 63,665 Operating costs and expenses (1,134 ) (16,658 ) (55,361 ) Segment income $ 170 $ 2,499 $ 8,304 Other partnership management: (1) Revenues $ 2,003 $ 16,735 $ 31,995 Operating costs and expenses (1,205 ) (10,570 ) (14,141 ) Depreciation, depletion and amortization expense (204 ) (13,684 ) (9,389 ) Segment income (loss) $ 594 $ (7,519 ) $ 8,465 Reconciliation of segment income (loss) to net loss: Segment income (loss): Gas and oil production $ 789 $ (40,035 ) $ (417,080 ) Well construction and completion 170 2,499 8,304 Other partnership management (1) 594 (7,519 ) 8,465 Total segment income (loss) 1,553 (45,055 ) (400,311 ) General and administrative expenses (2) (4,931 ) (58,004 ) (44,400 ) Interest expense (2) (3,810 ) (74,587 ) (75,105 ) Gain on early extinguishment of debt (2) — 26,498 — Gain (loss) on asset sales and disposal (2) 10 (479 ) (276) Reorganization items, net (2) (353 ) (16,614 ) — Other income (loss) (2) — (9,189 ) — Income tax expense (2) — — — Net loss $ (7,531 ) $ (177,430 ) $ (520,092 ) Reconciliation of segment revenues to total revenues: Gas and oil production $ 17,128 $ 115,178 $ 501,949 Well construction and completion 1,304 19,157 63,665 Other partnership management 2,003 16,735 31,995 Total revenues $ 20,435 $ 151,070 $ 597,609 Capital expenditures: Gas and oil production $ 5,464 $ 22,684 $ 87,986 Other partnership management (115 ) 2,046 13,433 Corporate and other 18 164 871 Total capital expenditures $ 5,367 $ 24,894 $ 102,290 (1) Includes revenues and expenses from well services, gathering and processing, administration and oversight, and other, net that do not meet the quantitative threshold for reporting segment information. (2) Gain (loss) on asset sales and disposal, general and administrative expenses, reorganization items, net, gain on early extinguishment of debt, interest expense and income tax expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented. Successor Predecessor September 30, 2016 December 31, 2015 Balance sheet: Goodwill: Well construction and completion $ — $ 6,389 Other partnership management — 7,250 Total goodwill $ — $ 13,639 Total assets: Gas and oil production $ 792,241 $ 1,551,450 Well construction and completion 730 27,039 Other partnership management 9,681 66,641 Corporate and other 41,979 54,819 Total assets $ 844,631 $ 1,699,949 |
Organization (Narrative) (Detai
Organization (Narrative) (Details) - USD ($) | Sep. 01, 2016 | Jul. 25, 2016 | Sep. 30, 2016 |
Organization [Line Items] | |||
Common shares issued | 5,416,667 | ||
Common shares outstanding | 5,416,667 | 5,416,667 | |
Percentage of notes outstanding | 100.00% | ||
Senior Notes | $ 668,000,000 | ||
Percentage of common equity interest | 90.00% | 90.00% | |
Minimum | |||
Organization [Line Items] | |||
Percentage of common stock voting rights | 67.00% | ||
First Lien Credit Facility | |||
Organization [Line Items] | |||
Line of credit facility maximum borrowing capacity | $ 440,000,000 | ||
Second Lien Term Loan | |||
Organization [Line Items] | |||
Line of credit facility maximum borrowing capacity | $ 252,500,000 | ||
Percentage of common equity interest | 10.00% | ||
Revolving Credit Facility Conforming Tranche | First Lien Credit Facility | |||
Organization [Line Items] | |||
Line of credit facility maximum borrowing capacity | $ 410,000,000 | ||
Revolving Credit Facility Nonconforming Tranche | First Lien Credit Facility | |||
Organization [Line Items] | |||
Line of credit facility maximum borrowing capacity | $ 30,000,000 | ||
Titan Energy Management, LLC | Series A Preferred Members' Equity | |||
Organization [Line Items] | |||
Percentage of preferred share | 2.00% | 2.00% | |
Atlas Resource Partners, L.P. | |||
Organization [Line Items] | |||
Aggregate principal amount outstanding | 80.00% | ||
Atlas Resource Partners, L.P. | Second Lien Term Loan | |||
Organization [Line Items] | |||
Percentage of line of credit facility | 100.00% | ||
Atlas Resource Partners, L.P. | 7.75% Senior Notes | |||
Organization [Line Items] | |||
Debt instrument interest rate stated percentage | 7.75% | ||
Atlas Resource Partners, L.P. | 9.25% Senior Notes | |||
Organization [Line Items] | |||
Debt instrument interest rate stated percentage | 9.25% | ||
Atlas Resource Partners, L.P. | First Lien Credit Facility | |||
Organization [Line Items] | |||
Percentage of line of credit facility | 100.00% |
Basis of Presentation and Sum31
Basis of Presentation and Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Millions | Jun. 05, 2015 | May 31, 2015 | Sep. 30, 2016 |
Summary Of Significant Accounting Policies [Line Items] | |||
Pro-rata share in Drilling Partnerships | 30.00% | ||
Arkoma Acquisition | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Net cash acquired | $ 31.5 | ||
Arkoma Acquisition | Predecessor | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Issuances of Partnership Units to Fund the Purchase Price | 6,500,000 | 6,500,000 |
Basis of Presentation and Sum32
Basis of Presentation and Summary of Significant Accounting Policies (Summary of Retrospective Restatement) (Details) - USD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | |
Common limited partners’ interest | $ (524,113) | ||
General partner’s interest | $ (8,159) | ||
Net loss attributable to common limited partners per unit – basic | $ (1.36) | $ (5.76) | |
Net loss attributable to common limited partners per unit – diluted | $ (1.36) | $ (5.76) | |
Common limited partners’ interests | $ (262,762) | ||
General partner’s interest | (31,156) | ||
Previously Filed | |||
Common limited partners’ interest | $ (521,627) | ||
General partner’s interest | $ (10,645) | ||
Net loss attributable to common limited partners per unit – basic | $ (5.74) | ||
Net loss attributable to common limited partners per unit – diluted | $ (5.74) | ||
Common limited partners’ interests | (260,276) | ||
General partner’s interest | (33,642) | ||
Adjustment | |||
Common limited partners’ interest | $ (2,486) | ||
General partner’s interest | $ 2,486 | ||
Net loss attributable to common limited partners per unit – basic | $ (0.02) | ||
Net loss attributable to common limited partners per unit – diluted | $ (0.02) | ||
Common limited partners’ interests | (2,486) | ||
General partner’s interest | $ 2,486 |
Basis of Presentation and Sum33
Basis of Presentation and Summary of Significant Accounting Policies (Schedule of Net Income Reconciliation) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended |
Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2015 | |
Earnings Per Share Basic [Line Items] | |||||
Net loss | $ (7,531) | ||||
Net income (loss) attributable to common limited partners and the general partner | $ (7,380) | ||||
Less: General partner’s interest | $ (8,159) | ||||
Net loss attributable to common limited partners | (524,113) | ||||
Predecessor | |||||
Earnings Per Share Basic [Line Items] | |||||
Net loss | $ (48,624) | $ (560,854) | $ (177,430) | (520,092) | |
Preferred member / limited partner dividends | (4,293) | (4,013) | (12,180) | ||
Net income (loss) attributable to common limited partners and the general partner | (48,624) | (565,147) | (181,443) | (532,272) | |
Less: General partner’s interest | (973) | (11,303) | (3,629) | (8,159) | |
Net loss attributable to common limited partners | (47,651) | (553,844) | (177,814) | (524,113) | |
Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Basic | (47,651) | (553,844) | (177,814) | (524,113) | |
Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Diluted | $ (47,651) | $ (553,844) | $ (177,814) | $ (524,113) |
Basis of Presentation and Sum34
Basis of Presentation and Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number Of Common Limited Partner Units) (Details) - shares | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended |
Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2015 | |
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items] | |||||
Weighted average number of common limited partner units—basic | 5,417,000 | ||||
Weighted average number of common limited partner units—diluted | 5,417,000 | ||||
Predecessor | |||||
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items] | |||||
Weighted average number of common limited partner units—basic | 104,366,000 | 96,660,000 | 102,912,000 | 90,943,000 | |
Weighted average number of common limited partner units—diluted | 104,366,000 | 96,660,000 | 102,912,000 | 90,943,000 | |
Predecessor | Phantom Units | |||||
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items] | |||||
Anti-dilutive securities excluded from computation of diluted earnings attributable to common limited partners outstanding units | 247,000 | 346,000 | 274,000 | 501,000 |
Fresh Start Accounting (Narrati
Fresh Start Accounting (Narrative) (Details) $ in Thousands | 9 Months Ended |
Sep. 30, 2016USD ($) | |
Fresh Start Adjustment [Line Items] | |
Threshold voting shares percentage below which existing voting shares holders should receive to qualify for fresh start accounting | 50.00% |
Enterprise value | $ 714,325 |
Partnership Management Business | |
Fresh Start Adjustment [Line Items] | |
Long term growth rate on projected cash flows | 1.00% |
Discount rate | 12.00% |
Gas and Oil Business | |
Fresh Start Adjustment [Line Items] | |
Discount rate | 10.00% |
Fresh Start Accounting - Reconc
