See accompanying notes to condensed combined consolidated financial statements.
See accompanying notes to condensed combined consolidated financial statements.
See accompanying notes to condensed combined consolidated financial statements.
See accompanying notes to condensed combined consolidated financial statements.
See accompanying notes to condensed combined consolidated financial statements.
NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1—BASIS OF PRESENTATION
We are a publicly traded (OTC: ATLS) Delaware limited liability company formed in October 2011. Unless the context otherwise requires, references to “Atlas Energy Group, LLC,” “the Company,” “we,” “us,” “our” and “our company,” refer to Atlas Energy Group, LLC, and our combined and consolidated subsidiaries.
On February 27, 2015, our former owner, Atlas Energy, L.P. (“Atlas Energy”), transferred its assets and liabilities, other than those related to its midstream assets, to us, and effected a pro rata distribution of our common units representing a 100% interest in us, to Atlas Energy’s unitholders (the “Separation”). Concurrently with the distribution of our units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading.
At June 30, 2016, our operations primarily consisted of our ownership interests in the following:
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·
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100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in Atlas Resource Partners, L.P. (“ARP”), a publicly traded Delaware master limited partnership (“MLP”) (OTC: ARPJ) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. As part of its exploration and production activities, ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities;
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|
·
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all of the incentive distribution rights, an 80.0% general partner interest and a 2.1% limited partner interest in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas. On June 30, 2015, AGP concluded a private placement offering, during which it issued $233.0 million of its common limited partner units. Of the $233.0 million of gross funds raised, we purchased $5.0 million common limited partner units. AGP’s registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission on April 5, 2016. AGP is offering in the aggregate up to 100,000,000 Class A common units and Class T common units, each representing limited partner interests in AGP, pursuant to a primary offering on a "best efforts" basis. AGP must receive minimum offering proceeds of $1.0 million to break escrow, and the maximum offering proceeds of the primary offering may not exceed $1.0 billion. The Class A common units will be sold for a cash purchase price of $10.00 and the Class T common units will be sold for a cash purchase price of $9.60, with the remaining $0.40 constituting the Class T common unitholders' deferred payment obligation to AGP. AGP is also offering up to 21,505,376 Class A common units at $9.30 per unit pursuant to a distribution reinvestment plan; and
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·
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12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.4% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the Board. Lightfoot L.P. focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. We account for our investment in Lightfoot under the equity method of accounting. During both the three months ended June 30, 2016 and 2015, we received net cash distributions of approximately $0.4 million. During both the six months ended June 30, 2016 and 2015, we received net cash distributions of approximately $0.8 million.
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At June 30, 2016, we had 26,037,992 common limited partner units issued and outstanding. The common units are a class of limited liability company interests in us. The holders of common units are entitled to participate in company distributions and exercise the rights or privileges available to holders of common units as outlined in the limited liability company agreement.
The accompanying condensed combined consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2015, was derived from audited financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission 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
12
financial
statements contained in Form 10-K. It is suggested that these interim condensed combined consolidated financial statements be read in conjunction with the financial statements and the notes thereto included in our latest Annual Report on Form 10-K. In man
agement’s opinion, all adjustments necessary for a fair presentation of our 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 t
o conform to the current year presentation due to the adoption of certain accounting standards (see Note 5). The results of operations for the interim periods presented may not necessarily be indicative of the results of operations for the full year.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Combination
Our condensed combined consolidated financial statements for the six months ended June 30, 2016 and 2015, subsequent to the transfer of assets on February 27, 2015, include our accounts and accounts of our subsidiaries. Our condensed combined consolidated financial statements for the portion of 2015 which is prior to the transfer of assets on February 27, 2015, were derived from the separate records maintained by Atlas Energy and may not necessarily be indicative of the conditions or results of operations that would have existed if we had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising us, Atlas Energy’s net investment in us is shown as equity in the condensed combined consolidated financial statements. U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed combined consolidated balance sheets and related condensed combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive the financial statements of us. Actual balances and results could be different from those estimates. Transactions between us and other Atlas Energy operations have been identified in the condensed combined consolidated financial statements as transactions between affiliates.
In connection with Atlas Energy’s merger with Targa and the concurrent Separation, we were required to repay $150.0 million of Atlas Energy’s term loan credit facility, which was issued in July 2013 for $240.0 million. In accordance with U.S. GAAP, we included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within our historical financial statements. Atlas Energy’s other historical borrowings were allocated to our historical financial statements in the same ratio. We used proceeds from the issuance of our Series A preferred units (see Note 10) and borrowings under our term loan credit facilities to fund the $150.0 million payment.
We determined that ARP and AGP are variable interest entities (“VIE’s”) based on their respective partnership agreements, our power, as the general partner, to direct activities that most significantly impact each of their respective economic performance, and our ownership of each of their respective incentive distribution rights. Accordingly, we consolidate the financial statements of ARP and AGP into our condensed combined consolidated financial statements. Our VIE’s operating results and assets balances are presented separately in Note 12 – Operating Segment Information. As the general partner for both ARP and AGP, we have unlimited liability for the obligations of ARP and AGP except for those contractual obligations that are expressly made without recourse to the general partner. The non-controlling interests in ARP and AGP are reflected as (income) loss attributable to non-controlling interests in the condensed combined consolidated statements of operations and as a component of unitholders’ equity on the condensed combined consolidated balance sheets. All material intercompany transactions have been eliminated.
In accordance with established practice in the oil and gas industry, our condensed combined 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 ARP has an interest. Such interests generally approximate 30%. Our condensed combined consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics.
On June 5, 2015, ARP completed the acquisition of our coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma for $31.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). ARP funded the purchase price using proceeds from the issuance of 6,500,000 common limited partner units. The Arkoma Acquisition had an effective date of January 1, 2015. ARP accounted for the Arkoma Acquisition as a transaction between entities under common control in its standalone consolidated financial statements.
Liquidity and Capital Resources
Our primary sources of liquidity are cash distributions received with respect to our ownership interests in ARP, AGP, and Lightfoot. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital
13
expenditures, and distributions to unitholders, which we expect to fund through op
erating cash flow, and cash distributions received.
We rely on the cash flows from the distributions received on our ownership interests in ARP, AGP, and Lightfoot. The amount of cash that ARP and AGP can distribute to their partners, including us, principally depends upon the amount of cash they each generate from their operations. ARP’s and AGP’s 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 ARP’s and AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on ARP’s and AGP’s liquidity position and ability to make distributions. Reductions of such distributions to us would adversely affect our ability to fund our cash requirements and obligations and meet our financial covenants under our credit agreements.
On May 5, 2016, the Board of Directors elected to suspend ARP’s common unit and Class C preferred distributions, beginning with the month of March of 2016, due to the continued lower commodity price environment.
Ability for the Company and ARP to Continue as a Going Concern
On July 25, 2016, ARP and certain of its subsidiaries and us, 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% ARP Senior Notes due 2021 (the “7.75% ARP Senior Notes”) and the 9.25% ARP Senior Notes due 2021 (the “9.25% ARP Senior Notes” and, together with the 7.75% ARP 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 have agreed, subject to certain terms and conditions, to support ARP’s restructuring (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”). See Note 3, “
ARP
Restructuring Support Agreement
,” for further information.
On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“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 are being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”
The Restructuring, including as a result of ARP monetizing certain hedges to pay down borrowings outstanding under ARP’s senior secured credit facility, will result in a reduction of ARP’s existing debt by approximately $900 million and elimination of approximately $80 million of ARP’s annual debt service obligations. Pursuant to the Plan, ARP’s business assets and operations will vest in a limited liability company, which will be classified as a corporation for U.S. federal income tax purposes (“New Holdco”). ARP expects to consummate the Plan and emerge from Chapter 11 before the end of the third quarter of 2016. Interested parties should refer to the information and the limitations and qualifications discussed in ARP’s disclosure statement related to ARP’s Restructuring (the “ARP Disclosure Statement”) which was filed as Exhibit 99.1 to ARP’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 25, 2016.
ARP intends to continue to operate 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, it is contemplated that all of ARP’s suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired by the Plan and will be satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms will be 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.
The Chapter 11 Filings constituted an event of default that accelerated all of ARP’s outstanding debt obligations under the ARP First Lien Credit Facility (as defined below), the ARP Second Lien Term Loan (as defined below) and the indenture governing the ARP Notes. Any efforts to enforce such payments are automatically stayed as a result of ARP’s Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11. Accordingly, we classified all of ARP’s outstanding debt obligations as a current liability on our condensed combined consolidated balance sheet as of June 30, 2016. See Note 5,
Debt
, for further information.
14
ARP’s Restructuring is not expected to materially impact us or our ownership interest in AGP or Lightfoot. We are not a party to ARP’s Restructuring. We remain controlled by the same ow
nership group and management team and thus, we expect that ARP’s Restructuring will not have a material impact on the ability of management to operate us or the other businesses.
The significant risks and uncertainties related to ARP’s Chapter 11 Filings raise substantial doubt about ARP’s and our ability to continue as a going concern. Our condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we and ARP cannot continue as a going concern, adjustments to the carrying values and classification of our and ARP’s assets and liabilities and the reported amounts of income and expenses could be required and could be material.
Atlas Growth Partners - Liquidity and Capital Resources
AGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including its private placement offering completed in 2015. AGP’s 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 AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on AGP’s liquidity position.
AGP is not a party to the Restructuring Support Agreement, and ARP’s Restructuring is not expected to materially impact AGP.
Use of Estimates
The preparation of our condensed combined 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 combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, fair value of derivative and other financial instruments and fair value of certain gas and oil properties and asset retirement obligations. Such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive the historical financial statements of us. The natural 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.