Fresh Start Accounting - Reconciliation of Reorganization Value (Details) $ in Thousands | Sep. 30, 2016USD ($) |
Reorganizations [Abstract] | |
Enterprise value | $ 714,325 |
Plus: Cash and cash equivalents | 15,428 |
Plus: Working capital surplus | 63,222 |
Plus: Other liabilities | 70,183 |
Reorganization value of Successor assets | $ 863,158 |
Fresh Start Accounting - Consol
Fresh Start Accounting - Consolidated Balance Sheet (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 01, 2016 | Aug. 31, 2016 | ||
Predecessor, Current assets: | |||||
Predecessor, Cash and cash equivalents | $ 35,688 | ||||
Predecessor, Accounts receivable | 56,621 | ||||
Predecessor, Advances to affiliates | 5,592 | ||||
Predecessor, Prepaid expenses and other | 18,635 | ||||
Predecessor, Total current assets | 116,536 | ||||
Predecessor, Property, plant and equipment, net | $ 1,154,866 | 1,154,866 | |||
Predecessor, Goodwill | 13,639 | ||||
Predecessor, Other assets, net | 15,773 | ||||
Predecessor, Total assets | 1,300,814 | ||||
Predecessor, Current liabilities: | |||||
Predecessor, Accounts payable | 49,324 | ||||
Predecessor, Derivative payable to Drilling Partnerships | 534 | ||||
Predecessor, Current portion of derivative liability | 3,087 | ||||
Predecessor, Accrued well drilling and completion costs | 12,322 | ||||
Predecessor, Accrued interest | 3,210 | ||||
Predecessor, Accrued liabilities | 18,311 | ||||
Predecessor, Current portion of long-term debt | 30,000 | ||||
Predecessor, Total current liabilities | 116,788 | ||||
Predecessor, Long-term debt, less current portion, net | 405,809 | ||||
Predecessor, Long-term derivative liability | 4,259 | ||||
Predecessor, Asset retirement obligations | 130,935 | ||||
Predecessor, Other long-term liabilities | 7,108 | ||||
Predecessor, Liabilities subject to compromise | 915,626 | 915,626 | |||
Predecessor, Commitments and contingencies (Note 9) | 0 | ||||
Predecessor, Partners’ Capital (Deficit) / Members’ Equity: | |||||
Predecessor, General partner’s interest | (34,902) | ||||
Predecessor, Preferred limited partners’ interests | 103,698 | ||||
Predecessor, Common limited partners’ interests | (357,124) | ||||
Predecessor, Accumulated other comprehensive income | 8,617 | ||||
Predecessor, Total partners’ deficit / members’ equity | (279,711) | ||||
Predecessor, Total liabilities and partners’ deficit / members’ equity | $ 1,300,814 | ||||
Reorganization Adjustment, Current assets: | |||||
Reorganization Adjustment, Cash and cash equivalents | (20,260) | $ (20,260) | [1] | ||
Reorganization Adjustment, Total current assets | (20,260) | ||||
Reorganization Adjustment, Other assets, net | [2] | (7,040) | |||
Reorganization Adjustment, Total assets | (27,300) | ||||
Reorganization Adjustment, Current liabilities: | |||||
Reorganization Adjustment, Accrued interest | [3] | (3,210) | |||
Reorganization Adjustment, Total current liabilities | (3,210) | ||||
Reorganization Adjustment, Long-term debt, less current portion, net | [4] | 250,346 | |||
Reorganization Adjustment, Liabilities subject to compromise | [5] | (915,626) | |||
Partners’ Capital (Deficit) / Members’ Equity: | |||||
Reorganization Adjustment, General partner’s interest | [6] | 34,902 | |||
Reorganization Adjustment, Preferred limited partners’ interests | [6] | (103,698) | |||
Reorganization Adjustment, Common limited partners’ interests | [6] | 357,124 | |||
Reorganization Adjustment, Accumulated other comprehensive income | [6] | (8,617) | |||
Reorganization Adjustment, Common shareholders’ interests | 354,249 | 354,249 | [7] | ||
Reorganization Adjustment, Total partners’ deficit / members’ equity | 641,190 | ||||
Reorganization Adjustment, Total liabilities and partners’ deficit / members’ equity | (27,300) | ||||
Fresh-Start Adjustment, Current assets: | |||||
Fresh-Start Adjustment, Accounts receivable | (56) | (56) | [1] | ||
Advances to affiliates | 0 | ||||
Prepaid expenses and other | 0 | ||||
Fresh-Start Adjustment, Total current assets | (56) | ||||
Fresh-Start Adjustment, Property, plant and equipment, net | (396,661) | (396,661) | [2] | ||
Fresh-Start Adjustment, Goodwill | [3] | (13,639) | |||
Fresh-Start Adjustment, Total assets | (410,356) | ||||
Fresh-Start Adjustment, Current liabilities: | |||||
Fresh-Start Adjustment, Accrued liabilities | (2,774) | (2,774) | [4] | ||
Fresh-Start Adjustment, Total current liabilities | (2,774) | ||||
Fresh-Start Adjustment, Asset retirement obligations | (72,067) | (72,067) | [5] | ||
Fres-Start Adjustment, Other long-term liabilities | (52) | (52) | [6] | ||
Fresh-Start Adjustment, Partners’ Capital (Deficit) / Members’ Equity: | |||||
Fresh-Start Adjustment, Common shareholders’ interests | (328,754) | (328,754) | [7] | ||
Fresh-Start Adjustment, Total partners’ deficit / members’ equity | (335,463) | (335,463) | |||
Fresh-Start Adjustment, Total liabilities and partners’ deficit / members’ equity | (410,356) | ||||
Successor, Current assets: | |||||
Successor, Cash and cash equivalents | 15,428 | ||||
Successor, Accounts receivable | 56,565 | ||||
Successor, Advances to affiliates | 5,592 | ||||
Successor, Prepaid expenses and other | 18,635 | ||||
Successor, Total current assets | 96,220 | ||||
Successor, Property, plant and equipment, net | 758,205 | 758,205 | |||
Successor, Other assets, net | 8,733 | ||||
Successor, Total assets | 863,158 | ||||
Successor, Current liabilities: | |||||
Successor, Accounts payable | 49,324 | ||||
Successor, Derivative payable to Drilling Partnerships | 534 | ||||
Successor, Current portion of derivative liability | 3,087 | ||||
Successor, Accrued well drilling and completion costs | 12,322 | ||||
Successor, Accrued liabilities | 15,537 | ||||
Successor, Current portion of long-term debt | 30,000 | ||||
Successor, Total current liabilities | 110,804 | ||||
Successor, Long-term debt, less current portion, net | 656,155 | ||||
Successor, Long-term derivative liability | 4,259 | ||||
Successor, Asset retirement obligations | 58,868 | ||||
Successor, Other long-term liabilities | 7,056 | ||||
Successor, Commitments and contingencies (Note 9) | |||||
Successor, Partners’ Capital (Deficit) / Members’ Equity: | |||||
Successor, Common shareholders’ interests | 25,495 | ||||
Successor, Total partners’ deficit / members’ equity | 26,016 | ||||
Successor, Total liabilities and partners’ deficit / members’ equity | 863,158 | ||||
Series A Preferred Members' Equity | |||||
Partners’ Capital (Deficit) / Members’ Equity: | |||||
Reorganization Adjustment, Series A Preferred member’s interest | 7,230 | 7,230 | [7] | ||
Fresh-Start Adjustment, Partners’ Capital (Deficit) / Members’ Equity: | |||||
Fresh-Start Adjustment, Series A Preferred member’s interest | $ (6,709) | (6,709) | [7] | ||
Successor, Partners’ Capital (Deficit) / Members’ Equity: | |||||
Successor, Series A Preferred member’s interest | $ 521 | ||||
[1] | Reflects the use of cash on the Plan Effective Date from implementation of the Plan: First Lien Credit Facility deferred financing costs $ (2,525) Second Lien Credit Facility deferred financing costs(1,838) Accrued interest on old first lien credit facility (3,210) Accrued interest on old second lien credit facility(2,375) Professional fees(10,312) Total uses$ (20,260) | ||||
[2] | (a) Reflects the adjustment made to record the elimination of $9.6 million of the old first lien credit facility deferred financing costs offset by the recognition of $2.5 million in additional deferred financing costs related to the new First Lien Credit Facility. | ||||
[3] | (a) Reflects the payment of $3.2 million of accrued interest related to the old first lien credit facility pursuant to the Plan. | ||||
[4] | Reflects the incurrence of indebtedness under the Second Lien Credit Facility, which has an aggregate principal amount of $252.5 million pursuant to the Plan, and is net of deferred financing costs of $2.2 million. | ||||
[5] | Liabilities subject to compromise were settled as follows in accordance with the Plan: Liabilities subject to compromise (“LSTC”): 7.75% and 9.25% Senior Notes, net of debt discount and deferred financing costs$ 648,612 Old second lien credit facility, net of debt discount and deferred financing costs234,451 Accrued interest related to the Senior Notes and old second lien credit facility32,563 LSTC of Predecessor915,626 Issuance of Second Lien Credit Facility(252,500) Payment of accrued interest related to the old second lien credit facility(2,375) Second Lien Credit Facility deferred financing costs reinstated316 Gain on the settlement of LSTC$661,067 | ||||
[6] | Reflects the cancellation of our Predecessor’s general partner’s interest, preferred limited partners’ interests, common limited partner interests and accumulated other comprehensive income pursuant to the Plan. | ||||
[7] | Reflects the establishment of member’s equity following the consummation of the transactions pursuant to the Plan. Pursuant to our amended and restated limited liability company agreement, the holder of the Series A Preferred Share is entitled to 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity), subject to dilution if certain catch-up contributions are not made with respect to future equity issuances. Reflects the cumulative impact of reorganization adjustments as discussed above: Gain on liabilities subject to compromise$ 661,067 Cancellation of Predecessor's capital interests(279,711) Net cash, deferring financing costs, and other adjustments(19,877) Total impact of reorganization adjustments$361,479 Allocation of total impact of reorganization adjustments to establish members’ equity: Series A Preferred member's interest$ 7,230 Common shareholders’ interests$ 354,249 |
Fresh Start Accounting - Cons38
Fresh Start Accounting - Consolidated Balance Sheet - Reorganization Adjustments Use of Cash on the Plan Effective Date (Details) - USD ($) $ in Thousands | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 01, 2016 | |||
Fresh Start Adjustment [Line Items] | ||||
Reorganization Adjustment, Accrued interest | [1] | $ (3,210) | ||
Professional fees | $ (10,312) | |||
Reorganization Adjustment, Cash and cash equivalents | (20,260) | $ (20,260) | [2] | |
First Lien Credit Facility | ||||
Fresh Start Adjustment [Line Items] | ||||
Reorganization adjustment, increase (decrease), deferred financing costs | (2,525) | |||
Second Lien Credit Facility | ||||
Fresh Start Adjustment [Line Items] | ||||
Reorganization adjustment, increase (decrease), deferred financing costs | (1,838) | |||
Old First Lien Credit Facility | ||||
Fresh Start Adjustment [Line Items] | ||||
Reorganization adjustment, increase (decrease), deferred financing costs | (9,600) | |||
Reorganization Adjustment, Accrued interest | (3,210) | |||
Old Second Lien Credit Facility | ||||
Fresh Start Adjustment [Line Items] | ||||
Reorganization Adjustment, Accrued interest | $ (2,375) | |||
[1] | (a) Reflects the payment of $3.2 million of accrued interest related to the old first lien credit facility pursuant to the Plan. | |||
[2] | Reflects the use of cash on the Plan Effective Date from implementation of the Plan: First Lien Credit Facility deferred financing costs $ (2,525) Second Lien Credit Facility deferred financing costs(1,838) Accrued interest on old first lien credit facility (3,210) Accrued interest on old second lien credit facility(2,375) Professional fees(10,312) Total uses$ (20,260) |
Fresh Start Accounting - Cons39
Fresh Start Accounting - Consolidated Balance Sheet (Parenthetical) (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 01, 2016 | |
Fresh Start Adjustment [Line Items] | |||
Reorganization Adjustment, Accrued interest | [1] | $ (3,210) | |
Old First Lien Credit Facility | |||
Fresh Start Adjustment [Line Items] | |||
Reorganization adjustment, increase (decrease), deferred financing costs | $ (9,600) | ||
Reorganization Adjustment, Accrued interest | (3,210) | ||
New First Lien Credit Facility | |||
Fresh Start Adjustment [Line Items] | |||
Reorganization adjustment, increase (decrease), deferred financing costs | 2,500 | ||
Second Lien Credit Facility | |||
Fresh Start Adjustment [Line Items] | |||
Reorganization adjustment, increase (decrease), deferred financing costs | (1,838) | ||
Reorganization Adjustment, increase (decrease), long-term debt, less current portion, net | (252,500) | ||
Reorganization adjustment, increase (decrease), deferred financing costs gross | $ (2,200) | ||
[1] | (a) Reflects the payment of $3.2 million of accrued interest related to the old first lien credit facility pursuant to the Plan. |
Fresh Start Accounting - Cons40
Fresh Start Accounting - Consolidated Balance Sheet - Reorganization Adjustments Liabilities Subject to Compromise Settlement (Details) - USD ($) $ in Thousands | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 01, 2016 | Aug. 31, 2016 | ||
Liabilities subject to compromise (“LSTC”): | ||||
Predecessor, Liabilities subject to compromise | $ 915,626 | $ 915,626 | ||
Payment of accrued interest related to the old second lien credit facility | [1] | $ (3,210) | ||
Gain on the settlement of LSTC | 661,067 | |||
7.75% and 9.25% Senior Notes | ||||
Liabilities subject to compromise (“LSTC”): | ||||
Predecessor, Liabilities subject to compromise | 648,612 | |||
Old Second Lien Credit Facility | ||||
Liabilities subject to compromise (“LSTC”): | ||||
Predecessor, Liabilities subject to compromise | 234,451 | |||
Payment of accrued interest related to the old second lien credit facility | (2,375) | |||
Accrued interest on Senior Notes and old second lien credit facility | ||||
Liabilities subject to compromise (“LSTC”): | ||||
Predecessor, Liabilities subject to compromise | 32,563 | |||
Second Lien Credit Facility | ||||
Liabilities subject to compromise (“LSTC”): | ||||
Issuance of Second Lien Credit Facility | (252,500) | |||
Second Lien Credit Facility deferred financing costs reinstated | $ 316 | |||
[1] | (a) Reflects the payment of $3.2 million of accrued interest related to the old first lien credit facility pursuant to the Plan. |
Fresh Start Accounting - Schedu
Fresh Start Accounting - Schedule of Cumulative Impact of Reorganization Adjustments (Details) - USD ($) $ in Thousands | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 01, 2016 | [1] | |
Fresh Start Adjustment [Line Items] | |||
Gain on the settlement of LSTC | $ 661,067 | ||
Cancellation of Predecessor's capital interests | (279,711) | ||
Net cash, deferring financing costs, and other adjustments | (19,877) | ||
Total impact of reorganization adjustments | 361,479 | ||
Reorganization Adjustment, Common shareholders’ interests | 354,249 | $ 354,249 | |
Series A Preferred Members' Equity | |||
Fresh Start Adjustment [Line Items] | |||
Reorganization Adjustment, Series A Preferred member’s interest | $ 7,230 | $ 7,230 | |
[1] | Reflects the establishment of member’s equity following the consummation of the transactions pursuant to the Plan. Pursuant to our amended and restated limited liability company agreement, the holder of the Series A Preferred Share is entitled to 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity), subject to dilution if certain catch-up contributions are not made with respect to future equity issuances. Reflects the cumulative impact of reorganization adjustments as discussed above: Gain on liabilities subject to compromise$ 661,067 Cancellation of Predecessor's capital interests(279,711) Net cash, deferring financing costs, and other adjustments(19,877) Total impact of reorganization adjustments$361,479 Allocation of total impact of reorganization adjustments to establish members’ equity: Series A Preferred member's interest$ 7,230 Common shareholders’ interests$ 354,249 |
Fresh Start Accounting - Summar
Fresh Start Accounting - Summary of Excess Reorganization Value Fair Value of Identified Tangible and Intangible Assets (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 01, 2016 | Aug. 31, 2016 | |
Fresh Start Adjustment [Line Items] | ||||
Predecessor, Accumulated depreciation, depletion and amortization | $ (2,810,139) | |||
Fresh Start Adjustments, Accumulated depreciation, depletion and amortization | 2,810,139 | |||
Predecessor, Property, plant and equipment, net | 1,154,866 | $ 1,154,866 | ||
Fresh-Start Adjustment, Property, plant and equipment, net | (396,661) | $ (396,661) | [1] | |
Successor, Property, plant and equipment, net | 758,205 | $ 758,205 | ||
Predecessor, total natural gas and oil properties | 3,965,005 | |||
Fresh Start Adjustment, total natural gas and oil properties | (3,206,800) | |||
Successor, total natural gas and oil properties | 758,205 | |||
Proved properties | ||||
Fresh Start Adjustment [Line Items] | ||||
Predecessor, total natural gas and oil properties | 3,620,371 | |||
Fresh Start Adjustment, total natural gas and oil properties | (2,946,257) | |||
Successor, total natural gas and oil properties | 674,114 | |||
Unproved properties | ||||
Fresh Start Adjustment [Line Items] | ||||
Predecessor, total natural gas and oil properties | 213,047 | |||
Fresh Start Adjustment, total natural gas and oil properties | (142,783) | |||
Successor, total natural gas and oil properties | 70,264 | |||
Support equipment and other | ||||
Fresh Start Adjustment [Line Items] | ||||
Predecessor, total natural gas and oil properties | 131,587 | |||
Fresh Start Adjustment, total natural gas and oil properties | (117,760) | |||
Successor, total natural gas and oil properties | $ 13,827 | |||
[1] | (a) Reflects the adjustment made to record the elimination of $9.6 million of the old first lien credit facility deferred financing costs offset by the recognition of $2.5 million in additional deferred financing costs related to the new First Lien Credit Facility. |
Fresh Start Accounting - Sche43
Fresh Start Accounting - Schedule of Cumulative Impact of Fresh Start Adjustments (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 01, 2016 | |
Fresh Start Adjustment [Line Items] | |||
Property, plant, and equipment, net fair value adjustment | $ (396,661) | $ (396,661) | [1] |
Elimination of Predecessor’s goodwill | (13,639) | ||
Accounts receivable fair value adjustment | (56) | (56) | [2] |
Other liabilities fair value adjustment | 52 | 52 | [3] |
Accrued liabilities fair value adjustment | 2,774 | 2,774 | [4] |
Asset retirement fair value adjustment | 72,067 | 72,067 | [5] |
Total impact of fresh start adjustments | (335,463) | (335,463) | |
Common shareholders’ interest | (328,754) | (328,754) | [6] |
Series A Preferred Members' Equity | |||
Fresh Start Adjustment [Line Items] | |||
Series A Preferred member's interest | $ (6,709) | $ (6,709) | [6] |