Net Income (Loss) Per Common Unit
Basic net income (loss) attributable to common unitholders per unit is computed by dividing net income (loss) attributable to common unitholders, which is determined after the deduction of net income attributable to participating securities and the preferred unitholders’ interests, if applicable, by the weighted average number of common unitholders units outstanding during the period.
Unvested unit-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities. A portion of our phantom unit awards, which consist of common units issuable under the terms of our long-term incentive plans and incentive compensation agreements, contain non-forfeitable rights to distribution equivalents. The participation rights 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 (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.
15
The following is a reconciliation of net income (loss) allocated to the common unitholders for purposes of calculating net income (loss) attributable to common unit
holders per unit (in thousands, except unit data):
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|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
Net loss
|
|
$
|
(150,717
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)
|
|
$
|
(59,543
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)
|
|
$
|
(151,989
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)
|
|
$
|
(6,064
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)
|
Preferred unitholders’ dividends
|
|
|
—
|
|
|
|
(1,004
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)
|
|
|
(339
|
)
|
|
|
(1,337
|
)
|
(Income) loss attributable to non-controlling interests
|
|
|
114,637
|
|
|
|
38,740
|
|
|
|
109,297
|
|
|
|
(19,558
|
)
|
Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
10,475
|
|
Net loss attributable to common unitholders
|
|
|
(36,080
|
)
|
|
|
(21,807
|
)
|
|
|
(43,031
|
)
|
|
|
(16,484
|
)
|
Less: Net income attributable to participating securities – phantom units
(1)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – diluted
(1)
|
|
$
|
(36,080
|
)
|
|
$
|
(21,807
|
)
|
|
$
|
(43,031
|
)
|
|
$
|
(16,484
|
)
|
(1)
|
Net income (loss) attributable to common unitholders for the net income (loss) attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders, less income allocable to participating securities. For the three months ended June 30, 2016, and 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 352,000 and 69,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the six months ended June 30, 2016 and 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 307,000 and 67,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.
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Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to 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 and convertible preferred units, 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 weighted average number of common unitholder units used to compute basic net loss attributable to common unitholders per unit with those used to compute diluted net loss attributable to common unitholders per unit (in thousands):
|
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
Weighted average number of common unitholders per unit—basic
|
|
|
26,031
|
|
|
|
26,011
|
|
|
|
26,029
|
|
|
|
26,011
|
|
Add effect of dilutive incentive awards
(1)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Add effect of dilutive convertible preferred units
(2)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Weighted average number of common unitholders per unit—diluted
|
|
|
26,031
|
|
|
|
26,011
|
|
|
|
26,029
|
|
|
|
26,011
|
|
|
(1)
|
For the three months ended June 30, 2016 and 2015, approximately 2,692,000 and 750,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. For the six months ended June 30, 2016, and 2015, approximately 2,691,000 and 567,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.
|
|
(2)
|
For each of the three months and six months ended June 30, 2016 and 2015, potential common units issuable upon conversion of our Series A preferred units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.
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Rabbi Trust
In 2011, we established an excess 401(k) plan relating to certain executives. In connection with the plan, we established a “rabbi” trust for the contributed amounts. At June 30, 2016 and December 31, 2015, we reflected $4.1 million and $5.6 million, respectively, related to the value of the rabbi trust within other assets, net on our condensed combined
16
consolidated balance sheets, and recorded corresponding liabilities of $4.1 million and $5.6 million as of those same dates, respectively, within asset retirement obligations and other on our condensed combined con
solidated balance sheets. During the six months ended June 30, 2016, a $2.3 million distribution was made to participants related to the rabbi trust. No distributions were made to participants related to the rabbi trust for the six months ended June 30, 2
015.
Recently Issued Accounting Standards
In February 2016, the Financial Accounting Standards Board (“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 combined 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 combined 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 combined 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 combined 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 combined consolidated financial statements and our method of adoption.
NOTE 3—RESTRUCTURING SUPPORT AGREEMENT
As disclosed in Note 2, on July 25, 2016, ARP and certain of its subsidiaries and us, solely with respect to certain sections thereof, entered into the Restructuring Support Agreement with the Restructuring Support Parties. On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. Under the Restructuring Support Agreement, the Restructuring Support Parties have agreed, subject to certain terms and conditions, to support ARP’s Restructuring pursuant to the Plan.
In particular, under the Plan, on the Plan’s effective date (the “Plan Effective Date”), the First Lien Lenders will receive 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 become lenders under an exit facility credit agreement (the “First Lien Exit Facility”), composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche. The non-conforming tranche will mature on May 1, 2017 and the conforming reserve-based tranche will mature on August 23, 2019. In addition, ARP will enter into a new second lien credit agreement (the “Second Lien Exit Facility” and, together with the First Lien Exit Facility, the “Exit Facilities”). The Second Lien Lenders will receive a pro rata share of the Second Lien Exit Facility, which will have an aggregate principal amount of $250 million plus the amounts resulting from the accrual of paid in kind interest on the principal amount of $250 million from the commencement of ARP’s Chapter 11 Filings, with interest expense paid in cash to be reduced to 2% and the remainder to be paid-in-kind from the
17
commencement date through May 1, 2017 at a rate equal to Adjusted LIBO Rate plus 9% per annum. During the next 15-month period, cash and in-kind interest will vary based on a pricing grid tied to ARP’s leverage ratio under the ARP revolving credit facil
ity. After such 15-month period, interest will accrue at a rate equal to Adjusted LIBO Rate plus 9% per annum and will be payable in cash. In addition to the Second Lien Exit Facility, the Second Lien Lenders will receive a pro rata share of 10% of the com
mon equity interests of New HoldCo, 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 o
f the Chapter 11 cases, will receive, on the Plan Effective Date, 90% of the common equity interests of New HoldCo as of the Plan Effective Date, subject to dilution by a management incentive plan.
Under the Plan, holders of ARP’s limited partnership units will receive no recovery. On the Plan Effective Date, all of ARP’s preferred limited partnership units and common limited partnership units will be cancelled without the receipt of any consideration.
ARP intends to continue to operate 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 will be unimpaired by the Plan and will be satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms will be 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.
Under the Plan, on the Plan Effective Date, a wholly owned subsidiary of the Company (“ARP Mgt LLC”) will receive a preferred share of New HoldCo. The preferred share will entitle ARP Mgt LLC to receive 2% of the economics of New HoldCo (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 of New HoldCo are representatives of ARP Mgt LLC (the “New HoldCo Class A Directors”). For so long as ARP Mgt LLC holds such preferred share, the New HoldCo Class A Directors will be appointed by a majority of ARP’s Class A Directors then in office. New HoldCo will have a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in New HoldCo's limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of New HoldCo unaffiliated with ARP Mgt LLC voting in favor of the exercise of the right to purchase the preferred share.
In accordance with, and subject to the terms and conditions of, the Restructuring Support Agreement, each of the Restructuring Support Parties has agreed, among other things, to: (i) support and take all commercially reasonable actions necessary or reasonably requested by ARP to facilitate consummation of the Restructuring in accordance with the Plan and the related term sheets, including without limitation, if applicable, to timely vote to accept the Plan; (ii) use commercially reasonable efforts to support the confirmation of the Plan and approval of the Disclosure Statement and the solicitation procedures; (iii) not object to, delay, interfere, impede, or take any other action to delay, interfere or impede, directly or indirectly, with the Restructuring, confirmation of the Plan, or approval of the Disclosure Statement or the solicitation procedures; and (iv) not object to our efforts to enter into the Exit Facilities, and not object to, or support the efforts of any other person to oppose or object to, the Exit Facilities.
In accordance with, and subject to the terms and conditions of, the Restructuring Support Agreement, ARP has agreed, subject to applicable fiduciary duties, among other things, to: (i) support and complete the Restructuring and all transactions set forth in the Plan and the Restructuring Support Agreement; (ii) complete the Restructuring and all transactions set forth or described in the Plan; (iii) take any and all necessary actions in furtherance of the Restructuring, the Restructuring Support Agreement and the Plan; (iv) make commercially reasonable efforts to obtain any and all required regulatory and/or third-party approvals for the Restructuring; and (v) operate the business in the ordinary course, taking into account the Restructuring.
The Restructuring Support Agreement may be terminated upon the occurrence of certain events, including the failure to meet specified milestones related to filing, confirmation and consummation of the Plan, among other requirements, and in the event of certain breaches by the parties under the Restructuring Support Agreement. There can be no assurance that the restructuring transactions will be consummated.
18
NOTE 4—PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at the dates indicated (in thousands):
|
|
|
June 30,
|
|
|
December 31,
|
|
|
Estimated
Useful Lives
|
|
|
|
2016
|
|
|
2015
|
|
|
in Years
|
Natural gas and oil properties:
|
|
|
|
|
|
|
|
|
|
|
Proved properties:
|
|
|
|
|
|
|
|
|
|
|
Leasehold interests
|
|
$
|
571,761
|
|
|
$
|
569,377
|
|
|
|
Pre-development costs
|
|
|
7,125
|
|
|
|
6,529
|
|
|
|
Wells and related equipment
|
|
|
3,173,064
|
|
|
|
3,157,708
|
|
|
|
Total proved properties
|
|
|
3,751,950
|
|
|
|
3,733,614
|
|
|
|
Unproved properties
|
|
|
213,047
|
|
|
|
213,047
|
|
|
|
Support equipment
|
|
|
44,264
|
|
|
|
44,921
|
|
|
|
Total natural gas and oil properties
|
|
|
4,009,261
|
|
|
|
3,991,582
|
|
|
|
Pipelines, processing and compression facilities
|
|
|
61,139
|
|
|
|
59,733
|
|
|
15 – 20
|
Rights of way
|
|
|
829
|
|
|
|
829
|
|
|
20 – 40
|
Land, buildings and improvements
|
|
|
9,798
|
|
|
|
9,798
|
|
|
3 – 40
|
Other
|
|
|
18,422
|
|
|
|
18,405
|
|
|
3 – 10
|
|
|
|
4,099,449
|
|
|
|
4,080,347
|
|
|
|
Less – accumulated depreciation, depletion and amortization
|
|
|
(2,825,996
|
)
|
|
|
(2,763,450
|
)
|
|
|
|
|
$
|
1,273,453
|
|
|
$
|
1,316,897
|
|
|
|
During the six months ended June 30, 2016 and 2015, we recognized $18.7 million and $29.0 million, respectively, of non-cash property, plant and equipment additions, within the changes in accounts payable and accrued liabilities on our condensed combined consolidated statements of cash flows.