[1] | (a) Reflects the adjustment made to record the elimination of $9.6 million of the old first lien credit facility deferred financing costs offset by the recognition of $2.5 million in additional deferred financing costs related to the new First Lien Credit Facility. | ||
[2] | Reflects the use of cash on the Plan Effective Date from implementation of the Plan: First Lien Credit Facility deferred financing costs $ (2,525) Second Lien Credit Facility deferred financing costs(1,838) Accrued interest on old first lien credit facility (3,210) Accrued interest on old second lien credit facility(2,375) Professional fees(10,312) Total uses$ (20,260) | ||
[3] | Reflects the cancellation of our Predecessor’s general partner’s interest, preferred limited partners’ interests, common limited partner interests and accumulated other comprehensive income pursuant to the Plan. | ||
[4] | Reflects the incurrence of indebtedness under the Second Lien Credit Facility, which has an aggregate principal amount of $252.5 million pursuant to the Plan, and is net of deferred financing costs of $2.2 million. | ||
[5] | Liabilities subject to compromise were settled as follows in accordance with the Plan: Liabilities subject to compromise (“LSTC”): 7.75% and 9.25% Senior Notes, net of debt discount and deferred financing costs$ 648,612 Old second lien credit facility, net of debt discount and deferred financing costs234,451 Accrued interest related to the Senior Notes and old second lien credit facility32,563 LSTC of Predecessor915,626 Issuance of Second Lien Credit Facility(252,500) Payment of accrued interest related to the old second lien credit facility(2,375) Second Lien Credit Facility deferred financing costs reinstated316 Gain on the settlement of LSTC$661,067 | ||
[6] | Reflects the establishment of member’s equity following the consummation of the transactions pursuant to the Plan. Pursuant to our amended and restated limited liability company agreement, the holder of the Series A Preferred Share is entitled to 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity), subject to dilution if certain catch-up contributions are not made with respect to future equity issuances. Reflects the cumulative impact of reorganization adjustments as discussed above: Gain on liabilities subject to compromise$ 661,067 Cancellation of Predecessor's capital interests(279,711) Net cash, deferring financing costs, and other adjustments(19,877) Total impact of reorganization adjustments$361,479 Allocation of total impact of reorganization adjustments to establish members’ equity: Series A Preferred member's interest$ 7,230 Common shareholders’ interests$ 354,249 |
Fresh Start Accounting - Summ44
Fresh Start Accounting - Summary of Reorganization Items Net (Details) - USD ($) $ in Thousands | 1 Months Ended | 9 Months Ended | |
Sep. 30, 2016 | [1] | Sep. 30, 2016 | |
Reorganizations [Abstract] | |||
Professional fees and other | $ (33,065) | ||
Accelerated amortization of deferred financing costs | (9,565) | ||
Net gain on reorganization adjustments | 361,479 | ||
Net loss on fresh start adjustments | (335,463) | ||
Reorganization items, net | $ (353) | $ (16,614) | |
[1] | Gain (loss) on asset sales and disposal, general and administrative expenses, reorganization items, net, gain on early extinguishment of debt, interest expense and income tax expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented. |
Property, Plant and Equipment45
Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Property Plant And Equipment [Line Items] | ||
Proved properties | $ 678,208 | |
Unproved properties | 74,434 | |
Support equipment and other | 13,080 | |
Total natural gas and oil properties | 765,722 | |
Less – accumulated depreciation, depletion and amortization | (4,872) | |
Property, plant and equipment, Net, Total | $ 760,850 | |
Predecessor | ||
Property Plant And Equipment [Line Items] | ||
Proved properties | $ 3,585,839 | |
Unproved properties | 213,047 | |
Support equipment and other | 130,691 | |
Total natural gas and oil properties | 3,929,577 | |
Less – accumulated depreciation, depletion and amortization | (2,737,966) | |
Property, plant and equipment, Net, Total | $ 1,191,611 |
Property, Plant and Equipment46
Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Millions | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended |
Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2015 | |
Property Plant And Equipment [Line Items] | |||||
Non-cash property plant and equipment additions | $ 0.4 | $ 18.7 | $ 5.2 | ||
Weighted Average Interest Rate Used To Capitalize Interest | 7.60% | 6.00% | 6.50% | 6.50% | 6.40% |
Interest Costs Capitalized | $ 0.7 | $ 1.7 | $ 4 | $ 6.5 | $ 12 |
Liabilities incurred in asset retirement obligations | 12.9 | ||||
Depreciation, depletion and amortization | |||||
Property Plant And Equipment [Line Items] | |||||
Accretion expense | $ 0.5 | $ 1.3 | $ 1.6 | $ 4.6 | $ 4.7 |
Debt (Schedule of Total Debt Ou
Debt (Schedule of Total Debt Outstanding) (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 01, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | |||
Senior Notes | $ 668,000 | ||
Deferred financing costs | $ (2,121) | ||
Total debt, net | 688,222 | ||
Less current maturities | (30,000) | ||
Total long-term debt, net | 658,222 | $ 1,503,427 | |
Predecessor | |||
Debt Instrument [Line Items] | |||
Deferred financing costs | (31,055) | ||
Total debt, net | 1,503,427 | ||
Total long-term debt, net | 1,503,427 | ||
Old Second Lien Term Loan | Predecessor | |||
Debt Instrument [Line Items] | |||
Old Second Lien Term Loan | 243,783 | ||
7.75% Senior Notes | Predecessor | |||
Debt Instrument [Line Items] | |||
Senior Notes | 374,619 | ||
9.25% Senior Notes | Predecessor | |||
Debt Instrument [Line Items] | |||
Senior Notes | 324,080 | ||
First Lien Credit Facility | |||
Debt Instrument [Line Items] | |||
Credit Facility | 435,809 | ||
Second Lien Credit Facility | |||
Debt Instrument [Line Items] | |||
Credit Facility | $ 254,534 | ||
Old First Lien Credit Facility | Predecessor | |||
Debt Instrument [Line Items] | |||
Credit Facility | $ 592,000 |
Debt (Schedule of Retrospective
Debt (Schedule of Retrospective Effect of Reclassification Results) (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | ||
Other assets, net | $ 11,145 | $ 28,989 |
Total long-term debt, net | $ 658,222 | 1,503,427 |
Previously Filed | ||
Debt Instrument [Line Items] | ||
Other assets, net | 60,044 | |
Total long-term debt, net | 1,534,482 | |
Adjustment | ||
Debt Instrument [Line Items] | ||
Other assets, net | (31,055) | |
Total long-term debt, net | $ (31,055) |
Debt (Narrative) (Details)
Debt (Narrative) (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended |
Sep. 30, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2015 | |
Debt Instrument [Line Items] | ||||
Cash Payments For Interest On Debt | $ 0.5 | |||
Predecessor | ||||
Debt Instrument [Line Items] | ||||
Cash Payments For Interest On Debt | $ 40.4 | $ 53.7 | $ 87.7 |
Debt (First Lien Credit Facilit
Debt (First Lien Credit Facility) (Details) - First Lien Credit Facility - USD ($) | Sep. 01, 2016 | Sep. 30, 2016 |
Line Of Credit Facility [Line Items] | ||
Line of credit facility maximum borrowing capacity | $ 440,000,000 | |
Fee on the unused portion of the borrowing base | 0.50% | |
Line of credit facility, weighted average interest rate | 5.10% | |
Line of credit facility interest rate description | Borrowings bear interest at our election at either LIBOR plus an applicable margin between 3.00% and 4.00% per annum or the “alternate base rate” plus an applicable margin between 2.00% and 3.00% per annum, which fluctuates based on utilization. We are also required to pay a fee of 0.50% per annum on the unused portion of the borrowing base. At September 30, 2016, the weighted average interest rate on outstanding borrowings under the First Lien Credit Facility was 5.1%. | |
Minimum | ||
Line Of Credit Facility [Line Items] | ||
Percentage of commodity hedges covering | 80.00% | |
Required Current Assets to Current Liabilities ratio | 100.00% | |
EBITDA to interest expense ratio | 2.50% | |
Maximum | ||
Line Of Credit Facility [Line Items] | ||
Total Debt to EBITDA | 5.00% | |
Ratio of First Lien Debt to EBITDA | 3.50% | |
London Interbank Offered Rate (LIBOR) | Minimum | ||
Line Of Credit Facility [Line Items] | ||
Applicable margin rate | 3.00% | |
London Interbank Offered Rate (LIBOR) | Maximum | ||
Line Of Credit Facility [Line Items] | ||
Applicable margin rate | 4.00% | |
Alternate Base Rate | Minimum | ||
Line Of Credit Facility [Line Items] | ||
Applicable margin rate | 2.00% | |
Alternate Base Rate | Maximum | ||
Line Of Credit Facility [Line Items] | ||
Applicable margin rate | 3.00% | |
Revolving Credit Facility Conforming Tranche | ||
Line Of Credit Facility [Line Items] | ||
Line of credit facility maximum borrowing capacity | $ 410,000,000 | |
Line of Credit Facility, Expiration Date | Aug. 23, 2019 | |
Revolving Credit Facility Nonconforming Tranche | ||
Line Of Credit Facility [Line Items] | ||
Line of credit facility maximum borrowing capacity | $ 30,000,000 | |
Line of Credit Facility, Expiration Date | May 1, 2017 |
Debt (Second Lien Credit Facili
Debt (Second Lien Credit Facility) (Details) - Second Lien Credit Facility - USD ($) | Sep. 01, 2016 | Sep. 30, 2016 |