ARP capitalizes 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 rates used to capitalize interest on combined borrowed funds by ARP was 6.6% for both the three months ended June 30, 2016 and 2015. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP were 6.7% and 6.4% for the six months ended June 30, 2016 and 2015, respectively. The amounts of interest capitalized by ARP were $2.4 million and $4.1 million for the three months ended June 30, 2016 and 2015, respectively. The amounts of interest capitalized by ARP were $4.8 million and $8.0 million for the six months ended June 30, 2016 and 2015, respectively.
For the three months ended June 30, 2016 and 2015, we recorded $1.7 million and $1.6 million, respectively, of accretion expense related to ARP and AGP’s asset retirement obligations within depreciation, depletion and amortization in our condensed combined consolidated statements of operations. For the six months ended June 30, 2016 and 2015, we recorded $3.3 million and $3.2 million, respectively, of accretion expense related to ARP and AGP’s asset retirement obligations within depreciation, depletion and amortization in our condensed combined consolidated statements of operations. For the three months ended June 30, 2016 and 2015, ARP recorded liabilities of $9.9 million and $0.2 million, respectively, in asset retirement obligations in our condensed consolidated balance sheet due to the liquidation of some of ARP’s Drilling Partnerships. For the six months ended June 30, 2016 and 2015, ARP recorded liabilities of $12.9 million and $0.5 million, respectively, in asset retirement obligations in our condensed consolidated balance sheet due to the liquidation of some of ARP’s Drilling Partnerships.
19
NOTE 5—DEBT
Total debt consists of the following at the dates indicated (in thousands):
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2016
|
|
|
2015
|
|
Term loan facilities
|
|
$
|
72,619
|
|
|
$
|
72,700
|
|
Deferred financing costs
|
|
(257
|
)
|
|
|
(3,813
|
)
|
ARP First Lien Credit Facility
|
|
669,500
|
|
|
|
592,000
|
|
ARP Second Lien Term Loan
|
|
244,534
|
|
|
|
243,783
|
|
ARP 7.75% Senior Notes—due 2021
|
|
354,385
|
|
|
|
374,619
|
|
ARP 9.25% Senior Notes—due 2021
|
|
312,096
|
|
|
|
324,080
|
|
ARP deferred financing costs
|
|
(27,238
|
)
|
|
|
(31,055
|
)
|
Total debt, net
|
|
1,625,639
|
|
|
|
1,572,314
|
|
Less current maturities
|
|
(1,553,277
|
)
|
|
|
(4,250
|
)
|
Total long-term debt, net
|
|
$
|
72,362
|
|
|
$
|
1,568,064
|
|
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:
Condensed Combined Consolidated Balance Sheet
|
|
Previously Filed
|
|
|
Adjustment
|
|
|
Restated
|
|
December 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Other assets, net
|
|
$
|
88,980
|
|
|
$
|
(34,868
|
)
|
|
$
|
54,112
|
|
Long-term debt, less current portion
|
|
$
|
1,602,932
|
|
|
$
|
(34,868
|
)
|
|
$
|
1,568,064
|
|
Cash Interest
. Cash payments for interest by us and our subsidiaries on our/their respective borrowings were $16.4 million and $13.2 million for the three months ended June 30, 2016 and 2015, respectively, and $59.1 million and $51.7 million for the six months ended June 30, 2016 and 2015, respectively.
Term Loan Facilities
First Lien Credit Facility
. On March 30, 2016, we, together with New Atlas Holdings, LLC (the “Borrower”) and Atlas Lightfoot, LLC, entered into a third amendment (the “Third Amendment”) to our credit agreement with Riverstone Credit Partners, L.P., as administrative agent (“Riverstone”), and the lenders (the “Lenders”) from time to time party thereto (the “First Lien Credit Agreement”).
The outstanding loans under the First Lien Credit Agreement were bifurcated between the existing First Lien Credit Agreement and the new Second Lien Credit Agreement (defined below), with $35.0 million and $35.8 million (including $2.4 million in deemed prepayment premium) in borrowings outstanding, respectively. In connection with the execution of the Third Amendment, the Borrower made a prepayment of approximately $4.25 million of the outstanding principal, which was classified as current portion of long-term debt on our condensed combined consolidated balance sheet at December 31, 2015, and $0.5 million of interest. The Third Amendment amended the First Lien Credit Agreement to, among other things:
|
·
|
provide the ability for us and the Borrower to enter into the new Second Lien Credit Agreement (defined below);
|
|
·
|
shorten the maturity date of the First Lien Credit Agreement to September 30, 2017, subject to an optional extension to September 30, 2018 by the Borrower, assuming certain conditions are met, including a First Lien Leverage Ratio (as defined in the First Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee;
|
|
·
|
modify the applicable cash interest rate margin for ABR Loans and Eurodollar Loans to 0.50% and 1.50%, respectively, and add a pay-in-kind interest payment of 11% of the principal balance per annum;
|
20
|
·
|
allow the Borrower to make mandatory pre-payments under the First Lien Credit Agreement or
the new Second Lien Credit Agreement, in its discretion, and add additional mandatory pre-payment events, including a monthly cash sweep for balances in excess of $4 million;
|
|
·
|
provide that the First Lien Credit Agreement may be prepaid without premium;
|
|
·
|
replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP’s credit agreement, beginning with the quarter ending June 30, 2016;
|
|
·
|
prohibit the payment of cash distributions on our common and preferred units;
|
|
·
|
require the receipt of quarterly distributions from AGP and Lightfoot; and
|
|
·
|
add a cross-default provision for defaults by ARP.
|
Second Lien Credit Agreement
. Also on March 30, 2016, we and the Borrower entered into a new second lien credit agreement (the “Second Lien Credit Agreement”) with Riverstone and the Lenders. As described above, $35.8 million of the indebtedness previously outstanding under the First Lien Credit Agreement was moved under the Second Lien Credit Agreement. The Second Lien Credit Agreement is presented in the table above net of an unamortized discount of $1.9 million as of June 30, 2016, related to the 4,668,044 warrants issued in connection with the Second Lien Credit Agreement (see Note 10).
The Second Lien Credit Agreement matures on March 30, 2019, subject to an optional extension (the “Extension Option”) to March 30, 2020, assuming certain conditions are met, including a Total Leverage Ratio (as defined in the Second Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee. Borrowings under the Second Lien Credit Agreement are secured on a second priority basis by security interests in the same collateral that secures borrowings under the First Lien Credit Agreement.
Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. If the First Lien Credit Agreement is repaid in full prior to March 30, 2018, the rate will be reduced to 20%. If the Extension Option is exercised, the rate will again be increased to 30%. If our market capitalization is greater than $75 million, we can issue common units in lieu of increasing the principal to satisfy the interest obligation.
The Borrower may prepay the borrowings under the Second Lien Credit Agreement without premium at any time. The Second Lien Credit Agreement includes the same mandatory prepayment events as the First Lien Credit Agreement, subject to the Borrower’s discretion to prepay either the First Lien Credit Agreement or the Second Lien Credit Agreement.
The Second Lien Credit Agreement contains the same negative and affirmative covenants and events of default as the First Lien Credit Agreement, including customary covenants that limit the Borrower’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. In addition, the Second Lien Credit Agreement requires that we maintain an Asset Coverage Ratio (as defined in the Second Lien Credit Agreement) of not less than 2.00 to 1.00 as of September 30, 2017 and each fiscal quarter ending thereafter.
As a result of the cross-default, on July 11, 2016, we entered into waiver agreements (the “Waivers”) with Riverstone and the Lenders in connection with the First Lien Credit Agreement and the Second Lien Credit Agreement. Pursuant to the Waivers, Riverstone and the Lenders agreed to waive under the First Lien Credit Agreement and the Second Lien Credit Agreement:
|
·
|
the cross-defaults relating to ARP’s default, for so long as the forbearing parties continue to forbear from exercising their rights and remedies; and
|
|
·
|
the potential default relating to ARP’s ongoing negotiations with its lenders and noteholders to the extent any resulting restructuring is completed prior to October 31, 2016
|
21
We and ARP’s future debt maturities, excluding any future payment-in-kind interest pa
yments, are as follows: $1,580.5 million, $35.0 million and $35.8 million, respectively, for the years ending December 31, 2016, 2017 and 2019, respectively.
In connection with the Term Loan Facilities, the lenders thereunder syndicated participations in loans underlying the facilities. As a result, certain of the Company’s current and former officers participated in approximately 12% of the loan syndication and warrants and a foundation affiliated with a 5% or more unitholder participated in approximately 12% of the loan syndication.