Line Of Credit Facility [Line Items] | ||
Line of credit facility maximum borrowing capacity | $ 252,500,000 | |
Line of Credit Facility, Expiration Date | Feb. 23, 2020 | |
Percentage of interest expense paid in cash | 2.00% | |
Variable interest rate, period | 15 months | |
Prior to February 23, 2017 | ||
Line Of Credit Facility [Line Items] | ||
Percentage of principal amount prepaid | 4.50% | |
After February 23, 2017 and Prior to February 23, 2018 | ||
Line Of Credit Facility [Line Items] | ||
Percentage of principal amount prepaid | 2.25% | |
After February 23, 2018 | ||
Line Of Credit Facility [Line Items] | ||
Percentage of principal amount prepaid | 0.00% | |
London Interbank Offered Rate (LIBOR) | ||
Line Of Credit Facility [Line Items] | ||
Applicable margin rate | 9.00% | |
Maximum | ||
Line Of Credit Facility [Line Items] | ||
Interest payable date | May 1, 2017 | |
Maximum | Prior to December 31, 2017 | ||
Line Of Credit Facility [Line Items] | ||
Leverage ratio | 5.50% | |
Maximum | December 31, 2017 Thereafter | ||
Line Of Credit Facility [Line Items] | ||
Leverage ratio | 5.00% | |
Minimum | ||
Line Of Credit Facility [Line Items] | ||
EBITDA to interest expense ratio | 2.50% | |
Required Current Assets to Current Liabilities ratio | 100.00% |
Debt (Old First Lien Credit Fac
Debt (Old First Lien Credit Facility) (Details) - Predecessor - USD ($) | Jul. 27, 2016 | Jul. 31, 2013 | Aug. 31, 2016 | Sep. 30, 2015 |
Line Of Credit Facility [Line Items] | ||||
Line Of Credit Facility Maximum Borrowing Capacity | $ 291,191,000 | $ 449,754,000 | ||
Old First Lien Credit Facility | ||||
Line Of Credit Facility [Line Items] | ||||
Line of credit facility maximum borrowing capacity | $ 1,500,000,000 | |||
Line of Credit Facility, Expiration Date | Jul. 1, 2018 | |||
Line Of Credit Facility Maximum Borrowing Capacity | $ 233,500,000 | |||
Line of credit facility, weighted average interest rate | 5.50% |
Debt (Old Second Lien Term Loan
Debt (Old Second Lien Term Loan) (Details) - Predecessor - Old Second Lien Term Loan - USD ($) | Aug. 31, 2016 | Feb. 23, 2015 |
Debt Instrument [Line Items] | ||
Line of credit facility maximum borrowing capacity | $ 250,000,000 | |
Line of credit facility, weighted average interest rate | 10.00% |
Debt (Senior Notes) (Details)
Debt (Senior Notes) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Feb. 29, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2015 | Sep. 01, 2016 | ||
Debt Instrument [Line Items] | |||||||
Cash Payments For Interest On Debt | $ 500 | ||||||
Percentage of principal amount outstanding in exchange for common equity interest | 100.00% | ||||||
Principal amount outstanding | $ 668,000 | ||||||
Percentage of common equity interest | 90.00% | 90.00% | |||||
Predecessor | |||||||
Debt Instrument [Line Items] | |||||||
Cash Payments For Interest On Debt | $ 40,400 | $ 53,700 | $ 87,700 | ||||
Gain on early extinguishment of debt | [1] | 26,498 | |||||
Amortization of financing costs | $ 900 | ||||||
7.75% Senior Notes | Predecessor | |||||||
Debt Instrument [Line Items] | |||||||
Repurchase of senior unsecured notes | $ 20,300 | ||||||
9.25% Senior Notes | Predecessor | |||||||
Debt Instrument [Line Items] | |||||||
Repurchase of senior unsecured notes | 12,100 | ||||||
Senior Notes | Predecessor | |||||||
Debt Instrument [Line Items] | |||||||
Repurchase of senior unsecured notes face amount | 5,500 | ||||||
Cash Payments For Interest On Debt | $ 600 | ||||||
[1] | Gain (loss) on asset sales and disposal, general and administrative expenses, reorganization items, net, gain on early extinguishment of debt, interest expense and income tax expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented. |
Derivative Instruments (Narrati
Derivative Instruments (Narrative) (Details) - Predecessor - USD ($) | Jul. 27, 2016 | Aug. 31, 2016 | Sep. 30, 2015 |
Derivative Instruments Gain Loss [Line Items] | |||
Repayment of outstanding borrowings | $ 291,191,000 | $ 449,754,000 | |
Old First Lien Credit Facility | |||
Derivative Instruments Gain Loss [Line Items] | |||
Repayment of outstanding borrowings | $ 233,500,000 |
Derivative Instruments (Summary
Derivative Instruments (Summary of Cash Settlement on Commodity Derivatives and Presentation in Partnership's Condensed Consolidated Statements of Operations) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended | |
Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2015 | ||
Derivative Instruments And Hedging Activities Disclosures [Line Items] | ||||||
Portion of settlements attributable to subsequent mark to market gains | [1] | $ 283 | ||||
Total cash settlements on commodity derivative contracts | [1] | 283 | ||||
Gains (losses) recognized on cash settlement | [2] | (22) | ||||
Gains (losses) recognized on open derivative contracts | [2] | (1,308) | ||||
Gains (losses) on mark-to-market derivatives | $ (1,330) | |||||
Predecessor | ||||||
Derivative Instruments And Hedging Activities Disclosures [Line Items] | ||||||
Portion of settlements associated with gains (losses) previously recognized within accumulated other comprehensive income, net of prior year offsets | [1],[3] | $ 1,688 | $ 23,927 | $ 10,758 | $ 77,048 | |
Portion of settlements attributable to subsequent mark to market gains | [1] | 3,996 | 19,555 | 89,041 | 49,680 | |
Total cash settlements on commodity derivative contracts | [1] | 5,684 | 43,482 | 99,799 | 126,728 | |
Gains (losses) recognized on cash settlement | [2] | 10,574 | 10,426 | (16,570) | 17,259 | |
Gains (losses) recognized on open derivative contracts | [2] | (7,346) | 120,639 | (7,346) | 192,447 | |
Gains (losses) on mark-to-market derivatives | $ 3,228 | $ 131,065 | $ (23,916) | $ 209,706 | ||
[1] | Excludes the effects of the $235.3 million, net of $8.2 million in hedge monetization fees, paid directly to the First Lien Credit Facility lenders upon the sale of substantially all of our Predecessor’s commodity hedge positions on July 25, 2016 and July 26, 2016. | |||||
[2] | Recognized in gain (loss) on mark-to-market derivatives. | |||||
[3] | Recognized in gas and oil production revenue. |
Derivative Instruments (Summa57
Derivative Instruments (Summary of Cash Settlement on Commodity Derivatives and Presentation in Partnership's Condensed Consolidated Statements of Operations) (Parenthetical) (Details) - Predecessor - First Lien Credit Facility $ in Millions | Jul. 27, 2016USD ($) |
Derivative Instruments And Hedging Activities Disclosures [Line Items] | |
Effect of hedge monetization fees paid | $ 235.3 |
Net of hedge monetization fees paid | $ 8.2 |
Derivative Instruments (Fair Va
Derivative Instruments (Fair Values of the Partnership's Derivative Instruments Table) (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | $ 8,324 | |
Gross Amounts Recognized, Liabilities | (17,282) | |
Current portion of derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Liabilities | (8,204) | |
Gross Amounts Offset, Liabilities | 2,905 | |
Net Amount Presented, Liabilities | (5,299) | |
Long-term portion of derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Liabilities | (9,078) | |
Gross Amounts Offset, Liabilities | 5,419 | |
Net Amount Presented, Liabilities | (3,659) | |
Total derivative liabilities | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Liabilities | (17,282) | |
Gross Amounts Offset, Liabilities | 8,324 | |
Net Amount Presented, Liabilities | (8,958) | |
Current portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 2,905 | |
Gross Amounts Offset, Assets | (2,905) | |
Current portion of derivative assets | Predecessor | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | $ 159,460 | |
Net Amount Presented, Assets | 159,460 | |
Long-term portion of derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 5,419 | |
Gross Amounts Offset, Assets | (5,419) | |
Long-term portion of derivative assets | Predecessor | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 198,262 | |
Net Amount Presented, Assets | 198,262 | |
Total derivative assets | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 8,324 | |
Gross Amounts Offset, Assets | $ (8,324) | |
Total derivative assets | Predecessor | ||
Derivatives Fair Value [Line Items] | ||
Gross Amounts Recognized, Assets | 357,722 | |
Net Amount Presented, Assets | $ 357,722 |
Derivative Instruments (Commodi
Derivative Instruments (Commodity Derivative Instruments by Type Table) (Details) $ in Thousands | Sep. 30, 2016USD ($)MMBTUbbl$ / MMBTU$ / bbl | |
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | $ (8,958) | [1] |
Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | 1,948 | [1] |
Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Fair Value Asset | $ (10,906) | [1] |
Production Period Ending December 31 2016 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | 13,656,600 | [2],[3] |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 2.970 | [2],[3] |
Fair Value Asset | $ (425) | [1],[2] |
Production Period Ending December 31 2016 | Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | 301,900 | [2],[3] |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 42.763 | [2],[3] |
Fair Value Asset | $ (1,856) | [1],[2] |
Production Period Ending December 31 2017 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | 48,127,700 | [3] |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 3.116 | [3] |
Fair Value Asset | $ 958 | [1] |
Production Period Ending December 31 2017 | Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | 1,057,900 | [3] |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 46.150 | [3] |
Fair Value Asset | $ (5,367) | [1] |
Production Period Ending December 31 2018 | Natural Gas - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | MMBTU | 47,559,300 | [3] |
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 2.959 | [3] |
Fair Value Asset | $ 1,415 | [1] |
Production Period Ending December 31 2018 | Crude Oil - Fixed Price Swaps | ||
Derivatives Fair Value [Line Items] | ||
Derivatives Nonmonetary Volume Notional Amount | bbl | 893,500 | [3] |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 48.938 | [3] |
Fair Value Asset | $ (3,683) | [1] |
[1] | Fair value for natural gas fixed price swaps and natural gas put options are based on forward NYMEX natural gas prices, as applicable. Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable. | |
[2] | The production volumes for 2016 include the remaining three months of 2016 beginning October 1, 2016. | |
[3] | Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels. |
Fair Value of Financial Instr60
Fair Value of Financial Instruments (Schedule of Financial Instruments at Fair Value) (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Assets, gross | $ 8,324 | |
Liabilities, gross | (17,282) | |
Total derivatives, fair value, net | (8,958) | |
Predecessor | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Total derivatives, fair value, net | $ 357,722 | |
Level 2 | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Assets, gross | 8,324 | |
Liabilities, gross | (17,282) | |
Total derivatives, fair value, net | (8,958) | |
Level 2 | Predecessor | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Total derivatives, fair value, net | 357,722 | |
Commodity Swaps | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Assets, gross | 8,324 | |
Liabilities, gross | (17,282) | |
Commodity Swaps | Predecessor | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Assets, gross | 355,329 | |
Commodity Swaps | Level 2 | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Assets, gross | 8,324 | |
Liabilities, gross | $ (17,282) | |
Commodity Swaps | Level 2 | Predecessor | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Assets, gross | 355,329 | |
Commodity Puts | Predecessor | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Assets, gross | 2,393 | |
Commodity Puts | Level 2 | Predecessor | ||
Fair Value Option Qualitative Disclosures Related To Election [Line Items] | ||
Assets, gross | $ 2,393 |
Fair Value of Financial Instr61
Fair Value of Financial Instruments - Additional Information (Details) - First and Second Lien Credit Facility $ in Millions | Sep. 30, 2016USD ($) |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |
Long-term Debt, Fair Value | $ 639.4 |
Long-term debt, carrying amount | $ 690.3 |
Certain Relationships and Rel62
Certain Relationships and Related Party Transactions (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands | Oct. 24, 2016 | Aug. 31, 2016 | Dec. 31, 2016 | Aug. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | |||||||||
Accrued well drilling and completion costs | $ 15,491 | ||||||||
Predecessor | |||||||||
Related Party Transaction [Line Items] | |||||||||
Accrued well drilling and completion costs | $ 26,914 | ||||||||
Other income (loss) | [1] | $ (3,033) | $ (9,189) | ||||||
Provision for losses on Drilling Partnership receivables | 10,906 | ||||||||
Relationship with ATLS | |||||||||
Related Party Transaction [Line Items] | |||||||||
Accounts receivable | 5,500 | ||||||||
Accounts payable | 1,300 | ||||||||
Relationship with Drilling Partnerships | |||||||||
Related Party Transaction [Line Items] | |||||||||
Accounts receivable | 600 | 6,600 | |||||||
Accounts payable | 2,300 | 3,000 | |||||||
Relationship with Drilling Partnerships | Subsequent Event | |||||||||
Related Party Transaction [Line Items] | |||||||||
Payments to acquire oil and gas properties | $ 31,000 | ||||||||
Asset retirement obligation | $ 14,700 | ||||||||
Acquisitions effective date | Oct. 1, 2016 | ||||||||
Relationship with Drilling Partnerships | Predecessor | |||||||||
Related Party Transaction [Line Items] | |||||||||
Capital raised from investors | $ 36,700 | ||||||||
Accrued well drilling and completion costs | $ 13,300 | ||||||||
Cash transferred to partners | $ 5,200 | ||||||||
Payments to acquire oil and gas properties | 7,200 | 7,200 | |||||||
Asset retirement obligation | $ 12,400 | 12,400 | |||||||
Other income (loss) | $ 6,100 | ||||||||
Relationship with Drilling Partnerships | Scenario, Forecast | |||||||||
Related Party Transaction [Line Items] | |||||||||
Other income (loss) | $ 16,300 | ||||||||
Relationship with AGP | |||||||||
Related Party Transaction [Line Items] | |||||||||
Accounts receivable | $ 100 | ||||||||
Accounts payable | $ 8,700 | ||||||||
Compensation as percentage of gross proceeds of private placement offering | 3.00% | ||||||||
Percentage of gross offering proceeds reallowed | 1.25% | ||||||||
Relationship with AGP | Maximum | |||||||||
Related Party Transaction [Line Items] | |||||||||
Compensation as percentage of gross proceeds of private placement offering | 12.00% | ||||||||
Limited partners units issued | 100,000,000 | ||||||||
Percentage of gross offering proceeds reallowed | 1.50% | ||||||||
Relationship with AGP | Class A Common Units | |||||||||
Related Party Transaction [Line Items] | |||||||||
Sales commissions as percentage of gross proceeds of private placement offering | 7.00% | ||||||||
Relationship with AGP | Class T Common Units | |||||||||
Related Party Transaction [Line Items] | |||||||||
Sales commissions as percentage of gross proceeds of private placement offering | 3.00% | ||||||||
Distribution and unitholder servicing fee as percentage of gross proceeds of private placement offering | 4.00% | ||||||||
Rate of cash distributions to be withheld or payable to purchasers, per unit per quarter | $ 0.025 | ||||||||
[1] | Gain (loss) on asset sales and disposal, general and administrative expenses, reorganization items, net, gain on early extinguishment of debt, interest expense and income tax expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented. |
Commitments and Contingencies (
Commitments and Contingencies (General Commitments) (Details) - USD ($) $ in Millions | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended | |
Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2016 | Sep. 30, 2015 | |
Percentage of present value of future cash flows | 10.00% | |||||
Net partnership revenues subordinated | $ 0.2 | $ 0.4 | $ 0.4 | $ 1 | $ 1.5 | |
Long-term purchase commitment, amount | $ 4.3 | |||||
Minimum | ||||||
Partnership obligations to purchase units from investor partners | 5.00% | |||||
Investor partners return on investment | 10.00% | |||||
Period of return on unhedged revenue | 5 years | |||||
Maximum | ||||||
Partnership obligations to purchase units from investor partners | 10.00% | |||||
Percentage on unhedged revenue | 50.00% | |||||
Investor partners return on investment | 12.00% | |||||
Period of return on unhedged revenue | 8 years |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) | 1 Months Ended | 9 Months Ended |
Sep. 30, 2016USD ($) | Sep. 30, 2016USD ($) | |
Income Tax Disclosure [Abstract] | ||
Additions, reductions or settlements in unrecognized tax benefits | $ 0 | |
Uncertain tax positions | 0 | $ 0 |
Income tax provision (benefit) | $ 0 | |
Income Tax Examination, Description | We are subject to income taxes in the U.S. federal jurisdiction and various states. Tax regulations within each jurisdiction are subject to the interpretations of the related tax laws and regulations and require significant judgment to apply. We are no longer subject to U.S. federal, state, and local, or non-U.S. income tax examinations by tax authorities for the years before 2013. |
Issuances of Units (Details)
Issuances of Units (Details) - USD ($) | Sep. 01, 2016 | Jul. 31, 2016 | Jul. 12, 2016 | May 12, 2016 | Jun. 05, 2015 | Mar. 31, 2015 | Sep. 30, 2016 | Aug. 31, 2015 | May 31, 2015 | Apr. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2016 | Sep. 30, 2015 | Jul. 31, 2013 |
Capital Unit [Line Items] | ||||||||||||||||
Common equity outstanding | 5,416,667 | 5,416,667 | 5,416,667 | |||||||||||||
Non-cash compensation expense | $ 68,000 | |||||||||||||||
Equity Distribution Agreement With M L V And Co Limited Liability Company | Class D And Class E Preferred Units | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Partners' Capital Account, Units, Percentage | 8.625% | |||||||||||||||
Predecessor | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Non-cash compensation expense | $ 1,167,000 | $ 4,497,000 | ||||||||||||||
Net proceeds from issuance of common limited partner units | 204,000 | $ 89,409,000 | ||||||||||||||
Average closing price for common unit | $ 1 | |||||||||||||||
Predecessor | General and Administrative Expense | Phantom Share Units | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Non-cash compensation expense | $ 800,000 | |||||||||||||||
Impact on compensation expense | 0 | |||||||||||||||