ARP First Lien Credit Facility
ARP is party to a Second Amended and Restated Credit Agreement, dated as of July 31, 2013 by and among ARP, the lenders from time to time party thereto, and Wells Fargo Bank, National Association, as administrative agent, as amended, supplemented or modified from time to time (the “ARP First Lien Credit Facility”), which provides for a senior secured revolving credit facility with a maximum borrowing base of $1.5 billion scheduled to mature in July 2018.
On June 8, 2016, ARP received notice from Wells Fargo Bank, National Association, as administrative agent under the ARP First Lien Credit Facility that its borrowing base had been redetermined in accordance with the ARP First Lien Credit Facility and reduced from $700.0 million to $530.0 million. As of June 30, 2016, $669.5 million in borrowings were outstanding (which includes $4.2 million in letters of credit) under the ARP First Lien Credit Facility, resulting in a borrowing base deficiency of $143.7 million. The ARP First Lien Credit Facility provides that within 30 days after ARP’s receipt of a notification of a borrowing base deficiency, ARP must elect to cure the borrowing base deficiency through any combination of the following actions: (i) repay amounts outstanding under the ARP First Lien Credit Facility sufficient to cure the borrowing base deficiency, either within 30 days after receipt of the borrowing base deficiency notice or in four equal monthly installments beginning on July 11, 2016; or (ii) pledge as collateral additional oil and gas properties acceptable to the administrative agent and lenders sufficient to cure the borrowing base deficiency within 60 days after receipt of the borrowing base deficiency notice. As part of the discussions with ARP’s lenders and noteholders (see Notes 1 and 3), ARP determined not to make the first installment payment that was due on July 11, 2016.
In connection therewith and in support of negotiations with ARP’s First Lien Lenders, Second Lien Lenders, and Consenting Noteholders, on July 11, 2016, ARP and certain of its subsidiaries entered into two forbearance agreements: (i) with Wells Fargo Bank, National Association, as administrative agent, and the other lenders under the ARP First Lien Credit Facility (the “ARP First Lien Credit Forbearance”) and (ii) with the Consenting Noteholders of the 7.75% ARP Senior Notes and the 9.25% ARP Senior Notes (the “ARP Notes Forbearance”).
Pursuant to the ARP First Lien Credit Forbearance, the administrative agent and the lenders representing approximately 81% of the outstanding indebtedness under the ARP First Lien Credit Facility agreed to forbear from exercising their rights and remedies arising from non-payment of the first installment of the borrowing base deficiency cure due on July 11, 2016 and related cross-defaults (the “ARP Specified Default”) until the earliest to occur of (i) July 27, 2016, (ii) the occurrence of an event of default under the ARP First Lien Credit Facility (unrelated to the ARP Specified Default) or (iii) the exercise by any holder of indebtedness outstanding under the ARP Second Lien Term Loan, the ARP Notes or any other material indebtedness of ours of rights or remedies against us or the other loan parties or their respective property.
Pursuant to the ARP Notes Forbearance, the holders of approximately 78% of the aggregate outstanding principal amount of the 7.75% ARP Senior Notes and approximately 82% of the 9.25% ARP Senior Notes agreed to forbear from exercising their rights and remedies arising from the cross-default that resulted from the ARP Specified Default until the earliest to occur of (i) July 27, 2016, (ii) another event of default under the 7.75% ARP Senior Notes indenture or the 9.25% ARP Senior Notes indenture or (iii) any other holder of the ARP Notes commences a legal proceeding against us or the other loan parties or their respective property. The holders of a majority of the Second Lien Term Loan were supportive of the forbearance.
ARP’s borrowing base is scheduled for semi-annual redeterminations in May and November of each year. Up to $20.0 million of the ARP First Lien Credit Facility may be in the form of standby letters of credit, of which $4.2 million was outstanding at June 30, 2016. ARP’s obligations under the ARP First Lien Credit Facility are secured by mortgages on ARP’s oil and gas properties and first priority security interests in substantially all of ARP’s assets. Additionally, obligations under the ARP First Lien Credit Facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. At June 30, 2016, the weighted average interest rate on outstanding borrowings under the ARP First Lien Credit Facility was 4.0%.
22
The ARP
First Lien Credit Facility
contains customary covenants including, without limitation, covenants that limit ARP’s ability to incur additional indebtedness (but which permits second li
en debt in an aggregate principal amount of up to $300.0 million and third lien debt that satisfies certain conditions including pro forma financial covenants), grant liens, make loans or investments, make distributions if a borrowing base deficiency or de
fault exists or would result from the distribution, merge or consolidate with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The ARP
First Lien Credit Facility
also requires that ARP main
tain a ratio of First Lien Debt to EBITDA (ratio as defined in the ARP
First Lien Credit Facility
) of not greater than 2.75 to 1.00, and a ratio of current assets to current liabilities (ratio as defined in the ARP
First Lien Credit Facility
) of not less t
han 1.0 to 1.0 as of the last day of any fiscal quarter. ARP was not in compliance with these covenants as of June 30, 2016.
ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under the ARP First Lien Credit Facility and as a result, we classified $669.5 million of ARP’s outstanding amounts under the ARP First Lien Credit Facility as current portion of long-term debt and $12.2 million of deferred financing costs related to the ARP First Lien Credit Facility as current assets within our condensed combined consolidated balance sheet as of June 30, 2016.Any efforts to enforce such payments are automatically stayed as a result of the Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.
Pursuant to the ARP Restructuring Support Agreement, ARP 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 ARP First Lien Credit Facility. Accordingly, approximately $440 million remained outstanding under the ARP First Lien Credit Facility as of July 27, 2016, the date of ARP’s Chapter 11 Filings.
On the Plan Effective Date, ARP expect to enter into the new ARP First Lien Exit Facility, which will replace the ARP First Lien Credit Facility (see Note 3).
ARP Second Lien Term Loan
ARP is party to a Second Lien Credit Agreement, dated as of February 23, 2015 by and among ARP, 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 “ARP Second Lien Term Loan”), which provides for a second lien term loan in an original principal amount of $250.0 million. The ARP Second Lien Term Loan matures on February 23, 2020. The Second Lien Term Loan is presented in the table above net of unamortized discount of $5.5 million as of June 30, 2016.
ARP’s obligations under the ARP Second Lien Term Loan are secured on a second priority basis by security interests in all of ARP’s assets and those of its restricted subsidiaries that guarantee the ARP First Lien Credit Facility. In addition, the obligations under the ARP Second Lien Term Loan are guaranteed by ARP’s material restricted subsidiaries. At June 30, 2016, the weighted average interest rate on outstanding borrowings under the ARP Second Lien Term Loan was 10.0%.
The ARP Second Lien Term Loan contains customary covenants including, without limitation, covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred units, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities. In addition, the ARP Second Lien Term Loan contains covenants substantially similar to those in the ARP 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. ARP was not in compliance with the financial covenants as of June 30, 2016.
ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under the ARP Second Lien Term Loan and as a result, we classified $244.5 million of ARP’s outstanding amounts under the ARP Second Lien Term Loan, which is net of $5.5 million unamortized discount and $9.4 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of June 30, 2016. Any efforts to enforce such payments are automatically stayed as a result of the Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.
On the Plan Effective Date, ARP expects to enter into the new ARP Second Lien Exit Facility, which will replace the ARP Second Lien Term Loan (see Note 3).
ARP Senior Notes
At June 30, 2016, ARP had $354.4 million outstanding of its 7.75% ARP Senior Notes due 2021. The 7.75% ARP Senior Notes were presented net of a $0.3 million unamortized discount as of June 30, 2016.
23
At June 30,
2016, ARP had $312.1 million outstanding of its 9.25% ARP Senior Notes due 2021. The 9.25% ARP Senior Notes were presented net of a $0.8 million unamortized discount as of June 30, 2016.
In January and February 2016, ARP executed transactions to repurchase $20.3 million of its 7.75% Senior Notes and $12.1 million of its 9.25% Senior Notes for $5.5 million, which included $0.6 million of interest. As a result of these transactions, we recognized $26.5 million as gain on early extinguishment of debt, net of accelerated amortization of deferred financing costs of $0.9 million, in our condensed combined consolidated statement of operations for the six months ended June 30, 2016.
The 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are full and unconditional and joint and several, subject to certain customary automatic release provisions, including, in certain circumstances, the sale or other disposition of all or substantially all the assets of, or all of the equity interests in, the subsidiary guarantor, or the subsidiary guarantor is declared “unrestricted” for covenant purposes, and any subsidiaries of ARP, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries.
The indentures governing the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes contain covenants including, without limitation, covenants that limit ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets. ARP was in compliance with these covenants as of June 30, 2016.
On June 6, 2016, ARP and certain of its subsidiaries, Wells Fargo Bank, National Association, as resigning trustee (“Wells Fargo”) and U.S. Bank National Association, as successor trustee (“U.S. Bank”), entered into an Instrument of Resignation, Appointment and Acceptance (the “Instrument”). In connection with the Instrument, Wells Fargo resigned as trustee, note custodian, registrar and paying agent under the Indenture dated as of July 30, 2013, as supplemented and amended and ARP accepted such resignation and appointed U.S. Bank as the successor trustee, note custodian, registrar and paying agent under the such indenture.
ARP’s Chapter 11 Filings constituted an event of default that accelerated ARP’s obligations under the 7.75% ARP Senior Notes and the 9.25% ARP Senior Notes and as a result, we classified $354.4 million of ARP’s outstanding amounts under the 7.75% ARP Senior Notes, which is net of $0.3 million unamortized discount and $9.5 million deferred financing costs, and $312.1 million of ARP’s outstanding amounts under the 9.25% ARP Senior Notes, which is net of $0.8 million unamortized discount and $8.3 million deferred financing costs, as current portion of long-term debt within our condensed combined consolidated balance sheet as of June 30, 2016. Any efforts to enforce such payments are automatically stayed as a result of the Chapter 11 Filings, and the holders’ rights of enforcement are subject to the applicable provisions of Chapter 11.
On the Plan Effective Date, the 7.75% Senior Notes and the 9.25% Senior Notes (together with accrued but unpaid interest) will be cancelled and the holders will receive 90% of the common equity interests of New HoldCo (see Note 3).
NOTE 6—DERIVATIVE INSTRUMENTS
ARP and AGP use a number of different derivative instruments, principally swaps and options, in connection with their commodity price risk management activities. ARP and AGP do not apply hedge accounting to any of their derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings.
ARP and AGP enter into commodity future option contracts to achieve more predictable cash flows by hedging their exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile 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. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while ethane, propane, butane and iso butane contracts are based on the respective Mt. Belvieu price. These contracts were recorded at their fair values.
We recorded net derivative assets on our condensed combined consolidated balance sheets of $234.6 million and $358.1 million at June 30, 2016 and December 31, 2015, respectively. Of the $2.3 million of net gain in accumulated other comprehensive income within unitholders’ equity on our condensed combined consolidated balance sheet related to derivatives at June 30, 2016, we expect to reclassify $1.5 million of gains to our condensed combined consolidated statement of operations over the next twelve-month period as these contracts expire. Aggregate gains of $0.8 million of gas and oil
24
production revenues will be reclassified to our condensed combined consolidated statements of operations in later periods as the remaining contracts expire.
Pursuant to the ARP Restructuring Support Agreement, ARP completed the sale of certain 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 ARP First Lien Credit Facility.
The following table summarizes the commodity derivative activity and presentation in our condensed combined consolidated statement of operations for the periods indicated (in thousands):
|
|
Three Months Ended June 30,
|
|
|
Six Months Ended June 30,
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets
(1)
|
$
|
5,555
|
|
|
$
|
25,778
|
|
|
$
|
9,070
|
|
|
$
|
53,121
|
|
Portion of settlements attributable to subsequent mark to market gains (losses)
|
|
39,835
|
|
|
|
14,922
|
|
|
|
85,265
|
|
|
|
30,125
|
|
Total cash settlements on commodity derivative contracts
|
$
|
45,390
|
|
|
$
|
40,700
|
|
|
$
|
94,335
|
|
|
$
|
83,246
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains recognized on cash settlement
(2)
|
$
|
4,732
|
|
|
$
|
3,678
|
|
|
$
|
10,666
|
|
|
$
|
6,881
|
|
Gains (losses) recognized on open derivative contracts
(2)
|
|
(78,822
|
)
|
|
|
(30,574
|
)
|
|
|
(38,303
|
)
|
|
|
71,808
|
|
Gains (losses) on mark-to-market derivatives
|
$
|
(74,090
|
)
|
|
$
|
(26,896
|
)
|
|
$
|
(27,637
|
)
|
|
$
|
78,689
|
|
(1)
|
Recognized in gas and oil production revenue.
|
(2)
|
Recognized in gain on mark-to-market derivatives.
|
During the three and six months ended June 30, 2015, we received approximately $4.9 million in net proceeds from the early termination of our remaining natural gas and oil derivative positions for production periods from 2015 through 2018. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under our Term Loan Facilities.
Atlas Growth Partners
On May 1, 2015, AGP entered into a secured credit facility agreement with a syndicate of banks. As of June 30, 2016, the lenders under the credit facility have no commitment to lend to AGP under the credit facility, but AGP and its subsidiaries have the ability to enter into derivative contracts to manage their exposure to commodity price movements which will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on AGP’s oil and gas properties and first priority security interests in substantially all of its assets. The credit facility may be amended in the future if AGP and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. The secured credit facility agreement contains covenants that limit AGP and its subsidiaries ability to incur 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 its assets. AGP was in compliance with these covenants as of June 30, 2016. In addition, AGP’s credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control provisions.
25
The following table summarizes the gross fair values of AGP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on ou
r condensed combined consolidated balance sheets as of the dates indicated (in thousands):
Offsetting Derivatives as of June 30, 2016
|
|
Gross
Amounts
Recognized
|
|
|
Gross
Amounts
Offset
|
|
|
Net Amount Presented
|
|
Current portion of derivative assets
|
|
$
|
183
|
|
|
$
|
(183
|
)
|
|
$
|
—
|
|
Long-term portion of derivative assets
|
|
|
55
|
|
|
|
(55
|
)
|
|
|
—
|
|
Total derivative assets
|
|
$
|
238
|
|
|
$
|
(238
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of derivative liabilities
|
|
$
|
(320
|
)
|
|
$
|
183
|
|
|
$
|
(137
|
)
|
Long-term portion of derivative liabilities
|
|
|
(218
|
)
|
|
|
55
|
|
|
|
(163
|
)
|
Total derivative liabilities
|
|
$
|
(538
|
)
|
|
$
|
238
|
|
|
$
|
(300
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Offsetting Derivatives as of December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of derivative assets
|
|
$
|
399
|
|
|
$
|
(96
|
)
|
|
$
|
303
|
|
Long-term portion of derivative assets
|
|
|
162
|
|
|
|
(53
|
)
|
|
|
109
|
|
Total derivative assets
|
|
$
|
561
|
|
|
$
|
(149
|
)
|
|
$
|
412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of derivative liabilities
|
|
$
|
(96
|
)
|
|
$
|
96
|
|
|
$
|
—
|
|
Long-term portion of derivative liabilities
|
|
|
(53
|
)
|
|
|
53
|
|
|
|
—
|
|
Total derivative liabilities
|
|
$
|
(149
|
)
|
|
$
|
149
|
|
|
$
|
—
|
|
At June 30, 2016, AGP had the following commodity derivatives:
Type
|
|
Production
Period Ending
December 31,
|
|
|
Volumes
(1)
|
|
|
Average
Fixed Price
(1)
|
|
Fair Value
(Liability)
|
|
|
Total Type
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
(2)
|
|
|
(in thousands)
(2)
|
Crude Oil – Fixed Price Swaps
|
|
2016
(3)
|
|
|
31,600
|
|
|
$
|
46.350
|
|
$
|
(95
|
)
|
|
|
|
|
|
2017
|
|
|
37,100
|
|
|
$
|
49.968
|
|
$
|
(79
|
)
|
|
|
|
|
|
2018
|
|
|
26,500
|
|
|
$
|
48.850
|
|
$
|
(126
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AGP’s net liabilities
|
|
|
$
|
(300)
|
(1)
|
Volumes for crude oil are stated in barrels.
|
(2)
|
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 six months of 2016 beginning July 1, 2016.
|
26
Atlas Resource Partners
The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our condensed combined consolidated balance sheets as of the dates indicated (in thousands):
Offsetting Derivatives as of June 30, 2016
|
|
Gross
Amounts
Recognized
|
|
|
Gross
Amounts
Offset
|
|
|
Net Amount
Presented
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of derivative assets
|
|
$
|
99,654
|
|
|
$
|
—
|
|
|
$
|
99,654
|
|
Long-term portion of derivative assets
|
|
|
135,231
|
|
|
|
—
|
|
|
|
135,231
|
|
Total derivative assets
|
|
$
|
234,885
|
|
|
$
|
—
|
|
|
$
|
234,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of derivative liabilities
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Long-term portion of derivative liabilities
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Total derivative liabilities
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 30, 2016, ARP had the following commodity derivatives:
Type
|
|
Production
Period Ending
December 31,
|
|
Volumes
(1)
|
|
|
Average
Fixed Price
(1)
|
|
|
Fair Value
Asset
|
|
|
Total Type
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
(2)
|
|
|
(in thousands)
(2)
|
|
Natural Gas – Fixed Price Swaps
|
|
2016
(3)
|
|
26,910,000
|
|
|
$
|
4.224
|
|
|
$
|
32,326
|
|
|
|
|
|
|
|
2017
|
|
50,120,000
|
|
|
$
|
4.221
|
|
|
$
|
51,933
|
|
|
|
|
|
|
|
2018
|
|
40,300,000
|
|
|
$
|
4.168
|
|
|
$
|
45,498
|
|
|
|
|
|
|
|
2019
|
|
15,860,000
|
|
|
$
|
4.019
|
|
|
$
|
15,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
145,702
|
|
Natural Gas – Put Options – Drilling Partnerships
|
|
2016
(3)
|
|
720,000
|
|
|
$
|
4.150
|
|
|
$
|
814
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
814
|
|
Crude Oil – Fixed Price Swaps
|
|
2016
(3)
|
|
820,500
|
|
|
$
|
81.685
|
|
|
$
|
26,449
|
|
|
|
|
|
|
|
2017
|
|
1,200,000
|
|
|
$
|
77.610
|
|
|
$
|
30,412
|
|
|
|
|
|
|
|
2018
|
|
1,080,000
|
|
|
$
|
76.281
|
|
|
$
|
24,184
|
|
|
|
|
|
|
|
2019
|
|
540,000
|
|
|
$
|
68.371
|
|
|
$
|
7,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
88,369
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net ARP assets
|
|
|
$
|
234,885
|
|
|
(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 based on forward NYMEX natural gas prices, as applicable. Fair value for crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable.
|
(3)
|
The production volumes for 2016 include the remaining six months of 2016 beginning July 1, 2016.
|
Secured Hedge Facility
At June 30, 2016, ARP had 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 ARP’s revolving credit facility, ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. ARP, as general partner
27
of the Drilling Partnerships,
administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantees 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 covena
nts 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 a
ll of its assets.