Predecessor | Board of Directors | Phantom Share Units | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Granted (in units) | 110,000 | |||||||||||||||
Predecessor | Arkoma Acquisition | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 6,500,000 | 6,500,000 | ||||||||||||||
Partners' Capital Account, Units, Date Of Sale | May 2,015 | |||||||||||||||
Sale of stock price per share | $ 7.97 | |||||||||||||||
Net Proceeds from Issuance of Common Limited Partners Units | $ 49,700,000 | |||||||||||||||
Predecessor | Preferred Class D | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 800,000 | |||||||||||||||
Sale of stock price per share | $ 25 | |||||||||||||||
Predecessor | Equity Distribution Agreement with Deutsche Bank Securities Inc. | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Aggregate Offering Price Of Common Units (Maximum) | $ 100,000,000 | |||||||||||||||
Agent commission, maximum percentage, of the gross sales price of common limited partner units sold. | 2.00% | |||||||||||||||
Partners' Capital Account, Units, Sale of Units | 5,519,110 | 245,175 | 8,404,934 | |||||||||||||
Net proceeds from issuance of common limited partner units | $ 18,600,000 | $ 200,000 | $ 40,000,000 | |||||||||||||
Payments for commissions and offering expenses | $ 300,000 | $ 4,000 | $ 1,000,000 | |||||||||||||
Predecessor | Class E Cumulative Redeemable Perpetual Preferred Units | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 255,000 | |||||||||||||||
Net Proceeds from Issuance of Common Limited Partners Units | $ 6,000,000 | |||||||||||||||
Public offer price per share | $ 25 | |||||||||||||||
Predecessor | Common Limited Partners' Interests | Equity Distribution Agreement with Deutsche Bank Securities Inc. | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 0 | |||||||||||||||
August 2015 ATM Agreement | Equity Distribution Agreement With M L V And Co Limited Liability Company | Class D Preferred Units | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 90,328 | 0 | 90,328 | |||||||||||||
Net proceeds from issuance of common limited partner units | $ 1,000,000 | $ 1,000,000 | ||||||||||||||
November 2015 ATM Agreement | Equity Distribution Agreement With M L V And Co Limited Liability Company | Class E Preferred Units | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 1,083 | 0 | 1,083 | |||||||||||||
Payments for commissions and offering expenses | $ 200,000 | $ 200,000 | ||||||||||||||
Titan Energy, LLC Management Incentive Plan | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Management incentive plan, description | On September 1, 2016, we adopted the Titan Energy, LLC Management Incentive Plan (the “MIP”) for the employees, directors and individual consultants of us and our affiliates. On October 26, 2016 the MIP was amended and restated to increase the number of shares that may be issued. The MIP permits the grant of options, phantom shares and restricted and unrestricted common shares, as well as dividend equivalent rights. Subject to adjustment in accordance with the MIP, a maximum of 655,555 common shares may be issued pursuant to awards under the MIP. | |||||||||||||||
Maximum number of common shares that may be issued | 655,555 | |||||||||||||||
Term of plan | 10 years | |||||||||||||||
Number of common shares issued | 277,917 | |||||||||||||||
Non-cash compensation expense | 100,000 | |||||||||||||||
Unrecognized compensation expense related to unvested common shares | $ 1,500,000 | $ 1,500,000 | ||||||||||||||
Remaining common shares not yet vested | 277,917 | 277,917 | ||||||||||||||
Titan Energy, LLC Management Incentive Plan | Next three anniversaries | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Common shares vest percentage | 33.00% | |||||||||||||||
Titan Energy, LLC Management Incentive Plan | Predecessor | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Number of common shares issued | 138,750 | |||||||||||||||
Number of common shares vested immediately | 138,750 | |||||||||||||||
Non-cash compensation expense | $ 700,000 | $ 700,000 | ||||||||||||||
Minimum | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Percentage of common stock voting rights | 67.00% | |||||||||||||||
Minimum | Predecessor | Phantom Share Units | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Vesting date | May 15, 2016 | |||||||||||||||
Maximum | Predecessor | Phantom Share Units | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Vesting date | Aug. 31, 2016 | |||||||||||||||
ATLS | Predecessor | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Common stock warrant expired | 562,497 | |||||||||||||||
Preferred Series A | Titan Energy Management, LLC | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Percentage of preferred share | 2.00% | 2.00% | 2.00% | |||||||||||||
Class C Preferred Stock | ATLS | Predecessor | ||||||||||||||||
Capital Unit [Line Items] | ||||||||||||||||
Preferred units, issued | 3,749,986 | |||||||||||||||
Convertible preferred units, issued upon conversion | 3,749,986 |
Cash Distributions - Additional
Cash Distributions - Additional Information (Details) - Predecessor - USD ($) | 1 Months Ended | 3 Months Ended | 4 Months Ended | 7 Months Ended | 8 Months Ended | 9 Months Ended | ||||
Jul. 31, 2015 | Feb. 28, 2015 | Jan. 31, 2015 | Sep. 30, 2016 | Jun. 30, 2015 | Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2016 | Sep. 30, 2015 | Jun. 30, 2016 | |
Common Limited Partners' Interests | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 5,100,000 | $ 103,000,000 | ||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.1966 | $ 0.1966 | $ 0.1083 | $ 0.0125 | ||||||
Class C Preferred Limited Partners | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 2,500,000 | 5,900,000 | ||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | 0.1966 | 0.1966 | 0.17 | $ 0.0125 | ||||||
Class A General Partner | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 200,000 | 4,300,000 | ||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | 0.1966 | 0.1966 | $ 0.1083 | $ 0.0125 | ||||||
Class B Preferred Limited Partners | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 42,000 | |||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.1966 | $ 0.1966 | $ 0.1333 | |||||||
Class D Preferred Limited Partners | October 15, 2015 to April 14, 2016 | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 4,400,000 | |||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.5390625 | |||||||||
Class D Preferred Limited Partners | October 2, 2014 to January 14, 2015 | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 6,300,000 | |||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.6169270 | |||||||||
Class D Preferred Limited Partners | January 15, 2015 to April 14, 2015 | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.539063 | |||||||||
Class E Preferred Limited Partners | October 15, 2015 to April 14, 2016 | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 300,000 | |||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.671875 | |||||||||
Class E Preferred Limited Partners | April 14, 2015 to July 14, 2015 | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $ 200,000 | |||||||||
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ 0.6793 | |||||||||
Preferred Class B | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Preferred Unit Regular Monthly Cash Distributions Per Unit | $ 0.1333 | |||||||||
Conversion of Class B preferred units (units) | 39,654 | |||||||||
Preferred Class C | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Preferred Unit Regular Monthly Cash Distributions Per Unit | $ 0.17 | |||||||||
Preferred Class D | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.5390625 | |||||||||
Preferred Unit Regular Annually Cash Distributions Per Unit | $ 2.15625 | |||||||||
Partners' Capital Account, Units, Percentage | 8.625% | |||||||||
Preferred Stock Liquidation Preference | $ 25 | |||||||||
Preferred Units Accrued Distributions | $ 3,400,000 | |||||||||
Preferred Class E | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.671875 | |||||||||
Preferred Unit Regular Annually Cash Distributions Per Unit | $ 2.6875 | |||||||||
Partners' Capital Account, Units, Percentage | 10.75% | |||||||||
Preferred Stock Liquidation Preference | $ 25 | |||||||||
Preferred Units Accrued Distributions | $ 300,000 | |||||||||
Minimum | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Percentage of Distributions in Excess of Targets | 13.00% | |||||||||
Minimum | Preferred Class B | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.40 | |||||||||
Minimum | Preferred Class C | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Preferred Unit Regular Quarterly Cash Distributions Per Unit | $ 0.51 | |||||||||
Maximum | ||||||||||
Distribution Made To Limited Partner [Line Items] | ||||||||||
Percentage of Distributions in Excess of Targets | 48.00% |
Operating Segment Information67
Operating Segment Information (Narrative) (Details) | 9 Months Ended |
Sep. 30, 2016Segment | |
Segment Reporting [Abstract] | |
Number of reportable operating segments | 3 |
Operating Segment Information68
Operating Segment Information (Operating Segment Data) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended | |
Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2015 | ||
Segment Reporting Information [Line Items] | ||||||