An event of default occurred under the secured hedging facility agreement upon ARP’s 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 are pending and, upon occurrence of the effective date of the Plan contemplated by ARP’s Restructuring Support Agreement, such event of default will no longer be deemed to exist or to continue under the secured hedge facility.
In addition, it will be an event of default under ARP’s revolving credit facility if ARP, as general partner of the Drilling Partnerships, breaches 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.
NOTE 7—FAIR VALUE OF FINANCIAL INSTRUMENTS
Assets and Liabilities Measured at Fair Value on a Recurring Basis
We and our subsidiaries use a market approach fair value methodology to value our financial instruments. 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 and our subsidiaries separate the fair value of our financial instruments into the three level hierarchy (Levels 1, 2 and 3) based on our/their assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of June 30, 2016 and December 31, 2015, all derivative financial instruments were classified as Level 2.
Information for our and our subsidiaries’ financial instruments measured at fair value at June 30, 2016 and December 31, 2015 were as follows (in thousands):
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
As of June 30, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets, gross
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rabbi trust
|
|
$
|
4,072
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,072
|
|
ARP Commodity swaps
|
|
|
—
|
|
|
|
234,071
|
|
|
|
—
|
|
|
|
234,071
|
|
ARP Commodity puts
|
|
|
—
|
|
|
|
814
|
|
|
|
—
|
|
|
|
814
|
|
AGP Commodity swaps
|
|
|
—
|
|
|
|
238
|
|
|
|
—
|
|
|
|
238
|
|
Total assets, gross
|
|
|
4,072
|
|
|
|
235,123
|
|
|
|
—
|
|
|
|
239,195
|
|
Liabilities, gross
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AGP Commodity swaps
|
|
|
—
|
|
|
|
(538
|
)
|
|
|
—
|
|
|
|
(538
|
)
|
Total derivative liabilities, gross
|
|
|
—
|
|
|
|
(538
|
)
|
|
|
—
|
|
|
|
(538
|
)
|
Total assets, fair value, net
|
|
$
|
4,072
|
|
|
$
|
234,585
|
|
|
$
|
—
|
|
|
$
|
238,657
|
|
As of December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets, gross
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rabbi trust
|
|
$
|
5,584
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,584
|
|
ARP Commodity swaps
|
|
|
—
|
|
|
|
355,329
|
|
|
|
—
|
|
|
|
355,329
|
|
ARP Commodity puts
|
|
|
—
|
|
|
|
2,393
|
|
|
|
—
|
|
|
|
2,393
|
|
AGP Commodity swaps
|
|
|
—
|
|
|
|
561
|
|
|
|
—
|
|
|
|
561
|
|
Total assets, gross
|
|
|
5,584
|
|
|
|
358,283
|
|
|
|
—
|
|
|
|
363,867
|
|
Liabilities, gross
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AGP Commodity swaps
|
|
|
—
|
|
|
|
(149
|
)
|
|
|
—
|
|
|
|
(149
|
)
|
Total derivative liabilities, gross
|
|
$
|
—
|
|
|
$
|
(149
|
)
|
|
$
|
—
|
|
|
$
|
(149
|
)
|
Total assets, fair value, net
|
|
$
|
5,584
|
|
|
$
|
358,134
|
|
|
$
|
—
|
|
|
$
|
363,718
|
|
28
Other Financial Instruments
We and our subsidiaries’ other current assets and liabilities on our condensed combined 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 values of our and ARP’s debt at June 30, 2016 and December 31, 2015, which consist of borrowings under our term loan facilities, ARP’s senior notes and borrowings under ARP’s term loan and revolving credit facility, were $1,020.7 million and $929.2 million, respectively, compared with the carrying amounts of $1,661.6 million and $1,614.7 million, respectively. The carrying values of outstanding borrowings under the ARP revolving credit facility, which bear interest at variable interest rates, approximated their estimated fair value. The estimated fair values of the ARP senior notes and term loan facility were based upon the market approach and calculated using the yields of the ARP senior notes and term loan 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 ARP’s natural gas and oil properties transferred to ARP 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, ARP’s 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 ARP’s 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 ARP upon liquidations of certain Drilling Partnerships (see Note 4) based on discounted cash flow projections using ARP’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 considering inflation rates, federal and state regulatory requirements, and ARP’s 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 the Warrants associated the Second Lien Credit Agreement (see Note 10) using a Black-Scholes pricing model which is based on Level 3 inputs including a unit price on the date of issuance of $0.50, exercise price of $0.20, risk free rate of 1.8%, a term of 10 years, and estimated volatility rate of 57%. The volatility rate used is consistent with that of ARP and similar sized entities within the industry. The estimated fair value per warrant was $0.40.
NOTE 8—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Relationship with ARP
. ARP does not directly employ any persons to manage or operate its business. These functions are provided by employees of us and/or our affiliates.
Relationship with AGP.
AGP does not directly employ any persons to manage or operate its business. These functions are provided by employees of us and/or our affiliates. Atlas Growth Partners, GP, LLC (“AGP GP”) receives an annual management fee in connection with its management of AGP equivalent to 1% of capital contributions per annum. During the three months ended June 30, 2016 and 2015, AGP paid approximately $0.6 million and $0.3 million related to AGP GP for this management fee. During the six months ended June 30, 2016 and 2015, AGP paid approximately $1.1 million and $0.6 million related to AGP GP for this management fee. We charge direct costs, such as salary and wages, and allocate indirect costs, such as rent for offices, to AGP by us based on the number of its employees who devoted substantially all of their time to activities on its behalf. AGP reimburses us at cost for direct costs incurred on its behalf. AGP will reimburse all necessary and reasonable costs allocated by the general partner. AGP was required to pay AGP GP an amount equal to any actual, out-of-pocket expenses related to its private placement offering and the formation and financing of AGP, including legal costs incurred by AGP GP, which payments were approximately 2% of the gross proceeds of its private placement offering.
Relationship with Drilling Partnerships
. ARP conducts certain activities through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. ARP serves as the ultimate general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the ultimate general partner, ARP is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. ARP is 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.
29
In March 2016, ARP transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred by ARP to the Atlas Eagle
Ford 2015 L.P. private drilling partnership for activities directly related to their program. In June 2016, ARP transferred $5.2 million of funds to certain of the Drilling Partnerships that were projected to make monthly or quarterly distributions to the
ir limited partners over the next several months and/or quarter to ensure accessible distribution funding coverage in accordance with the respective Drilling Partnerships’ operations and partnership agreements in the event ARP experiences a prolonged restr
ucturing period as ARP performs all administrative and management functions for the Drilling Partnerships. On July 26, 2016, ARP adopted certain amendments to the Drilling Partnerships’ partnership agreements, i
n accordance with ARP’s 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 eve
nts, 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 Partnersh
ips.
ARP intends 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, ARP expects 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 ARP upon their liquidation. During the quarter ended June 30, 2016, ARP recorded $7.2 million and $12.4 million of gas and oil properties and asset retirement obligations, respectively, transferred to ARP 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 ARP (see Note 7) and resulted in a non-cash loss of $6.2 million, net of liquidation and transfer adjustments, for the three and six months ended June 30, 2016, which was recorded in other income/(loss) in the condensed consolidated statement of operations.
As of June 30, 2016 and December 31, 2015, ARP had trade receivables of $8.9 million and $6.6 million, respectively, from certain of the Drilling Partnerships, which were recorded in accounts receivable in the condensed consolidated balance sheets. As of June 30, 2016 and December 31, 2015, ARP had trade payables of $1.5 million and $3.0 million, respectively, to certain of the Drilling Partnerships, which were recorded in accounts payable in the condensed consolidated balance sheets.
Other Relationships
. We have other related party transactions with regard to our Term Loan Facilities (see Note 5), our Series A preferred units (Note 10) and our general partner and limited partner interest in Lightfoot (see Note 1).
NOTE 9—COMMITMENTS AND CONTINGENCIES
ARP is the ultimate managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. ARP has 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, ARP is 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 ARP may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it does 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 ARP to reflect current well performance, commodity prices and production costs, among other items. Based on its historical experience, as of June 30, 2016, the management of ARP believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material.
While its historical structure has varied, ARP has generally agreed to subordinate a portion of its 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 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. ARP periodically compares 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, ARP recognizes subordination as an estimated reduction of its 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 ARP has recognized subordination in a historical period, if projected investment returns subsequently
30
reflect that the agreed upon limited partner investment return will be achieved during the subordinatio
n period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. For both the three months ended June 30, 2016 and 2015, $0
.5 million of ARP’s 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. For the six months ended June 30, 2016 and 2015,
$0.6 million and $1.1 million, respectively, of ARP’s 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 June 30, 2016, we and our subsidiaries are committed to expend approximately $4.6 million on drilling and completion expenditures.
Legal Proceedings
We and our subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of our business. Our and our subsidiaries’ management believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.
NOTE 10—ISSUANCES OF UNITS
We recognize gains or losses on ARP’s and AGP’s equity transactions as credits or debits, respectively, to unitholders’ equity on our condensed combined consolidated balance sheets rather than as income or loss on our condensed combined consolidated statements of operations. These gains or losses represent our portion of the excess or the shortage of the net offering price per unit of each of ARP’s and AGP’s common units as compared to the book carrying amount per unit.
In connection with the Second Lien Credit Agreement, on April 27, 2016, we issued to the Lenders, warrants (the “Warrants”) to purchase up to 4,668,044 common units representing limited partner interests at an exercise price of $0.20 per unit. The Warrants expire on March 30, 2026 and are subject to customary anti-dilution provisions. On April 27, 2016, we entered into a registration rights agreement pursuant to which we agreed to register the offer and resale of our common units underlying the Warrants as well as any common units issued as in-kind interest payments under the Second Lien Credit Agreement. The Warrants include a cashless exercise provision entitling the Lenders to surrender a portion of the underlying common units that has a value equal to the aggregate exercise price in lieu of paying cash upon exercise of a warrant. As a result of issuance of the Warrants, we recognized a $1.9 million debt discount on the Second Lien Credit Agreement, which will be amortized over the term of the debt, and a corresponding $1.9 million increase to unitholders’ equity – warrants on our condensed combined balance sheet as of June 30, 2016.
On February 27, 2015 we issued and sold an aggregate of 1.6 million of our newly created Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A Preferred Units”), at a purchase price of $25.00 per unit to certain members of our management, two management members of the Board, and outside investors. Holders of the Series A Preferred Units are entitled to monthly distributions of cash at a rate equal to the greater of (i) 10% of the liquidation preference per annum, increasing to 12% per annum, 14% per annum and 16% per annum on the first, second and third anniversaries of the of the private placement, respectively or (ii) the monthly equivalent of any cash distribution declared by us to holders of our common units, as well as Series A Preferred Units at a rate equal to 2% of the liquidation preference per annum. All or a portion of the Series A Preferred Units will be convertible into our units at the option of the holder at any time following the later of (i) the one-year anniversary of the distribution and (ii) receipt of unitholder approval. The conversion price will be equal to the greater of (i) $8.00 per common unit; and (ii) the lower of (a) 110.0% of the volume weighted average price for our common units over the 30 trading days following the distribution date; and (b) $16.00 per common unit. We sold the Series A Preferred Units in a private transaction exempt from registration under Section 4(a)(2) of the Securities Act. The Series A Preferred Units resulted in proceeds to us of $40.0 million. We used the proceeds to fund a portion of the $150.0 million payment by us to Atlas Energy related to the repayment of Atlas Energy’s term loan (see Note 2). The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities.
On August 26, 2015, at a special meeting of our unitholders, the unitholders approved changes to the terms of the Series A Preferred Units to provide that each Series A Preferred Unit will be convertible into common units at the option of the holder.
On January 7, 2016, we were notified by the NYSE that we were not in compliance with NYSE’s continued listing criteria under Section 802.01C of the NYSE Listed Company Manual because the average closing price of our common units had been less than $1.00 for 30 consecutive trading days. We also were notified by the NYSE on December 23, 2015, that we were not in compliance with the NYSE’s continued listing criteria under Section 802.01B of the NYSE Listed Company
31
Manual because our average market capitalization had been less than $50 million for 30 consecutive trading days and our stockholders’ equity had b
een less than $50 million. On March 18, 2016, we were notified by the NYSE that it determined to commence proceedings to delist our common units from the NYSE as a result of our failure to comply with the continued listing standard set forth in Section 802
.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million. The NYSE also suspended the trading of our common units at the close of trading on March 18, 2016.
Our common units began trading on the OTCQX on Monday, March 21, 2016 under the ticker symbol: ATLS.
On May 12, 2016, due to the income tax ramifications of potential options we were considering, the Board of Directors delayed the vesting of approximately 911,900 units granted, under our long-term incentive plan, to employees, directors and officers, until March 2017. The phantom units were set to vest between June 8, 2016 and September 1, 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 three and six months ended June 30, 2016 or our remaining unrecognized compensation expense related to such awards.
Atlas Resource Partners
ARP has an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP may sell from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, may be 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 existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP may also sell 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 common units to an Agent as principal would be pursuant to the terms of a separate agreement between ARP and such Agent. During the three months ended June 30, 2016, ARP did not issue any common limited partner units under the equity distribution program. During the three months ended June 30, 2015, ARP issued 2,403,288 common limited partner units under the equity distribution agreement for net proceeds of $17.5 million, net of $0.5 million in commissions and offering expenses paid. During the six months ended June 30, 2016, ARP issued 245,175 common limited partner units under the equity distribution program for net proceeds of $0.2 million, net of $4,000 in commissions and offering expenses paid. During the six months ended June 30, 2015, ARP issued 2,885,824 common limited partner units under the equity distribution agreement for net proceeds of $21.4 million, net of $0.6 million in commissions and offering expenses paid.
In August 2015, ARP entered into a distribution agreement with MLV & Co. LLC (“MLV”) which ARP terminated and replaced in November 2015, when ARP entered into a distribution agreement with MLV and FBR Capital Markets & Co. pursuant to which ARP may sell its 8.625% Class D Cumulative Redeemable Perpetual Preferred Units (“Class D ARP Preferred Units”) and 10.75% Class E Cumulative Redeemable Perpetual Preferred Units (“Class E ARP Preferred Units”). ARP did not issue any Class D Preferred Units nor Class E Preferred Units under the August 2015 and November 2015 preferred equity distribution programs for the three and six months ended June 30, 2016 and 2015.
In May 2015, in connection with the Arkoma Acquisition, ARP 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. ARP used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under ARP’s First Lien Credit Facility.
In April 2015, ARP issued 255,000 of its 10.75% Class E ARP 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 the quarterly installment related to the Eagle Ford acquisition, ARP issued an additional 800,000 Class D ARP Preferred Units to the seller at a value of $25.00 per unit.
On May 12, 2016, due to the income tax ramifications of the potential options ARP was considering, the 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 ARP’s compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the three and six months ended June 30, 2016 or our remaining unrecognized compensation expense related to such awards.
32
On July 12, 2016, ARP received notification from the New York Stock Exchange that the NYSE commenced proceedings to delist ARP’s common units as a result of ARP’s failure to comply with the continued listed standa
rds 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. The Class D ARP Preferred Units and Class E ARP Preferred Units were also delisted from the NYSE. AR
P’s common units, Class D ARP Preferred Units, and Class E ARP Preferred Units began trading on the OTC market on July 13, 2016 with the ticker symbol “ARPJ” for ARP’s common units, “ARPJP” for Class D ARP Preferred Units, and “ARPJN” for Class E ARP Prefe
rred Units.
Atlas Growth Partners
On April 5, 2016, we announced that AGP’s registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the Securities and Exchange Commission.
Under the terms of AGP’s initial offering, AGP offered in a private placement $500.0 million of its common limited partner units. The termination date of the private placement offering was December 31, 2014, subject to two 90 day extensions to the extent that it had not sold $500.0 million of common units at any extension date. AGP exercised each of such extensions. Under the terms of the offering, an investor received, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the warrant date (generally, the date upon which AGP gives the holder notice of a liquidity event) until the expiration date (generally, the date that is one day prior to the liquidity event or, if the liquidity event is a listing on a national securities exchange, 30 days after the liquidity event occurs). Under the warrant, a liquidity event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of AGP’s assets.
Through the completion of AGP’s private placement offering on June 30, 2015, AGP issued $233.0 million, or 23,300,410 of its common limited partner units, in exchange for proceeds to AGP, net of dealer manager fees and commissions and expenses, of $203.4 million. We purchased 500,010 common units for $5.0 million during the offering. In connection with the issuance of common limited partner units, unitholders received 2,330,041 warrants to purchase AGP’s common units at an exercise price of $10.00 per unit.
In connection with the issuance of ARP’s unit offerings during the six months ended June 30, 2016, we recorded gains of $0.2 million within unitholders’ equity and a corresponding decrease in non-controlling interests on our condensed combined consolidated balance sheet and condensed combined consolidated statement of unitholders’ equity. In connection with the issuance of ARP’s and AGP’s unit offerings for the six months ended June 30, 2015, we recorded gains of $2.9 million within equity and a corresponding decrease in non-controlling interests on our condensed combined consolidated balance sheets and condensed combined consolidated statement of unitholders’ equity.
NOTE 11—CASH DISTRIBUTIONS
Our Cash Distributions
. We have a cash distribution policy under which we distribute, within 50 days following the end of each calendar quarter, all of our available cash (as defined in our limited liability company agreement) for that quarter to our unitholders. As a result of the First Lien Credit Agreement and Second Lien Credit Agreement entered into on March 30, 2016 (see Note 5), we are prohibited from paying future cash distributions on our common and preferred units.
During the six months ended June 30, 2016, we paid a distribution of $1.0 million to Class A preferred unitholders. During the six months ended June 30, 2015, we paid a distribution of $0.7 million to Class A preferred unitholders.
ARP Cash Distributions
. ARP has a monthly cash distribution program whereby ARP distributes all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. If ARP’s common unit distributions in any quarter exceed specified target levels, we will receive between 13% and 48% of such distributions in excess of the specified target levels.
While outstanding, the Class B ARP 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 Class B Preferred Units were converted into ARP common limited partner units.
The Class C ARP 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, the Board of
33
Directors elected to suspend ARP’s common unit and Class C preferred distributions, beginning with the month of March of 2016, due to the conti
nued lower commodity price environment.
ARP pays quarterly distributions on its Class D ARP 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. ARP pays quarterly distributions on its Class E ARP 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, the Board of Directors elected to suspend the distributions on the Class D ARP Preferred Units and the Class E ARP Preferred Units, beginning with the second quarter 2016 distribution, due to the continued lower commodity price environment. The Class D ARP Preferred Units and Class E ARP Preferred Units accrued distributions of $1.9 million and $0.1 million, respectively, from April 15, 2016 through June 30, 2016. However, due to the distribution suspension and ARP’s recent Chapter 11 filings, these amounts were not earned as the preferred units will be cancelled without receipt of any consideration on the Plan Effective Date.