Revenues | $ 20,435 | |||||
Depreciation, depletion and amortization expense | (6,021) | |||||
Segment income (loss) | 1,553 | |||||
Predecessor | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | $ 64,686 | $ 257,895 | $ 151,070 | $ 597,609 | ||
Depreciation, depletion and amortization expense | (23,278) | (40,463) | (82,331) | (125,948) | ||
Asset impairment | (672,246) | (672,246) | ||||
Segment income (loss) | 3,103 | (521,322) | (45,055) | (400,311) | ||
Gas And Oil Production | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 17,128 | |||||
Operating costs and expenses | (10,522) | |||||
Depreciation, depletion and amortization expense | (5,817) | |||||
Segment income (loss) | 789 | |||||
Gas And Oil Production | Predecessor | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 42,433 | 221,799 | 115,178 | 501,949 | ||
Operating costs and expenses | (19,872) | (41,591) | (86,566) | (130,224) | ||
Depreciation, depletion and amortization expense | (16,512) | (37,079) | (68,647) | (116,559) | ||
Asset impairment | (672,246) | (672,246) | ||||
Segment income (loss) | 6,049 | (529,117) | (40,035) | (417,080) | ||
Well Construction And Completion | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 1,304 | |||||
Operating costs and expenses | (1,134) | |||||
Segment income (loss) | 170 | |||||
Well Construction And Completion | Predecessor | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 18,383 | 23,054 | 19,157 | 63,665 | ||
Operating costs and expenses | (15,985) | (20,046) | (16,658) | (55,361) | ||
Segment income (loss) | 2,398 | 3,008 | 2,499 | 8,304 | ||
Other Partnership Management | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | [1] | 2,003 | ||||
Operating costs and expenses | [1] | (1,205) | ||||
Depreciation, depletion and amortization expense | [1] | (204) | ||||
Segment income (loss) | [1] | $ 594 | ||||
Other Partnership Management | Predecessor | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | [1] | 3,870 | 13,042 | 16,735 | 31,995 | |
Operating costs and expenses | [1] | (2,448) | (4,871) | (10,570) | (14,141) | |
Depreciation, depletion and amortization expense | [1] | (6,766) | (3,384) | (13,684) | (9,389) | |
Segment income (loss) | [1] | $ (5,344) | $ 4,787 | $ (7,519) | $ 8,465 | |
[1] | Includes revenues and expenses from well services, gathering and processing, administration and oversight, and other, net that do not meet the quantitative threshold for reporting segment information. |
Operating Segment Information69
Operating Segment Information (Reconciliation of Segment Income (loss) to Net Income (Details) - USD ($) | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2016 | Sep. 30, 2015 | |||
Segment Reporting Information [Line Items] | ||||||||
Total segment income (loss) | $ 1,553,000 | |||||||
General and administrative expenses | [1] | (4,931,000) | ||||||
Interest expense | [1] | (3,810,000) | ||||||
Gain (loss) on asset sales and disposal | [1] | 10,000 | ||||||
Reorganization items, net | (353,000) | [1] | $ (16,614,000) | |||||
Income tax expense | 0 | |||||||
Net loss | (7,531,000) | |||||||
Predecessor | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Total segment income (loss) | $ 3,103,000 | $ (521,322,000) | $ (45,055,000) | $ (400,311,000) | ||||
General and administrative expenses | [1] | (17,166,000) | (13,978,000) | (58,004,000) | (44,400,000) | |||
Interest expense | [1] | (14,928,000) | (25,192,000) | (74,587,000) | (75,105,000) | |||
Gain on early extinguishment of debt | [1] | 26,498,000 | ||||||
Gain (loss) on asset sales and disposal | [1] | 14,000 | (362,000) | (479,000) | (276,000) | |||
Reorganization items, net | [1] | (16,614,000) | (16,614,000) | |||||
Other income (loss) | [1] | (3,033,000) | (9,189,000) | |||||
Net loss | (48,624,000) | (560,854,000) | (177,430,000) | (520,092,000) | ||||
Gas And Oil Production | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Total segment income (loss) | 789,000 | |||||||
Gas And Oil Production | Predecessor | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Total segment income (loss) | 6,049,000 | (529,117,000) | (40,035,000) | (417,080,000) | ||||
Well Construction And Completion | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Total segment income (loss) | 170,000 | |||||||
Well Construction And Completion | Predecessor | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Total segment income (loss) | 2,398,000 | 3,008,000 | 2,499,000 | 8,304,000 | ||||
Other Partnership Management | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Total segment income (loss) | [2] | $ 594,000 | ||||||
Other Partnership Management | Predecessor | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Total segment income (loss) | [2] | $ (5,344,000) | $ 4,787,000 | $ (7,519,000) | $ 8,465,000 | |||
[1] | Gain (loss) on asset sales and disposal, general and administrative expenses, reorganization items, net, gain on early extinguishment of debt, interest expense and income tax expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented. | |||||||
[2] | Includes revenues and expenses from well services, gathering and processing, administration and oversight, and other, net that do not meet the quantitative threshold for reporting segment information. |
Operating Segment Information70
Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended | |
Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2015 | ||
Segment Reporting Information [Line Items] | ||||||
Total revenues | $ 20,435 | |||||
Predecessor | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | $ 64,686 | $ 257,895 | $ 151,070 | $ 597,609 | ||
Gas And Oil Production | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | 17,128 | |||||
Gas And Oil Production | Predecessor | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | 42,433 | 221,799 | 115,178 | 501,949 | ||
Well Construction And Completion | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | 1,304 | |||||
Well Construction And Completion | Predecessor | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | 18,383 | 23,054 | 19,157 | 63,665 | ||
Other Partnership Management | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | [1] | $ 2,003 | ||||
Other Partnership Management | Predecessor | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | [1] | $ 3,870 | $ 13,042 | $ 16,735 | $ 31,995 | |
[1] | Includes revenues and expenses from well services, gathering and processing, administration and oversight, and other, net that do not meet the quantitative threshold for reporting segment information. |
Operating Segment Information71
Operating Segment Information (Capital Expenditures) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 9 Months Ended |
Sep. 30, 2016 | Aug. 31, 2016 | Sep. 30, 2015 | Aug. 31, 2016 | Sep. 30, 2015 | |
Segment Reporting Information [Line Items] | |||||
Capital expenditures | $ 5,367 | ||||
Predecessor | |||||
Segment Reporting Information [Line Items] | |||||
Capital expenditures | $ 6,074 | $ 32,799 | $ 24,894 | $ 102,290 | |
Gas And Oil Production | |||||
Segment Reporting Information [Line Items] | |||||
Capital expenditures | 5,464 | ||||
Gas And Oil Production | Predecessor | |||||
Segment Reporting Information [Line Items] | |||||
Capital expenditures | 5,529 | 31,753 | 22,684 | 87,986 | |
Other Partnership Management | |||||
Segment Reporting Information [Line Items] | |||||
Capital expenditures | (115) | ||||
Other Partnership Management | Predecessor | |||||
Segment Reporting Information [Line Items] | |||||
Capital expenditures | 496 | 639 | 2,046 | 13,433 | |
Corporate and Other | |||||
Segment Reporting Information [Line Items] | |||||
Capital expenditures | $ 18 | ||||
Corporate and Other | Predecessor | |||||
Segment Reporting Information [Line Items] | |||||
Capital expenditures | $ 49 | $ 407 | $ 164 | $ 871 |
Operating Segment Information72
Operating Segment Information (Balance Sheet) (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Segment Reporting Information [Line Items] | ||
Total assets | $ 844,631 | |
Predecessor | ||
Segment Reporting Information [Line Items] | ||
Goodwill, net | $ 13,639 | |
Total assets | 1,699,949 | |
Well Construction And Completion | ||
Segment Reporting Information [Line Items] | ||
Total assets | 730 | |
Well Construction And Completion | Predecessor | ||
Segment Reporting Information [Line Items] | ||
Goodwill, net | 6,389 | |
Total assets | 27,039 | |
Other Partnership Management | ||
Segment Reporting Information [Line Items] | ||
Total assets | 9,681 | |
Other Partnership Management | Predecessor | ||
Segment Reporting Information [Line Items] | ||
Goodwill, net | 7,250 | |
Total assets | 66,641 | |
Gas And Oil Production | ||
Segment Reporting Information [Line Items] | ||
Total assets | 792,241 | |
Gas And Oil Production | Predecessor | ||
Segment Reporting Information [Line Items] | ||
Total assets | 1,551,450 | |
Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Total assets | $ 41,979 | |
Corporate and Other | Predecessor | ||
Segment Reporting Information [Line Items] | ||
Total assets | $ 54,819 |
Subsequent Events (Narrative) (
Subsequent Events (Narrative) (Details) | Oct. 24, 2016 |
Relationship with Drilling Partnerships | Subsequent Event | |
Subsequent Event [Line Items] | |
Acquisitions effective date | Oct. 1, 2016 |