During the six months ended June 30, 2016, ARP paid four monthly cash distributions totaling $5.1 million to common limited partners ($0.0125 per unit per month); $2.5 million to Preferred Class C limited partners ($0.0125 per unit per month); and $0.2 million to the General Partner Class A holder ($0.0125 per unit per month). During the six months ended June 30, 2015, ARP paid six monthly cash distributions totaling $71.2 million to common limited partners ($0.1966 per unit in both January and February 2015 and $0.1083 per unit in March through June 2015); $4.0 million to Preferred Class C limited partners ($0.1966 per unit in both January and February 2015 and $0.17 per unit in March through June 2015); and $3.6 million to the General Partner Class A holder ($0.1966 per unit in both January and February 2015 and $0.1083 per unit in March through June 2015).
During the six months ended June 30, 2016, ARP paid two distributions totaling $4.4 million to Class D Preferred units ($0.5390625 per unit) for the period October 15, 2016 through April 14, 2016. During the six months ended June 30, 2015, ARP paid two distributions totaling $4.1 million to 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 April 14, 2015).
During the six months ended June 30, 2016, ARP paid two distributions totaling $0.3 million to Class E Preferred units ($0.671875 per unit) for the period October 15, 2015 through April 14, 2016. No distributions were paid to Class E Preferred units during the six months ended June 30, 2015.
AGP Cash Distributions
. AGP has a cash distribution policy under which it distributes to holders of common units and Class A units on a quarterly basis a distribution of $0.175 per unit, or $0.70 per unit per year, to the extent AGP has sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to the general partner and its affiliates. Distributions are generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders are entitled to receive distributions from AGP beginning with the quarter following the quarter in which AGP first admits them as limited partners.
During the six months ended June 30, 2016, AGP paid a distribution of $8.2 million to common limited partners ($0.1750 per unit per quarter) and $0.2 million to the general partner’s Class A units ($0.1750 per unit per quarter). During the six months ended June 30, 2015, AGP paid a distribution of $3.8 million to common limited partners ($0.1750 per unit per quarter) and $0.1 million to the general partner’s Class A units ($0.1750 per unit per quarter).
34
NOTE 12—OPERATING SEGMENT INFORMATION
Our operations include three reportable operating segments: ARP, AGP, and corporate and other. These operating segments reflect the way we manage our operations and make business decisions. Corporate and other includes our equity investment in Lightfoot (see Note 1), as well as our general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands):
|
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
Atlas Resource Partners:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
(1)
|
|
$
|
(16,824
|
)
|
|
$
|
96,125
|
|
|
$
|
86,384
|
|
|
$
|
339,714
|
|
Operating costs and expenses
|
|
(57,125
|
)
|
|
|
(75,822
|
)
|
|
(116,327
|
)
|
|
|
(163,640
|
)
|
Depreciation, depletion and amortization expense
|
|
(29,008
|
)
|
|
|
(42,494
|
)
|
|
(59,053
|
)
|
|
|
(85,485
|
)
|
Gain (loss) on asset sales and disposal
|
|
(502
|
)
|
|
|
97
|
|
|
(493
|
)
|
|
|
86
|
|
Interest expense
|
|
(31,954
|
)
|
|
|
(24,716
|
)
|
|
(59,659
|
)
|
|
|
(49,913
|
)
|
Gain on early extinguishment of debt
|
|
—
|
|
|
|
—
|
|
|
26,498
|
|
|
|
—
|
|
Other income (loss)
|
|
|
(6,156
|
)
|
|
|
—
|
|
|
|
(6,156
|
)
|
|
|
—
|
|
Segment income (loss)
|
|
$
|
(141,569
|
)
|
|
$
|
(46,810
|
)
|
|
$
|
(128,806
|
)
|
|
$
|
40,762
|
|
Atlas Growth Partners:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
2,559
|
|
|
$
|
1,865
|
|
|
$
|
5,993
|
|
|
$
|
4,176
|
|
Operating costs and expenses
|
|
(3,421
|
)
|
|
|
(3,243
|
)
|
|
(6,924
|
)
|
|
|
(8,312
|
)
|
Depreciation, depletion and amortization expense
|
|
(3,299
|
)
|
|
|
(782
|
)
|
|
(7,526
|
)
|
|
|
(2,247
|
)
|
Segment loss
|
|
$
|
(4,161
|
)
|
|
$
|
(2,160
|
)
|
|
$
|
(8,457
|
)
|
|
$
|
(6,383
|
)
|
Corporate and other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
461
|
|
|
$
|
257
|
|
|
$
|
672
|
|
|
$
|
156
|
|
General and administrative
|
|
(1,531
|
)
|
|
|
(2,359
|
)
|
|
(3,685
|
)
|
|
|
(22,574
|
)
|
Interest expense
|
|
(3,890
|
)
|
|
|
(8,471
|
)
|
|
(5,633
|
)
|
|
|
(18,025
|
)
|
Loss on early extinguishment of debt
|
|
(27
|
)
|
|
|
—
|
|
|
(6,080
|
)
|
|
|
—
|
|
Segment loss
|
|
$
|
(4,987
|
)
|
|
$
|
(10,573
|
)
|
|
$
|
(14,726
|
)
|
|
$
|
(40,443
|
)
|
Reconciliation of segment loss to net loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlas Resource Partners
|
|
$
|
(141,569
|
)
|
|
$
|
(46,810
|
)
|
|
$
|
(128,806
|
)
|
|
$
|
40,762
|
|
Atlas Growth Partners
|
|
(4,161
|
)
|
|
|
(2,160
|
)
|
|
(8,457
|
)
|
|
|
(6,383
|
)
|
Corporate and other
|
|
|
(4,987
|
)
|
|
|
(10,573
|
)
|
|
|
(14,726
|
)
|
|
|
(40,443
|
)
|
Net loss
|
|
$
|
(150,717
|
)
|
|
$
|
(59,543
|
)
|
|
$
|
(151,989
|
)
|
|
$
|
(6,064
|
)
|
Reconciliation of segment revenues to total revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlas Resource Partners
(1)
|
|
$
|
(16,824
|
)
|
|
$
|
96,125
|
|
|
$
|
86,384
|
|
|
$
|
339,714
|
|
Atlas Growth Partners
|
|
2,559
|
|
|
|
1,865
|
|
|
5,993
|
|
|
|
4,176
|
|
Corporate and other
|
|
461
|
|
|
|
257
|
|
|
672
|
|
|
|
156
|
|
Total revenues
(1)
|
|
$
|
(13,804
|
)
|
|
$
|
98,247
|
|
|
$
|
93,049
|
|
|
$
|
344,046
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlas Resource Partners
|
|
$
|
5,650
|
|
|
$
|
26,993
|
|
|
$
|
18,820
|
|
|
$
|
69,491
|
|
Atlas Growth Partners
|
|
778
|
|
|
|
3,175
|
|
|
6,327
|
|
|
|
13,118
|
|
Corporate and other
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
Total capital expenditures
|
|
$
|
6,428
|
|
|
$
|
30,168
|
|
|
$
|
25,147
|
|
|
$
|
82,609
|
|
35
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2016
|
|
|
2015
|
|
Balance sheet:
|
|
|
|
|
|
|
|
|
Goodwill:
|
|
|
|
|
|
|
|
|
Atlas Resource Partners
|
|
$
|
13,639
|
|
|
$
|
13,639
|
|
Atlas Growth Partners
|
|
—
|
|
|
|
—
|
|
Corporate and other
|
|
—
|
|
|
|
—
|
|
Total goodwill
|
|
$
|
13,639
|
|
|
$
|
13,639
|
|
Total assets:
|
|
|
|
|
|
|
|
|
Atlas Resource Partners
|
|
$
|
1,540,386
|
|
|
$
|
1,699,949
|
|
Atlas Growth Partners
|
|
135,721
|
|
|
|
159,622
|
|
Corporate and other
|
|
21,193
|
|
|
|
23,675
|
|
Total assets
|
|
$
|
1,697,300
|
|
|
$
|
1,883,246
|
|
|
1)
|
Revenues include gains (losses) on mark to market derivatives. A $73.3 million loss on ARP’s mark-to-market derivatives is included for the three months ended June 30, 2016 related to increases in commodity future prices relative to ARP’s commodity fixed price swaps during the three months ended June 30, 2016 as compared to the prior year period.
|
|
NOTE 13—SUBSEQUENT EVENTS
Atlas Resource Partners
First Lien Credit Facility Installment Payment
. As part of the ongoing discussions with ARP’s lenders and noteholders, ARP determined not to make the first installment payment that was due under the ARP First Lien Credit Facility on July 11, 2016 (see Note 5).
NYSE Compliance.
On July 12, 2016, ARP received notification from the New York Stock Exchange that the NYSE commenced proceedings to delist ARP’s common units
(see Note 10).
Restructuring Support Agreement.
On July 25, 2016, ARP and certain of their subsidiaries and us, solely with respect to certain sections thereof, entered into the Restructuring Support Agreement with the Restructuring Support Parties. On July 27, 2016, ARP and certain of their subsidiaries filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court (see Note 3).
Sale of ARP’s Commodity Hedge Positions
. Pursuant to the ARP Restructuring Support Agreement, ARP 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 ARP First Lien Credit Facility (See Note 5).
Conversion of Preferred Units and Warrants
. On July 31, the 3,749,986 Class C ARP Preferred Units that were issued to us on July 31, 2013, were converted into 3,749,986 common units and the associated warrant issued to us to purchase 562,497 of ARP’s common units expired.
Atlas Growth Partners
Cash Distributions
. On August 3, 2016, AGP declared a quarterly distribution of $0.1750 per common unit for the quarter ended June 30, 2016. The $4.2 million distribution, including $0.1 million to its general partner, will be paid on August 12, 2016 to unitholders of record at the close of business on June 30, 2016.
36